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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
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, 2003: $2,486,289,000.
Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 20, 2004:
116,749,774 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
Portions of the Registrant's Proxy Statement, dated March 5, 2004 are
incorporated by reference in Part III, Items 10, 11, 12 and 14 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 and Other
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
Item 9A -- Controls and Procedures
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 -- Principal Accountant Fees and Services
PART IV
Item 15 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K
Signatures
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 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. In addition to the risk factors and
cautionary statements 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, the following are some other
factors that should be considered for a better understanding of
the financial condition of MDU Resources Group, Inc. (Company).
These other factors may impact the Company's financial results in
future periods.
- Acquisition and disposal of assets or facilities
- Changes in operation, performance and construction of plant
facilities or other assets
- 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
- 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 contract counterparties to meet
their contractual obligations
- Changes in accounting principles and/or the application of
such principles to the Company
- Changes in technology
- Changes in legal proceedings
- The ability to effectively integrate the operations of
acquired companies
- Fluctuations in natural gas and crude oil prices
- Decline in general economic environment
- Changes in governmental regulation
- Changes in currency exchange rates
- Unanticipated increases in competition
- Variations in weather
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
The Company is a diversified natural resource company which
was incorporated under the laws of the state of Delaware in 1924.
Its principal executive offices are at 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 and around 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 performs integrated
construction services, in the central and western United
States and in the states of Alaska and Hawaii.
Utility Services specializes in electrical line
construction, pipeline construction, inside electrical
wiring and cabling and the manufacture and distribution
of specialty equipment.
Centennial Resources owns electric generating facilities
in the United States and has an investment in an electric
generating facility in Brazil. Electric capacity and
energy produced at these facilities are primarily sold under
long-term contracts to nonaffiliated entities. Centennial
Resources includes investments in potential new growth
opportunities that are not directly being pursued by the
other business units, as well as projects outside the
United States which are consistent with the Company's
philosophy, growth strategy and areas of expertise.
These activities are reflected in independent power
production and other.
Centennial Capital insures 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
independent power production and other.
As of December 31, 2003, the Company had 7,797 full-time
employees with 100 employed at MDU Resources Group, Inc., 913 at
Montana-Dakota, 59 at Great Plains, 457 at WBI Holdings, 3,590 at
Knife River's operations, 2,665 at Utility Services and 13 at
Centennial Resources. The number of employees at certain Company
operations fluctuates during the year depending upon the number
and size of construction projects. The Company considers its
relations with employees to be satisfactory.
At Montana-Dakota and Williston Basin Interstate Pipeline
Company (Williston Basin), an indirect wholly owned subsidiary of
WBI Holdings, 436 and 70 employees, respectively, are represented
by the International Brotherhood of Electrical Workers (IBEW).
Labor contracts with such employees are in effect through April
30, 2007 and March 31, 2005, for Montana-Dakota and Williston
Basin, respectively.
Knife River has 40 labor contracts that represent 730 of its
construction materials employees. Knife River is currently in
negotiations on four of its labor contracts.
Utility Services has 60 labor contracts representing the
majority of its employees. The majority of the labor contracts
contain provisions that prohibit work stoppages or strikes and
provide for binding arbitration dispute resolution in the event
of an extended disagreement.
The Company's principal properties, which are of varying ages
and are of different construction types, are believed to be
generally in good condition, are well maintained, and are
generally suitable and adequate for the purposes for which they
are used.
The financial results and data applicable to each of the
Company's business segments as well as their financing
requirements are set forth in Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations and
Item 8 -- Financial Statements and Supplementary Data - Note 14
and Supplementary Financial Information.
The Company has formed an alliance with several electric
cooperatives in the region to evaluate potential utility
opportunities presented by the bankruptcy of NorthWestern
Corporation (NorthWestern). NorthWestern filed for Chapter 11
bankruptcy protection on September 14, 2003.
The operations of the Company and certain of its subsidiaries
are subject to federal, state and local laws and regulations
providing for air, water and solid waste pollution control; state
facility-siting regulations; zoning and planning regulations of
certain state and local authorities; federal health and safety
regulations and state hazard communication standards. The
Company believes that it is in substantial compliance with these
regulations, except as what may be ultimately determined with
regard to the Portland, Oregon Harbor Superfund Site, which is
discussed under Items 1 and 2 -- Business and Properties -
Consolidated Construction Materials and Mining - Environmental
Matters and in Item 8 -- Financial Statements and Supplementary
Data - Note 19. There are no pending Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA) actions for any
of the Company's properties, other than the Portland, Oregon
Harbor Superfund Site.
Governmental regulations establishing environmental protection
standards are continuously evolving and, therefore, the
character, scope, cost and availability of the measures that will
permit compliance with these laws or regulations cannot be
accurately predicted. Disclosure regarding specific
environmental matters applicable to each of the Company's
businesses is set forth under each business description below.
This annual report on Form 10-K, the Company's quarterly
reports on Form 10-Q, the Company's current reports on Form 8-K
and any amendments to those reports filed or furnished pursuant
to Section 13(a) or 15(d) of the 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 117,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as
of December 31, 2003. 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
4,200 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 - Electric. As of
December 31, 2003, Montana-Dakota's net electric plant investment
approximated $296.5 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, and are subject to the junior lien of the
Indenture dated as of December 15, 2003, as supplemented, from
the Company to The Bank of New York, as trustee.
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 2003 electric utility operating revenues by
jurisdiction is as follows: North Dakota -- 59 percent; Montana -
- - 24 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 434,230
kilowatts (kW) and a total summer net capability of 473,460 kW.
Montana-Dakota's four principal generating stations are steam-
turbine generating units using coal for fuel. The nameplate
rating for Montana-Dakota's ownership interest in these four
stations (including interests in the Big Stone Station and the
Coyote Station aggregating 22.7 percent and 25.0 percent,
respectively) is 327,758 kW. Three combustion turbine peaking
stations supply the balance of Montana-Dakota's interconnected
system electric generating capability. A 40-megawatt natural gas-
fueled combustion turbine was added near Glendive, Montana and
became operational in late May 2003. 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. Montana-Dakota
also has an agreement through December 31, 2020 with the Western
Area Power Administration (WAPA) to provide federal hydroelectric
power to eligible Native American customers on the Fort Peck
Indian Reservation. The program provides a credit to the
customers for the portion of their power received from the
federal hydroelectric system. The associated summer monthly
capability from the WAPA agreement is 2,819 kW.
In August 2002, Montana-Dakota entered into an agreement with
Dakota I Power Partners to purchase energy from a 20-megawatt
wind energy farm to be constructed in Dickey County, North
Dakota. The contract provides for the wind farm to be on-line
early to mid-2004. Regulatory approvals have been obtained from
the NDPSC and SDPUC for the purchase of energy from the wind
farm, but Dakota I Power Partners has not yet begun construction.
Montana-Dakota cannot predict whether, or when, construction of
the project will be commenced or completed.
On January 9, 2004, Montana-Dakota entered into a firm
capacity contract with a Midwest utility to purchase 5 megawatts
of capacity during the period May 1, 2004 to October 31, 2004, 15
megawatts during the period May 1, 2005 to October 31, 2005 and
25 megawatts during the period May 1, 2006 to October 31, 2006.
In addition, on January 9, 2004, Montana-Dakota entered into a
firm power contract with the Midwest utility to purchase 70
megawatts of power during the period November 1, 2006 to December
31, 2006, 80 megawatts during the period January 1, 2007 to
December 31, 2007, 90 megawatts during the period January 1, 2008
to December 31, 2008 and 100 megawatts during the period January
1, 2009 to December 31, 2010. All capacity and power purchases
from these contracts are contingent upon the parties securing
transmission service for the delivery of capacity and power to
Montana-Dakota's customer load.
The following table sets forth details applicable to the
Company's electric generating stations:
2003 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 703,106
Heskett Steam 86,000 104,050 605,187
Williston Combustion
Turbine 7,800 9,600 (79)**
South Dakota --
Big Stone* Steam 94,111 103,660 734,902
Montana --
Lewis & Clark Steam 44,000 52,300 323,167
Glendive Combustion
Turbine 75,522 72,800 16,349
Miles City Combustion
Turbine 23,150 24,300 2,252
434,230 473,460 2,384,884
_________________________________
* Reflects Montana-Dakota's ownership interest.
