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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 certain factors that should be
considered for a better understanding of the Company's financial
condition, see 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.
For information pertinent to various commitments and
contingencies, see Items 1 and 2 -- Business and Properties, Item
3 -- Legal Proceedings and Item 8 -- Financial Statements and
Supplementary Data - Notes to Consolidated Financial Statements.
Earnings Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the Company's businesses.
Years ended December 31,
2003 2002 2001
Electric $ 16.9 $ 15.8 $ 18.7
Natural gas distribution 3.9 3.6 .7
Utility services 6.2 6.4 12.9
Pipeline and energy services 18.2 19.1 16.4
Natural gas and oil production 63.0 53.2 63.2
Construction materials and mining 54.4 48.7 43.2
Independent power production
and other 12.0 .9 ---
Earnings on common stock $ 174.6 $ 147.7 $ 155.1
Earnings per common share - basic $ 1.57 $ 1.39 $ 1.54
Earnings per common share - diluted $ 1.55 $ 1.38 $ 1.52
Return on average common equity 13.0% 12.5% 15.3%
2003 compared to 2002
Consolidated earnings for 2003 increased $26.9 million from
the comparable prior period. Contributing to the earnings
increase were higher earnings at the independent power production
and other businesses primarily resulting from the acquisition of
the Colorado and California electric generating facilities
acquired in late 2002 and early 2003, respectively, and higher
income from the Company's share of its equity investment in
Brazil. Increased earnings at the natural gas and oil production
business were primarily due to higher natural gas and oil prices
and natural gas production, offset in part by the absence in 2003
of the 2002 compromise agreement gain of $27.4 million ($16.6
million after tax) which was included in 2002 operating revenues
and the $12.7 million ($7.7 million after tax) noncash transition
charge in 2003, reflecting the cumulative effect of an accounting
change, as discussed in Item 8 -- Financial Statements and
Supplementary Data - Note 19 and Note 9, respectively, and higher
depreciation, depletion and amortization expense. Earnings
increased at the construction materials and mining business due
to higher aggregate volumes and margins and higher ready-mixed
concrete volumes at existing operations; partially offset by
lower asphalt margins; higher selling, general and administrative
costs; and higher depreciation, depletion and amortization
expense. Stronger sales for resale volumes and margins and
higher retail volumes at the electric business and rate relief
approved by various public service commissions at the natural gas
distribution business, partially offset by higher operation and
maintenance expense at both these businesses, also added to the
increase in earnings. In addition, earnings at the natural gas
distribution business increased due to the absence in 2003 of an
adjustment of $3.3 million (after tax) in 2002 related to certain
pipeline capacity charges, partially offset by higher income
taxes in 2003, the result of the reversal of certain tax
contingency reserves in 2002. Decreased earnings at the pipeline
and energy services and utility services businesses slightly
offset the earnings increase. Lower workloads and margins at the
utility services business are a reflection of the continuing
effects of the soft economy and the downturn in the
telecommunications market.
2002 compared to 2001
Consolidated earnings for 2002 decreased $7.4 million from the
comparable prior period. Lower earnings at the natural gas and
oil production business were largely due to lower realized
natural gas and oil prices offset in part by the previously
mentioned compromise agreement gain and higher natural gas
production. Also adding to the decrease in earnings were lower
earnings at the utility services business due to decreased
margins in the Rocky Mountain and Central regions and the write-
off of certain receivables and restructuring of the engineering
function, partially offset by increased workloads in the
Southwest and Northwest regions. Decreased sales for resale
prices partially offset by increased retail sales revenues at the
electric business also added to the decrease in earnings.
Partially offsetting the earnings decrease were higher earnings
at the construction materials and mining business due to earnings
from businesses acquired since the comparable prior period,
higher aggregate, asphalt and cement sales volumes, and increased
construction revenues, partially offset by the 2001 gain from the
sale of the Company's coal operations of $10.3 million ($6.2
million after tax, including final settlement cost adjustments),
included in 2001 other income - net, as discussed in Item 8 --
Financial Statements and Supplementary Data - Note 14. Also
partially offsetting the earnings decrease were higher earnings
at the natural gas distribution business due to higher retail
sales volumes and lower income taxes, largely the result of the
reversal of certain tax contingency reserves, partially offset by
an adjustment of $3.3 million (after tax) related to certain
pipeline capacity charges. Higher gathering revenues, partially
offset by the net effects of the sale of certain smaller
nonstrategic properties in 2001 at the pipeline and energy
services business, and earnings from the independent power
production and other businesses, also slightly offset the
earnings decline.
Financial and Operating Data
The following tables (dollars in millions, where applicable)
are key financial and operating statistics for each of the
Company's businesses.
Electric
Years ended December 31,
2003 2002 2001
Operating revenues:
Retail sales $ 148.1 $ 142.1 $ 137.3
Sales for resale and other 30.5 20.5 31.5
178.6 162.6 168.8
Operating expenses:
Fuel and purchased power 62.0 56.0 57.4
Operation and maintenance 52.9 46.0 45.6
Depreciation, depletion and
amortization 20.2 19.6 19.5
Taxes, other than income 7.7 7.1 7.6
142.8 128.7 130.1
Operating income $ 35.8 $ 33.9 $ 38.7
Retail sales (million kWh) 2,359.9 2,275.0 2,177.9
Sales for resale (million kWh) 841.