** Station use, to meet Mid-Continent Area Power Pool's (MAPP)
accreditation requirements, exceeded generation.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
subsidiaries of Westmoreland Coal Company (Westmoreland).
Contracts with Westmoreland for the Coyote, Heskett and Lewis &
Clark stations expire in May 2016, December 2005, and December
2007, respectively. The majority of the Big Stone Station's fuel
requirements are currently being met with coal supplied by RAG
Coal West, Inc. under a contract that expires on December 31,
2004. The RAG Coal West, Inc. coal supply arrangement allows for
the purchase during 2004 of 1.5 million tons of coal from the
Belle Ayr mine and 500,000 tons of coal from the Eagle Butte
mine, at contracted pricing.
The Coyote coal supply agreement provides for the purchase of
coal necessary to supply all the coal requirements of the Coyote
Station or 30,000 tons per week, whichever may be the greater
quantity at contracted pricing. The maximum quantity of coal
during the term of the agreement, and any extension, is 75
million tons. The Heskett coal supply agreement allows for the
purchase at contracted pricing. The anticipated fuel supply
requirement for 2004 is 375,000 tons. The Lewis & Clark coal
supply agreement provides for the purchase of coal necessary to
supply all the coal requirements of the Lewis & Clark Station, at
contracted pricing. Montana-Dakota estimates the coal
requirement to be in the range of 250,000 to 325,000 tons per
contract year.
During the years ended December 31, 1999, through December 31,
2003, 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,
2003 2002 2001 2000 1999
Average cost of
coal per
million Btu $ 1.04 $ .98 $ .92 $ .94 $ .90
Average cost of
coal per ton $15.22 $14.39 $13.43 $13.68 $13.31
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 470,000 kW in August 2003. 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 2009 will approximate 0.9 percent annually.
Montana-Dakota's latest forecast indicates that its kilowatt-hour
(kWh) sales growth rate, on a normalized basis, through 2009 will
approximate 1.1 percent annually.
Montana-Dakota currently estimates that it has adequate
capacity available through existing baseload generating stations,
turbine peaking stations and long-term firm purchase contracts to
meet the peak demand requirements of its customers until the year
2007. Additional capacity that is needed in 2007 or after to
replace expiring contracts and meet system growth requirements is
expected to be met through power contracts or building or
acquiring an additional 175 megawatts to 200 megawatts of
capacity. Montana-Dakota is working with the state of North
Dakota to determine the feasibility of constructing a lignite-
fired power plant in western North Dakota. Montana-Dakota is
also involved in a coalition with four other utilities to study
the feasibility of building a coal-based facility possibly
combined with a wind energy facility at potential sites in North
Dakota, South Dakota and Iowa. The costs of building and/or
acquiring the additional generating capacity are expected to be
recovered in rates.
Montana-Dakota has major interconnections with its neighboring
utilities, all of which are 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 52,300 kW and occurred in August 2003.
The Sheridan System is supplied through an interconnection
with Black Hills Power and Light Company under a power supply
contract through December 31, 2006 that allows for the purchase
of up to 55,000 kW of capacity annually.
Regulation and Competition --
Montana-Dakota is subject to competition in varying degrees,
in certain areas, from rural electric cooperatives, on-site
generators, co-generators and municipally owned systems. In
addition, competition in varying degrees exists between
electricity and alternative forms of energy such as natural gas.
The restructuring of the electric industry has been slowed due to
certain events in the industry. 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 is a member of the Midwest Independent
Transmission System Operator, Inc. (Midwest ISO). The Midwest
ISO is responsible for operational control of the transmission
systems of its members. The Midwest ISO agreement permits
Montana-Dakota to be a separate pricing zone. The Midwest ISO
also provides security center operations and tariff
administration.
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. In
March 2001, legislation was passed in Montana which delays the
restructuring and transition to full customer choice until a time
when 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. In 2003, the committee was expanded and the study
was extended for an additional four years. 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 -
Prospective Information - Electric.
On May 30, 2003, Montana-Dakota filed an application with the
NDPSC for an electric rate increase. Montana-Dakota requested a
total of $7.8 million annually or 9.1 percent above current
rates. On July 23, 2003, Montana-Dakota and the NDPSC Staff
filed a Settlement Agreement with the NDPSC agreeing on the
issues of rate of return, capital structure and cost of capital
components. On October 22, 2003, the NDPSC approved the
Settlement Agreement. On November 19, 2003, Montana-Dakota and
the NDPSC Staff filed an additional Settlement Agreement to
resolve all remaining outstanding issues with the NDPSC. This
Settlement Agreement reflected an increase of $1.0 million
annually and a sharing mechanism between Montana-Dakota and
retail customers of wholesale electric sales margins. On
December 18, 2003, the NDPSC approved the November 2003
Settlement Agreement and required Montana-Dakota to file a
compliance filing with the NDPSC. On January 14, 2004, the NDPSC
approved Montana-Dakota's compliance filing, which was filed on
January 7, 2004, with rates effective with service rendered on
and after January 23, 2004.
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 (24 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 these regulations.
The U.S. Environmental Protection Agency (EPA) may authorize a
state to manage federal programs such as the Federal Clean Air
Act (Clean Air Act) and Federal Clean Water Act (Clean Water
Act), under approved state programs. This is the case in all the
states where Montana-Dakota operates.
Montana-Dakota's electric generation facilities have Title V
Operating Permits, under the Clean Air Act, issued by the states
in which it operates. These permits have a five-year life, with
the first of these permits expiring on October 15, 2004. Montana-
Dakota renews these permits as necessary prior to expiration.
State water discharge permits issued under the requirements of
the Clean Water Act are maintained for power production
facilities located on the Yellowstone and Missouri Rivers. These
permits also have a five-year life, with the first permit
expiring on November 30, 2005. Montana-Dakota renews these
permits as necessary prior to expiration. Other permits held by
these facilities may include an initial siting permit, which is
typically a one-time, preconstruction permit issued by the state;
state permits to dispose of combustion by-products; state
authorizations to withdraw water for operations; and U.S. Army
Corps of Engineers (Army Corps) permits to construct water intake
structures. Montana-Dakota's Army Corps permits grant one-time
permission to construct, and do not require renewal. Other
permit terms vary, and the permits are renewed as necessary.
Montana-Dakota's electric operations are conditionally-exempt
small quantity hazardous waste generators and subject only to
minimum regulation under the Resource Conservation and Recovery
Act (RCRA). Montana-Dakota routinely handles polychlorinated
biphenyls (PCBs) from their electric operations in accordance
with federal requirements. PCB storage areas are registered with
the EPA as required.
Montana-Dakota did not incur any material environmental
expenditures in 2003 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2006. For matters involving
Montana-Dakota and the North Dakota Department of Health and a
related matter involving the Dakota Resource Council, see
Item 3 -- Legal Proceedings.
NATURAL GAS DISTRIBUTION
General --
Montana-Dakota sells natural gas at retail, serving over
220,000 residential, commercial and industrial customers located
in 142 communities and adjacent rural areas as of December 31,
2003, 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, 2003, 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 5,100 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 - Prospective Information - Natural gas
distribution. As of December 31, 2003, Montana-Dakota's and
Great Plains' net natural gas distribution plant investment
approximated $147.1 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, and are subject to the junior lien
of the Indenture dated as of December 15, 2003, as supplemented,
from the Company to The Bank of New York, as trustee.
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'
2003 natural gas utility operating revenues by jurisdiction is as
follows: North Dakota -- 39 percent; Minnesota -- 12 percent;
Montana -- 25 percent; South Dakota -- 18 percent and Wyoming --
6 percent.
System Supply, System Demand and Competition --
Montana-Dakota and Great Plains serve retail natural gas
markets, consisting principally of residential and firm
commercial space and water heating users, in portions of the
following states and major communities -- North Dakota, including
Bismarck, Dickinson, Wahpeton, Williston, Minot and Jamestown;
western Minnesota, including Fergus Falls, Marshall and
Crookston; eastern Montana, including Billings, Glendive and
Miles City; western and north-central South Dakota, including
Rapid City, Pierre and Mobridge; and northern Wyoming, including
Sheridan. These markets are highly seasonal and sales volumes
depend on the weather.
The following table reflects this segment's natural gas sales,
natural gas transportation volumes and degree days as a
percentage of normal during the last five years:
Years Ended December 31,
2003* 2002* 2001* 2000** 1999
Mdk (thousands of decatherms)
Sales:
Residential 21,498 21,893 20,087 20,554 18,059
Commercial 15,537 16,044 14,661 14,590 12,030
Industrial 1,537 1,621 1,731 1,451 842
Total 38,572 39,558 36,479 36,595 30,931
Transportation:
Commercial 1,528 1,849 1,847 2,067 1,975
Industrial 12,375 11,872 12,491 12,247 9,576
Total 13,903 13,721 14,338 14,314 11,551
Total Throughput 52,475 53,279 50,817 50,909 42,482
Degree days ***
(% of normal) 97.3% 101.1% 94.5% 100.4% 88.8%
_________________________________
* Includes Great Plains
** Sales and transportation volumes for Great Plains are for the
period July through December 2000. Degree days exclude Great
Plains.
***Degree days are a measure of daily temperature-related demand
for energy for heating.
Competition in varying degrees exists between natural gas and
other fuels and forms of energy. Montana-Dakota and Great Plains
have established various natural gas transportation service rates
for their distribution businesses to retain interruptible
commercial and industrial 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, Northern Natural Gas Company and Viking Gas
Transmission Company. These services have enhanced Montana-
Dakota's and Great Plains' competitive posture with alternate
fuels, although certain of Montana-Dakota's customers have
bypassed the respective distribution systems by directly
accessing transmission pipelines located within close proximity.
These bypasses did not have a material effect on results of
operations.
Montana-Dakota and Great Plains 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 that 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 --
In December 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. On October 27, 2003, Montana-Dakota and the SDPUC
Staff filed a Settlement Stipulation with the SDPUC agreeing to
an increase of $1.3 million annually. On December 2, 2003, the
SDPUC approved the Settlement Stipulation effective with service
rendered on and after December 2, 2003.
In October 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. In December 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. On October 9, 2003,
the MPUC issued a Final Order authorizing an increase of
$1.1 million annually and requiring Great Plains to file a
compliance filing with the MPUC. On January 16, 2004, the MPUC
issued an Order accepting Great Plains' compliance filing, which
was filed on November 10, 2003, effective with service rendered
on and after January 16, 2004.
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 costs are paid.
Environmental Matters --
Montana-Dakota's and Great Plains' natural gas distribution
operations are subject to federal, state and local environmental,
facility siting, zoning and planning laws and regulations.
Montana-Dakota and Great Plains believe they are in substantial
compliance with those regulations.
Montana-Dakota's and Great Plains' operations are
conditionally-exempt small quantity hazardous waste generators
and subject only to minimum regulation under the RCRA. Montana-
Dakota and Great Plains routinely handle PCBs from their natural
gas operations in accordance with federal requirements. PCB
storage areas are registered with the EPA as required.
Montana-Dakota and Great Plains did not incur any material
environmental expenditures in 2003 and do not expect to incur any
material capital expenditures related to environmental compliance
with current laws and regulations through 2006.
UTILITY SERVICES
General --
Utility Services specializes in electrical line construction,
pipeline construction, inside electrical wiring and cabling and
the manufacture and distribution of specialty equipment. These
services are provided to utilities and large manufacturing,
commercial, government and institutional customers.
Construction and maintenance crews are active year round.
However, activity in certain locations may be seasonal in nature
due to the effects of weather.
Utility Services operates a fleet of owned and leased trucks
and trailers, support vehicles and specialty construction
equipment, such as backhoes, excavators, trenchers, generators,
boring machines and cranes. In addition, as of December 31,
2003, Utility Services owned or leased offices in 13 states.
This space is used for offices, equipment yards, warehousing,
storage and vehicle shops. At December 31, 2003, Utility
Services' net plant investment was approximately $46.6 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, 2004, was approximately $142 million
compared to approximately $152 million at January 31, 2003. The
Company expects to complete a significant amount of the backlog
during the year ending December 31, 2004. 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.
This industry is experiencing a shortage of linemen in certain
areas. Utility Services works with the National Electrical
Contractors Association and the IBEW on hiring and recruiting of
qualified linemen.
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 for this segment. 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 these regulations.
The nature of Utility Services' operations is such that few,
if any, environmental permits are required. Operational
convenience supports the use of petroleum storage tanks in
several locations, which are permitted under state programs
authorized by the EPA. Utility Services currently has no ongoing
remediation related to releases from petroleum storage tanks.
Utility Services operations are conditionally-exempt small
quantity waste generators, subject to minimal regulation under
the RCRA. Federal permits for specific construction and
maintenance jobs that may require these permits are typically
obtained by the hiring entity, and not by Utility Services.
Utility Services did not incur any material environmental
expenditures in 2003 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2006.
PIPELINE AND ENERGY SERVICES
General --
Williston Basin, the principal regulated business of WBI
Holdings, owns and operates over 3,700 miles of transmission,
gathering and storage lines and owns or leases and operates 26
compressor stations located in the states of Montana, North
Dakota, South Dakota and Wyoming. Included in the transmission
lines described above are 253 miles of 16-inch natural gas
pipeline built in 2003 that spans sections of Wyoming, Montana,
and North Dakota. This newly constructed pipeline began
transporting natural gas from developing coalbed and conventional
natural gas production facilities in central Wyoming and south
central Montana to interconnecting pipelines on December 23,
2003. Three underground storage fields located in Montana and
Wyoming provide storage services to local distribution companies,
producers, natural gas marketers and others, and serve to enhance
system deliverability. Williston Basin's system is strategically
located near five natural gas producing basins, making natural
gas supplies available to Williston Basin's transportation and
storage customers. The system has 11 interconnecting points with
other pipeline facilities allowing for the receipt and/or
delivery of natural gas to and from other regions of the country.
At December 31, 2003, Williston Basin's net plant investment
was approximately $202.1 million.
WBI Holdings, through its nonregulated pipeline businesses,
owns and operates gathering facilities in Colorado, Kansas,
Montana and Wyoming. These facilities include approximately
1,600 miles of field gathering lines and 77 owned or 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. Certain of the services
are provided based on contracts that call for a determinable
quantity of natural gas. Energy services currently estimates
that it can adequately meet the requirements of these contracts.
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 Innovatum, Inc. (Innovatum), a cable
and pipeline magnetization and locating company. Innovatum
provides products and services that assist the oil and gas and
telecommunication industries with accurate location and tracking
of submerged pipelines and cables. Additionally, Innovatum
manufactures and resells a line of terrestrial, hand-held
locators that are used for locating and identifying underground
metal objects, utility systems and water distribution system
leaks. Innovatum recently developed a hand-held locating device
that can detect both magnetic and plastic materials. One of the
possible uses for this product would be in the detection of
unexploded ordnance. Innovatum is in the preliminary stages of
working with and demonstrating the device to a Department of
Defense contractor and has met with individuals from the
Department of Defense. For additional information regarding
these operations, see Item 7 -- Management's Discussion and
Analysis of Financial Conditions and Results of Operations - Risk
Factors and Cautionary Statements that May Affect Future Results
- - Economic Risks.
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, 2003, represented 75 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.
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 - Risk Factors and Cautionary
Statements that May Affect Future Results - Environmental and
Regulatory Risks. 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 that could provide substantial future benefits.
Regulatory Matters and Revenues Subject to Refund --
In December 1999, Williston Basin filed a general natural gas
rate change application with the FERC. Williston Basin began
collecting such rates effective June 1, 2000, subject to refund.
In May 2001, the Administrative Law Judge (ALJ) issued an Initial
Decision on Williston Basin's natural gas rate change
application. The Initial Decision addressed numerous issues
relating to the rate change application, including matters
relating to allowable levels of rate base, return on common
equity, and cost of service, as well as volumes established for
purposes of cost recovery, and cost allocation and rate design.
On July 3, 2003, the FERC issued its Order on Initial Decision.
The Order on the Initial Decision affirmed the ALJ's Initial
Decision on many of the issues including rate base and certain
cost of service items as well as volumes to be used for purposes
of cost recovery, and cost allocation and rate design. However,
there are other issues as to which the FERC differed with the ALJ
including return on common equity and the correct level of
corporate overhead expense. On August 4, 2003, Williston Basin
requested a rehearing of a number of issues including
determinations associated with cost of service, throughput, and
cost allocation and rate design, as discussed in the FERC's Order
on Initial Decision. On September 3, 2003, the FERC issued an
Order granting Williston Basin's request for rehearing of the
July 3, 2003, Order on Initial Decision. The Company is awaiting
a decision from the FERC on the merits of the Company's rehearing
request and is unable to predict the timing of the FERC's
decision.
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 believes
that such reserves are adequate based on its assessment of the
ultimate outcome of the proceeding.
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.
The ongoing operations of Williston Basin and Bitter Creek
Pipelines, LLC (Bitter Creek), an indirect wholly owned
subsidiary of WBI Holdings, are subject to the Clean Air Act and
the Clean Water Act. Administration of many provisions of these
laws has been delegated to the states where Williston Basin and
Bitter Creek operate, and permit terms vary. Some permits
require annual renewal, some have terms ranging from one to five
years and others have no expiration date. Permits are renewed as
necessary.
Detailed environmental assessments are included in the
permitting processes of the FERC for both the construction and
abandonment of Williston Basin's natural gas transmission
pipelines.
WBI Holdings' pipeline and energy services' operations did not
incur any material environmental expenditures in 2003 and does
not expect to incur any material capital expenditures related to
environmental compliance with current laws and regulations
through 2006.
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 and around the Gulf of Mexico in proportion
to its ownership 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. Natural gas production from operated properties was
74 percent of total natural gas production for the year ended
December 31, 2003.
Fidelity continues to seek additional reserve and production
growth opportunities through the direct acquisition of producing
properties, acquisition of exploration and development leaseholds
and acreage and through exploratory drilling opportunities, as
well as development of its existing properties. Future growth is
dependent upon its success in these endeavors.
Operating Information --
Information on natural gas and oil production, average
realized prices and production costs per net equivalent Mcf
related to natural gas and oil interests for 2003, 2002 and 2001,
are as follows:
2003 2002 2001
Natural Gas:
Production (MMcf) 54,727 48,239 40,591
Average realized price
(including hedges) $ 3.90 $ 2.72 $ 3.78
Average realized price
(excluding hedges) $ 4.28 $ 2.54 $ 3.74
Oil:
Production (000's of barrels) 1,856 1,968 2,042
Average realized price
(including hedges) $27.25 $22.80 $24.59
Average realized price
(excluding hedges) $28.42 $23.26 $23.72
Production costs, including taxes,
per net equivalent Mcf:
Lease operating costs $ .48 $ .46 $ .53
Gathering and transportation .22 .20 .11
Production and property taxes .32 .21 .20
$ 1.02 $ .87 $ .84
Well and Acreage Information --
Gross and net productive well counts and gross and net
developed and undeveloped acreage related to interests at
December 31, 2003, are as follows:
Gross Net
Productive Wells:
Natural Gas 2,678 2,155
Oil 2,178 130
Total 4,856 2,285
Developed Acreage (000's) 829 358
Undeveloped Acreage (000's) 1,275 863
Exploratory and Development Wells --
The following table reflects activities relating to Fidelity's
natural gas and oil wells drilled and/or tested during 2003, 2002
and 2001:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
2003 10 2 12 274 2 276 288
2002 4 --- 4 201 --- 201 205
2001 19 1 20 590 2 592 612
At December 31, 2003, there were 118 gross wells in the
process of drilling or under evaluation, 113 of which were
development wells and five of which were exploratory wells.
These wells are not included in the above table. Fidelity
expects to complete drilling and testing the majority of these
wells within the next 12 months.
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 these
regulations.
The ongoing operations of Fidelity are subject to the Clean
Water Act and other federal and state environmental regulations.
Administration of many provisions of the federal laws has been
delegated to the states where Fidelity operates, and permit terms
vary. Some permits have terms ranging from one to five years and
others have no expiration date.
Some of Fidelity's operations are subject to Section 404 of
the Clean Water Act as administered by the Army Corps. Section
404 permits are required for operations that may affect waters of
the United States, including operations in wetlands. The
expiration dates of these permits also vary, with five years
generally being the longest term.
Detailed environmental assessments and/or environmental impact
statements under federal and state laws are required as part of
the permitting process incident to commencement of drilling and
production operations as well as in abandonment proceedings.
In connection with the development of coalbed natural gas
properties, certain capital expenditures were incurred related to
water handling. For 2003, capital expenditures for water
handling in compliance with current laws and regulations were
approximately $2.0 million and are estimated to be less than
$3.0 million per year through 2006. For information regarding
coalbed natural gas legal proceedings, see Item 3 -- Legal
Proceedings, Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations - Risk Factors and
Cautionary Statements that May Affect Future Results -
Environmental and Regulatory Risks and Item 8 -- Financial
Statements and Supplementary Data - Note 19.
Reserve Information --
Fidelity's recoverable proved developed and undeveloped
natural gas and oil reserves approximated 411.7 Bcf and
18.9 million barrels, respectively, at December 31, 2003.
For additional information related to natural gas and oil
interests, see Item 8 -- Financial Statements and Supplementary
Data - Note 1 and Supplementary Financial Information.
CONSTRUCTION MATERIALS AND MINING
Construction Materials:
General --
Knife River operates construction materials and mining
businesses in Alaska, California, Hawaii, Iowa, Minnesota,
Montana, North Dakota, Oregon, Texas 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 2003, the Company acquired several construction
materials and mining businesses with operations in Montana, North
Dakota and Texas. None of these acquisitions were 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 has benefited
from the Transportation Equity Act for the 21st Century (TEA-21).
TEA-21 expired on September 30, 2003, however funding is
currently being provided under an extension of TEA-21 that
expires on February 29, 2004. Although it is difficult to
predict the outcome of legislation regarding federal highway
construction funding that is anticipated to replace TEA-21, Knife
River expects replacement funding to be equal to or higher than
TEA-21.
The construction materials business had approximately $399
million in backlog in mid-February 2004, compared to
approximately $244 million in mid-February 2003. The Company
anticipates that a significant amount of the current backlog will
be completed during the year ending December 31, 2004.
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.
Reserve Information --
Reserve estimates are calculated based on the best available
data. These data are collected from drill holes and other
subsurface investigations, as well as investigations of surface
features like mine highwalls and other exposures of the aggregate
reserves. Mine plans, production history and geologic data are
also utilized to estimate reserve quantities. Most acquisitions
are made of mature businesses with established reserves, as
distinguished from exploratory type properties.
Estimates are based on analyses of the data described above by
experienced mining engineers, operating personnel and geologists.
Property setbacks and other regulatory restrictions and
limitations are identified to determine the total area available
for mining. Data described above are used to calculate the
thickness of aggregate materials to be recovered. Topography
associated with alluvial sand and gravel deposits is typically
flat and volumes of these materials are calculated by simply
applying the thickness of the resource over the areas available
for mining. Volumes are then converted to tons by using an
appropriate conversion factor. Typically, 1.5 tons per cubic
yard in the ground is used for sand and gravel deposits.
Topography associated with the hard rock reserves is typically
much more diverse. Therefore, using available data, a final
topography map is created and computer software is utilized to
compute the volumes between the existing and final topographies.
Volumes are then converted to tons by using an appropriate
conversion factor. Typically, 2 tons per cubic yard in the
ground is used for hard rock quarries.
Estimated reserves are probable reserves as defined in
Securities Act Industry Guide 7. Remaining reserves are based on
estimates of volumes that can be economically extracted and sold
to meet current market and product applications. The reserve
estimates include only salable tonnage and thus exclude waste
materials that are generated in the crushing and processing
phases of the operation. Approximately 1.1 billion tons of the
1.2 billion tons of aggregate reserves are permitted reserves.
The remaining reserves are on properties that we expect will be
permitted for mining under current regulatory requirements. Some
sites have leases that expire prior to the exhaustion of the
estimated reserves. The estimated reserve life (years remaining)
anticipates, based on Knife River's experience, that leases will
be renewed to allow sufficient time to fully recover these
reserves. The data used to calculate the remaining reserves may
require revisions in the future to account for changes in
customer requirements and unknown geological occurrences. The
years remaining were calculated by dividing remaining reserves by
current year sales. Actual useful lives of these reserves will
be subject to, among other things, fluctuations in customer
demand, customer specifications, geological conditions and
changes in mining plans.
The following table sets forth details applicable to the
Company's aggregate reserves under ownership or lease as of
December 31, 2003 and sales as of and for the years ended
December 31, 2003, 2002 and 2001:
Number Number
of Sites of Sites Estimated
Production (Crushed Stone) (Sand & Gravel) Tons Sold (000's) Reserves Lease Reserve
Area owned leased owned leased 2003 2002 2001 (000's tons) Expiration Life (yrs)
Central MN --- 1 52 58 6,265 6,236 3,860 113,768 2004-2028 18
Portland, OR 1 4 4 3 4,610 4,186 3,951 276,132 2005-2055 60
Northern CA --- --- 7 1 3,907 3,430 2,797 63,419 2046 16
Southwest OR 3 6 11 2 3,360 2,812 2,710 106,992 2004-2031 32
Eugene, OR 4 3 4 2 1,442 2,724 1,418 188,464 2006-2046 131
Hawaii --- 6 --- --- 2,134 2,688 1,528 71,630 2011-2037 34
Central MT --- --- 5 3 2,667 2,463 1,951 40,053 2011-2023 15
Anchorage, AK --- --- 1 --- 1,610 1,719 1,991 24,752 N/A 15
Northwest MT --- --- 8 5 1,413 1,260 1,197 33,374 2005-2020 24
Southern CA --- 2 --- --- 1,945 1,247 101 96,328 2035 50
Bend, OR --- 2 2 1 857 1,030 836 66,976 2010-2012 78
Northern MN 2 --- 21 21 873 559 --- 34,678 2004-2016 40
North/South --- --- 1 43 704 --- --- 43,776 2004-2031 62
Dakota
Eastern TX 1 2 --- 3 449 --- --- 19,071 2005-2012 42
Casper, WY --- --- --- 1 172 61 67 2,000 2006 12
Sales from
other sources 6,030 4,663 5,158 ---
38,438 35,078 27,565 1,181,413
The 1.2 billion tons of estimated aggregate reserves at
December 31, 2003 is comprised of 531 million tons that are owned
and 650 million tons that are leased. The leases have various
expiration dates ranging from 2004 to 2055. Approximately 60
percent of the tons under lease have lease expiration dates of
20 years or more. The weighted average years remaining on all
leases containing estimated probable aggregate reserves is
approximately 23 years, including options for renewal that are at
Knife River's discretion. Based on 2003 sales from leased
reserves, the average time necessary to produce remaining
aggregate reserves from such leases is approximately 44 years.
The following table summarizes Knife River's aggregate
reserves at December 31, 2003, 2002 and 2001 and reconciles the
changes between these dates:
2003 2002 2001
(000's of tons)
Aggregate Reserves:
Beginning of year 1,110,020 1,065,330 894,500
Acquisitions 109,362 72,808 210,335
Sales volumes* (32,408) (30,415) (22,407)
Other (5,561) 2,297 (17,098)
End of year 1,181,413 1,110,020 1,065,330
_________________________________
*Excludes sales from other sources
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 - 2002 compared
to 2001 - Construction Materials and Mining.
The sale of the Company's coal operations in 2001 included
active coal mines in North Dakota and Montana, coal sales
agreements, reserves and mining equipment, and certain
development rights at the Company's former Gascoyne Mine site in
North Dakota. The Company retained ownership of lignite deposits
and leases at its former Gascoyne Mine site in North Dakota,
which were not part of the sale of the coal operations. The
Gascoyne Mine site was closed in 1995 due to the cancellation of
the coal sales contract. These lignite deposits are currently
not being mined and are not associated with an operating mine.
These lignite deposits are of a high moisture content and it is
not economical to mine and ship the lignite to other distant
markets. However, should a power plant be constructed near the
area, the Company may have the opportunity to participate in
supplying lignite to fuel a plant. As of December 31, 2003,
Knife River had under ownership or lease, deposits of
approximately 26.9 million tons of recoverable lignite coal.
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 Portland, Oregon Harbor Superfund Site issue
described below, Knife River believes it is in substantial
compliance with these regulations.
Knife River's asphalt and ready-mixed concrete manufacturing
plants and aggregate processing plants are subject to Clean Air
Act and Clean Water Act requirements for controlling air
emissions and water discharges. Some mining and construction
activities are also subject to these laws. In the states where
Knife River operates, these regulatory programs have been
delegated to state and local regulatory authorities. Knife
River's facilities are also subject to RCRA as it applies to
underground storage tanks and the management of petroleum
hydrocarbon products and wastes. These programs have also
generally been delegated to the state and local authorities in
the states where Knife River operates. No specific permits are
required but Knife River's facilities must comply with
requirements for managing petroleum hydrocarbon products and
wastes.
Some Knife River activities are directly regulated by federal
agencies. For example, gravel bar skimming and deep water
dredging operations are subject to provisions of the Clean Water
Act that are administered by the Army Corps. Knife River
operates nine gravel bar skimming operations and one deep water
dredging operation in Oregon, all of which are subject to Army
Corp permits as well as state permits. The expiration dates of
these permits vary, with five years generally being the longest
term. None of these in-water mining operations are included in
Knife River's aggregate reserve numbers.
Knife River's operations are also occasionally subject to the
Endangered Species Act (ESA). For example, land use regulations
often require environmental studies, including wildlife studies
before a permit may be granted for a new or expanded mining
facility. If endangered species or their habitats are
identified, ESA requirements for protection, mitigation or
avoidance apply. Endangered species protection requirements are
usually included as part of land use permit conditions. Typical
conditions include avoidance, setbacks, restrictions on
operations during certain times of the breeding or rearing
season, and construction or purchase of mitigation habitat.
Knife River's operations are also subject to state and federal
cultural resources protection laws when new areas are disturbed
for mining operations. Mining permit applications generally
require that areas proposed for mining be surveyed for cultural
resources. If any are identified, they must be protected or
managed in accordance with regulatory agency requirements.
The most challenging environmental permit requirements are
usually associated with new mining operations, although
requirements vary widely from state to state and even within
states. In some areas, land use regulations and associated
permitting requirements are minimal. However, some states and
local jurisdictions have very demanding requirements for
permitting new mines. Environmental impact reports are sometimes
required before a mining permit application can even be
considered for approval. These reports can take up to several
years to complete. The report can include projected impacts of
the proposed project on air and water quality, wildlife, noise
levels, traffic, scenic vistas, and other environmental factors.
The reports generally include suggested actions to mitigate the
projected adverse impacts.
Provisions for public hearings and public comments are usually
included in mine permit application review procedures in the
counties where Knife River operates. After taking into account
environmental, mine plan and reclamation information provided by
the permittee as well as comments from the public and other
regulatory agencies, the local authority approves or denies the
permit application. Denial is rare but permits for mining often
include conditions that must be addressed by the permittee.
Conditions may include property line setbacks, reclamation
requirements, environmental monitoring and reporting, operating
hour restrictions, financial guarantees for reclamation, and
other requirements intended to protect the environment or address
concerns submitted by the public or other regulatory agencies.
Despite the challenges, Knife River has been successful in
obtaining mining permit approvals so that sufficient permitted
reserves are available to support its operations. This often
requires considerable advanced planning to ensure sufficient time
is available to complete the permitting process before the newly
permitted reserve is needed to support Knife River's operations.
Knife River's Gascoyne surface coal mine last produced coal in
1995 but continues to be subject to reclamation requirements of
the Surface Mining Control and Reclamation Act (SMCRA), as well
as the North Dakota Surface Mining Act. Much of the property
formerly occupied by the mine remains under reclamation bond
pending completion of the ten year revegetation liability period
under SMCRA.
Knife River did not incur any material environmental
expenditures in 2003 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 2006.
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the Company, was named by the EPA as a
Potentially Responsible Party in connection with the cleanup of a
commercial property site, acquired by MBI in 1999, and part of
the Portland, Oregon, Harbor Superfund Site. Sixty-eight other
parties were also named in this administrative action. The EPA
wants responsible parties to share in the cleanup of sediment
contamination in the Willamette River. To date, costs of the
overall remedial investigation of the harbor site for both the
EPA and the Oregon State Department of Environmental Quality
(DEQ) are being recorded, and initially paid, through an
administrative consent order by the Lower Willamette Group (LWG),
a group of 10 entities which does not include MBI. The LWG
estimates the overall remedial investigation and feasibility
study will cost approximately $10 million. It is not possible to
estimate the cost of a corrective action plan until the remedial
investigation and feasibility study has been completed, the EPA
has decided on a strategy, and a record of decision has been
published. While the remedial investigation and feasibility
study for the harbor site has commenced, it is expected to take
several years to complete. The development of a proposed plan
and record of decision on the harbor site is not anticipated to
occur until 2006, after which a cleanup plan will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the seller
of the commercial property site to MBI, that it intends to seek
indemnity for any and all liabilities incurred in relation to the
above matters, 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.
INDEPENDENT POWER PRODUCTION AND OTHER
Centennial Resources owns electric generating facilities in
the United States and has an investment in an electric generating
facility in Brazil. Electric capacity and energy produced at
these facilities are primarily sold under long-term contracts to
nonaffiliated entities. Centennial Resources includes
investments in potential new growth opportunities that are not
directly being pursued by the other business units, as well as
projects outside the United States which are consistent with the
Company's philosophy, growth strategy and areas of expertise.
Substantially all of the operations of the independent power
production business 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.
On January 31, 2003, Centennial Power purchased a
66.6-megawatt wind-powered electric generating facility from San
Gorgonio Power Corporation, an affiliate of PG&E National Energy
Group. 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 contract with
the California Department of Water Resources that expires in
September 2011. The facility is connected to the Southern
California Edison Company Power transmission system. SeaWest
Wind Power, Inc. (SeaWest) is under a contract to operate the
facility. The contract with SeaWest expires in October 2013.
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
power 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 approaches 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 --
Centennial Power has several operations that require federal
or state environmental permits. The Brush Plant, in Colorado, 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 these
regulations.
The Brush Plant in Colorado has a Title V Operating Permit
issued by the state for a period of five years, under a program
approved by the EPA. The plant also has a water discharge
agreement to release process water to the City of Brush. This
agreement has no specific termination date as long as the Brush
Plant is operating in compliance with the agreement. The
Mountain View wind-powered electric generating facility has
obtained necessary siting authority and federal land leases for
its operations. It has minor requirements related to water
management and spill control under the Clean Water Act,
administered by the state.
Centennial Power did not incur any material environmental
expenditures in 2003 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2006.
Other --
Rocky Mountain Power, an indirect wholly owned subsidiary of
Centennial Resources, has begun construction of a 113-megawatt
coal-fired development project in Hardin, Montana. Based on
demand and power pricing in the Northwest, the plant is being
built on a merchant basis. Efforts will continue towards
securing a contract for the off-take of this plant. The
projected on-line date for this plant is late 2005. For
additional information regarding this plant, see Item 7 --
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors and Cautionary Statements
that May Affect Future Results - Risks Relating to the Company's
Independent Power Production Business, and - Prospective
Information - Independent power production and other.
International:
In August 2001, MDU Brasil Ltda. (MDU Brasil), an indirect
wholly owned Brazilian subsidiary of the Company, entered into a
joint venture agreement with a Brazilian firm under which the
parties formed MPX Participacoes, Ltda. (MPX) to develop electric
generation and transmission, steam generation, power equipment
and coal mining projects in Brazil. MDU Brasil has a 49 percent
interest in MPX. MPX, through a wholly owned subsidiary, owns a
220-megawatt natural gas-fired electric generating facility
(Brazil Generating Facility) in the Brazilian state of Ceara.
The first two turbines of the Brazil Generating Facility entered
commercial operations in July 2002. The remaining two turbines
entered commercial operations in January 2003. Petrobras, the
Brazilian state-controlled energy company, has agreed to purchase
all of the capacity and market all of the Brazil Generating
Facility's energy. The power purchase agreement with Petrobras
expires in May 2008. Petrobras also is under contract to supply
natural gas to the Brazil Generating Facility during the term of
the power purchase agreement. This natural gas supply contract
is renewable by a wholly owned subsidiary of MPX for an
additional 13 years. At December 31, 2003, Centennial Resource's
investment in the Brazil Generating Facility was approximately
$25.2 million, including undistributed earnings of $4.6 million.
Environmental Matters --
The Brazil Generating Facility is subject to all Brazilian
federal environmental statutes. IBAMA, the Brazilian government
regulatory agency or Brazilian Environment Institute, oversees
all environmental issues within Brazil. SEMACE, the state of
Ceara regulatory body or state of Ceara Environmental
Superintendency, annually issues an operating license to MPX.
MPX maintains and must annually renew its operating license that
is granted by SEMACE. SEMACE requires air and water monitoring
on a regular basis. ANEEL, the Brazilian federal electric
regulatory body, provides environmental guidance with which MPX
must comply. MPX is in material compliance with all applicable
environmental regulations and permit requirements.
MPX did not incur any material environmental expenditures in
2003 and does not expect to incur any material capital
expenditures related to environmental compliance with current
laws and regulations through 2006.
ITEM 3. LEGAL PROCEEDINGS
In June 1997, Jack J. Grynberg (Grynberg) filed a Federal
False Claims Act suit against Williston Basin and Montana-Dakota
and filed over 70 similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. 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 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.
The matter is currently in the discovery stage. Grynberg has
not specified the amount he seeks to recover. Williston Basin
and Montana-Dakota are unable to estimate their potential
exposure and will be unable to do so until discovery is
completed. Williston Basin and Montana-Dakota believe that the
Grynberg case will ultimately be dismissed because Grynberg is
not, as is required by the Federal False Claims Act, the original
source of the information underlying the action. Failing this,
Williston Basin and Montana-Dakota believe Grynberg will not
recover damages from Williston Basin and Montana-Dakota because
insufficient facts exist to support the allegations. Williston
Basin and Montana-Dakota believe the claims of Grynberg are
without merit and intend to vigorously contest this suit.
Williston Basin and Montana-Dakota believe it is not probable
that Grynberg will ultimately succeed given the current status of
the litigation.
Fidelity has been named as a defendant in, and/or certain of
its operations are subject of, 11 lawsuits filed in connection
with its coalbed natural gas development in the Powder River
Basin in Montana and Wyoming. These lawsuits were filed in
federal and state courts in Montana between June 2000 and
December 2003 by a number of environmental organizations,
including the Northern Plains Resource Council and the Montana
Environmental Information Center as well as the Tongue River
Water Users' Association and the Northern Cheyenne Tribe. Two of
the lawsuits have been transferred to Federal District Court in
Wyoming. The lawsuits involve allegations that Fidelity and/or
various government agencies are in violation of state and/or
federal law, including the Clean Water Act and the National
Environmental Policy Act. The lawsuits seek injunctive relief,
invalidation of various permits and unspecified damages.
Fidelity is unable to quantify the damages sought, and will be
unable to do so until after completion of discovery. Fidelity is
vigorously defending all coalbed-related lawsuits in which it is
involved. If the plaintiffs are successful in these lawsuits,
the ultimate outcome of the actions could have a material effect
on Fidelity's existing coalbed natural gas operations and/or the
future development of its coalbed natural gas properties.
Montana-Dakota has joined with two electric generators in
appealing a finding by the North Dakota Department of Health
(Department) in September 2003 that the Department may
unilaterally revise operating permits previously issued to
electric generating plants. Although it is doubtful that any
revision of Montana-Dakota's operating permits by the Department
would reduce the amount of electricity its plants could generate,
the finding, if allowed to stand, could increase costs for sulfur
dioxide removal and/or limit Montana-Dakota's ability to modify
or expand operations at its North Dakota generation sites.
Montana-Dakota and the other electric generators filed their
appeal of the order on October 8, 2003, in the Burleigh County
District Court in Bismarck, North Dakota. Proceedings have been
stayed pending discussions with the EPA, the Department and the
other electric generators.
In a related case, the Dakota Resource Council filed an action
in Federal District Court in Denver, Colorado, on September 30,
2003, to require the EPA to enforce certain air quality standards
in North Dakota. If successful, the action could require the
curtailment of discharges of sulfur dioxide into the atmosphere
by existing electric generating facilities and could preclude or
hinder the construction of future generating facilities in North
Dakota. The Company has filed a motion to Intervene in the
lawsuit and has joined in a brief supporting a Motion to Dismiss
filed by the EPA.
The Company cannot predict the outcome of the Department or
Dakota Resource Council matters or their ultimate impact on its
operations.
In December 2000, MBI, an indirect wholly owned subsidiary of
the Company, was named by the EPA as a Potentially Responsible
Party in connection with the cleanup of a commercial property
site, acquired by MBI in 1999, and part of the Portland, Oregon,
Harbor Superfund Site. For additional information regarding this
matter, see Items 1 and 2 -- Business and Properties -
Consolidated Construction Materials and Mining - Environmental
Matters.
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 2003.
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 2003 and 2002 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High)* (Low)* Per Share*
2003
First Quarter $ 18.87 $ 16.41 $ .1600
Second Quarter 22.66 18.55 .1600
Third Quarter 23.32 20.37 .1700
Fourth Quarter 24.35 22.23 .1700
$ .6600
2002
First Quarter $ 20.73 $ 18.17 $ .1533
Second Quarter 22.30 17.17 .1533
Third Quarter 18.27 12.00 .1600
Fourth Quarter 17.33 13.94 .1600
$ .6266
__________________________
* Reflects the Company's three-for-two common stock split
effected in October 2003.
As of December 31, 2003, the Company's common stock was held
by approximately 14,900 stockholders of record.
Between October 1, 2003 and December 31, 2003, the Company
issued 118,570 shares of Common Stock, $1.00 par value, as a
final adjustment with respect to an acquisition in a prior
period. The Common Stock and Rights issued by the Company in
these transactions were issued in a private transaction exempt
from registration under the Securities Act of 1933 pursuant to
Section 4(2) thereof, Rule 506 promulgated thereunder, or both.
The classes of persons to whom these securities were sold were
either accredited investors or other persons to whom such
securities were permitted to be offered under the applicable
exemption.
ITEM 6. SELECTED FINANCIAL DATA
MDU RESOURCES GROUP, INC.
OPERATING STATISTICS
2003 2002 2001 2000 1999 1998*
Selected Financial Data
Operating revenues (000's):
Electric $ 178,562 $ 162,616 $ 168,837 $ 161,621 $ 154,869 $ 147,221
Natural gas distribution 274,608 186,569 255,389 233,051 157,692 154,147
Utility services 434,177 458,660 364,750 169,382 99,917 64,232
Pipeline and energy services 252,192 165,258 531,114 636,848 383,532 180,732
Natural gas and oil production 264,358 203,595 209,831 138,316 78,394 61,842
Construction materials and mining 1,104,408 962,312 806,899 631,396 469,905 346,451
Independent power production and other 34,989 6,776 --- --- --- ---
Intersegment eliminations (191,105) (114,249) (113,188) (96,943) (64,500) (57,998)
$2,352,189 $2,031,537 $2,223,632 $1,873,671 $1,279,809 $ 896,627
Operating income (000's):
Electric $ 35,761 $ 33,915 $ 38,731 $ 38,743 $ 35,727 $ 32,167
Natural gas distribution 6,502 2,414 3,576 9,530 6,688 8,028
Utility services 12,885 13,980 25,199 16,606 11,518 5,932
Pipeline and energy services 35,155 39,091 30,368 28,782 40,627 33,651
Natural gas and oil production 118,347 85,555 103,943 66,510 26,845 (50,444)
Construction materials and mining 91,579 91,430 71,451 56,816 38,346 41,609
Independent power production and other 11,843 (268) --- --- --- ---
$ 312,072 $ 266,117 $ 273,268 $ 216,987 $ 159,751 $ 70,943
Earnings on common stock (000's):
Electric $ 16,950 $ 15,780 $ 18,717 $ 17,733 $ 15,973 $ 13,908
Natural gas distribution 3,869 3,587 677 4,741 3,192 3,501
Utility services 6,170 6,371 12,910 8,607 6,505 3,272
Pipeline and energy services 18,158 19,097 16,406 10,494 20,972 18,651
Natural gas and oil production 70,767** 53,192 63,178 38,574 16,207 (30,501)
Construction materials and mining 54,261** 48,702 43,199 30,113 20,459 24,499
Independent power production and other 12,021 959 --- --- --- ---
Earnings on common stock before
cumulative effect of accounting change 182,196** 147,688 155,087 110,262 83,308 33,330
Cumulative effect of accounting change (7,589) --- --- --- --- ---
$ 174,607 $ 147,688 $ 155,087 $ 110,262 $ 83,308 $ 33,330
Earnings per common share before cumulative
effect of accounting change -- diluted $ 1.62** $ 1.38 $ 1.52 $ 1.20 $ 1.01 $ .44
Cumulative effect of accounting change (.07) --- --- --- --- ---
$ 1.55 $ 1.38 $ 1.52 $ 1.20 $ 1.01 $ .44
Pro forma amounts assuming retroactive
application of accounting change:
Net income (000's) $ 182,913 $ 146,052 $ 152,933 $ 108,951 $ 82,932 $ 33,253
Earnings per common share -- diluted $ 1.62 $ 1.36 $ 1.49 $ 1.17 $ 1.00 $ .43
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 112,460 106,863 101,803 92,085 82,306 76,255
Dividends per common share $ .6600 $ .6266 $ .6000 $ .5733 $ .5467 $ .5223
Book value per common share $ 12.66 $ 11.56 $ 10.60 $ 9.03 $ 7.83 $ 6.93
Market price per common share (year-end) $ 23.81 $ 17.21 $ 18.77 $ 21.67 $ 13.33 $ 17.54
Market price ratios:
Dividend payout 43% 45% 39% 48% 54% 119%
Yield 2.9% 3.7% 3.3% 2.7% 4.2% 3.0%
Price/earnings ratio 15.4x 12.5x 12.3x 18.1x 13.2x 39.9x
Market value as a percent of book value 188.1% 148.8% 177.0% 239.9% 170.4% 253.2%
Profitability Indicators
Return on average common equity 13.0% 12.5% 15.3% 14.3% 13.9% 6.5%
Return on average invested capital 8.9% 8.6% 10.1% 9.5% 9.6% 5.5%
Interest coverage 7.4x 7.7x 8.5x 8.3x 7.1x 6.1x
Fixed charges coverage, including
preferred dividends 4.7x 4.8x 5.3x 4.1x 4.3x 2.5x
General
Total assets (000's) $3,380,592 $2,996,921 $2,675,978 $2,358,981 $1,806,648 $1,488,713
Net long-term debt (000's) $ 939,450 $ 819,558 $ 783,709 $ 728,166 $ 563,545 $ 413,264
Redeemable preferred stock (000's) $ --- $ 1,300 $ 1,400 $ 1,500 $ 1,600 $ 1,700
Capitalization ratios:
Common equity 60% 60% 58% 54% 54% 56%
Preferred stocks 1 1 1 1 1 2
Long-term debt 39 39 41 45 45 42
100% 100% 100% 100% 100% 100%
* Reflects $39.9 million or 52 cents per common share in noncash after-tax write-downs of natural gas and oil properties.
** Before cumulative effect of the change in accounting for asset retirement obligations required by the adoption of
SFAS No. 143, as discussed in Notes 1 and 9.
NOTE: Common stock share amounts reflect the Company's three-for-two common stock splits effected in July 1998
and October 2003.
2003 2002 2001 2000 1999 1998
Electric
Retail sales (thousand kWh) 2,359,888 2,275,024 2,177,886 2,161,280 2,075,446 2,053,862
Sales for resale (thousand kWh) 841,637 784,530 898,178 930,318 943,520 586,540
Electric system summer generating and firm
purchase capability -- kW
(Interconnected system) 542,680 500,570 500,820 500,420 492,800 489,100
Demand peak -- kW
(Interconnected system) 470,470 458,800 453,000 432,300 420,550 402,500
Electricity produced (thousand kWh) 2,384,884 2,316,980 2,469,573 2,331,188 2,350,769 2,103,199
Electricity purchased (thousand kWh) 929,439 857,720 792,641 948,700 860,508 730,949
Average cost of fuel and purchased
power per kWh $.019 $.018 $.018 $.016 $.016 $.017
Natural Gas Distribution
Sales (Mdk) 38,572 39,558 36,479 36,595 30,931 32,024
Transportation (Mdk) 13,903 13,721 14,338 14,314 11,551 10,324
Weighted average degree days --
% of previous year's actual 96% 109% 95% 113% 95% 94%
Pipeline and Energy Services
Transportation (Mdk) 90,239 99,890 97,199 86,787 78,061 88,974
Gathering (Mdk) 75,861 72,692 61,136 41,717 19,799 9,093
Natural Gas and Oil Production
Production:
Natural gas (MMcf) 54,727 48,239 40,591 29,222 24,652 20,699
Oil (000's of barrels) 1,856 1,968 2,042 1,882 1,758 1,912
Average realized prices:
Natural gas (per Mcf) $ 3.90 $ 2.72 $ 3.78 $ 2.90 $ 1.94 $ 1.81
Oil (per barrel) $27.25 $22.80 $24.59 $23.06 $15.34 $12.71
Net recoverable reserves:
Natural gas (MMcf) 411,700 372,500 324,100 309,800 268,900 243,600
Oil (000's of barrels) 18,900 17,500 17,500 15,100 14,700 11,500
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold) 38,438 35,078 27,565 18,315 13,981 11,054
Asphalt (tons sold) 7,275 7,272 6,228 3,310 2,993 1,790
Ready-mixed concrete (cubic yards sold) 3,484 2,902 2,542 1,696 1,186 1,021
Recoverable aggregate reserves (tons) 1,181,400 1,110,020 1,065,330 894,500 740,030 654,670
Coal (000's):
Sales (tons) ---* ---* 1,171* 3,111 3,236 3,113
Lignite deposits (tons) 26,910* 37,761* 56,012* 145,643 182,761 190,152
Independent Power Production and Other**
Net generation capacity -- kW 279,600 213,000 --- --- --- ---
Electricity produced and sold (thousand kWh) 270,044 15,804 --- --- --- ---
* Coal operations were sold effective April 30, 2001.
** Reflects domestic independent power production operations acquired in November 2002 and January 2003.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview
This subsection of Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations
(Management's Discussion and Analysis) is a brief overview of the
important factors that management focuses on in evaluating the
Company's businesses, the Company's financial condition and
operating performance, the Company's overall business strategy
and the earnings of the Company for the period covered by this
report. This subsection is not intended to be a substitute for
reading the entire Management's Discussion and Analysis section.
Reference is made to the various important factors listed under
the heading Risk Factors and Cautionary Statements that May
Affect Future Results, as well as other factors that are listed
in Part I in relation to any forward-looking statement.
Business and Strategy Overview
The Company has six reportable 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 separated independent power production and
other operations from its reportable segments. The independent
power production and other operations do not individually meet
the criteria to be considered a reportable segment.
Substantially all of the operations of independent power
production and other began in 2002; therefore, financial
information for years prior to 2002 has not been presented.
The electric and natural gas distribution segments include the
electric and natural gas distribution operations of Montana-
Dakota and the natural gas distribution operations of Great
Plains Natural Gas Co. The utility services segment includes all
the operations of Utility Services, Inc. The pipeline and energy
services segment includes WBI Holdings' natural gas
transportation, underground storage, gathering services, and
energy-related management services. The natural gas and oil
production segment includes the natural gas and oil acquisition,
exploration and production operations of WBI Holdings. The
construction materials and mining segment includes the results of
Knife River's operations. Independent power production and other
operations own electric generating facilities in the United
States and have an investment in an electric generating facility
in Brazil and investments in opportunities that are not directly
being pursued by the Company's other businesses.
Earnings from electric, natural gas distribution, and pipeline
and energy services are substantially all from regulated
operations. Earnings from utility services, natural gas and oil
production, construction materials and mining, and independent
power production and other are all from nonregulated operations.
On August 14, 2003, the Company's Board of Directors approved
a three-for-two common stock split. For more information on the
common stock split, see Item 8 -- Financial Statements and
Supplementary Data - Note 11.
The Company's strategy is to pursue growth opportunities by
expanding upon its expertise in energy and transportation
infrastructure industries, focusing on acquiring and developing
well-managed companies and projects that enhance shareholder
value and are accretive to earnings per share and returns on
invested capital.
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. In addition, earnings per share for 2004, diluted,
are projected in the range of $1.55 to $1.68. Contributing to
the anticipated growth goals and/or earnings per share
projections are a number of items including:
- Expected returns in 2004 at the electric business are
anticipated to be generally consistent with authorized levels.
- The Company expects to seek natural gas rate increases from
time to time to offset higher expected operating costs at the
natural gas distribution business.
- Anticipated increased margins in 2004 compared to 2003 at
the utility services business.
- An expected increase of total natural gas throughput of
approximately 25 percent to 30 percent over 2003 levels at the
pipeline and energy services business, largely due to the 253-
mile Grasslands Pipeline, which began providing natural gas
transmission service on December 23, 2003.
- Transportation rates are expected to decline in 2004 from
2003 levels due to the estimated effects of a FERC rate order
received in July 2003.
- An expected natural gas and oil production increase of
approximately 10 percent in 2004 compared to 2003.
- Natural gas prices in the Rocky Mountain region for February
through December 2004 reflected in the Company's 2004 earnings
guidance are in the range of $3.25 to $3.75 per Mcf. The
Company's estimates for natural gas prices on the NYMEX for
February through December 2004, reflected in the Company's 2004
earnings guidance, are in the range of $4.00 to $4.50 per Mcf.
- The Company has hedged a portion of its 2004 estimated
annual natural gas production. The Company has entered into
agreements representing approximately 30 percent to 35 percent of
2004 estimated annual natural gas production. The agreements are
at various indices and range from a low CIG index of $3.75 to a
high CIG index of $5.48 per Mcf. CIG is an index pricing point
related to Colorado Interstate Gas Co.'s system.
- NYMEX crude oil prices for January through December 2004,
reflected in the Company's 2004 earnings guidance, are in the
range of $26 to $30 per barrel.
- The Company has hedged a portion of its 2004 oil production.
The Company has entered into agreements at NYMEX prices with a
low of $28.84 and a high of $30.28, representing approximately 30
percent to 35 percent of 2004 estimated annual oil production.
- An expected increase in 2004 revenues of approximately 5
percent to 10 percent over 2003 levels at the construction
materials and mining business.
- Anticipated earnings in the range of $18 million to $23
million in 2004 at the independent power production and other
businesses.
The Company has capabilities to fund its growth and operations
through various sources, including internally generated funds,
commercial paper credit facilities and through the issuance of
long-term debt and the Company's equity securities. Net capital
expenditures for 2003 were $474 million and are estimated to be
approximately $370 million for 2004.
The Company faces certain challenges and risks as it pursues
its growth strategies, including, but not limited to the
following:
- The natural gas and oil production business experienced
higher average natural gas and oil prices in 2003 compared to
2002. These prices are volatile and subject to significant
change at any time. The Company hedges a portion of its natural
gas and oil production in order to mitigate price volatility.
- The soft economy and the depressed telecommunications market
have been challenging particularly for the Company's utility
services business, which has been subjected to lower margins and
decreased workloads. These economic factors have also negatively
affected the Company's energy services business.
- Fidelity continues to seek additional reserve and production
growth through acquisition, exploration, development and
production of natural gas and oil resources, including the
development and production of its coalbed natural gas properties.
Future growth is dependent upon success in these endeavors.
Fidelity has been named as a defendant in, and/or certain of its
operations are the subject of, 11 lawsuits filed in connection
with its coalbed natural gas development in the Powder River
Basin in Montana and Wyoming. If the plaintiffs are successful
in these lawsuits, the ultimate outcome of the actions could have
a material effect on Fidelity's existing coalbed natural gas
operations and/or the future development of its coalbed natural
gas properties.
For further information on certa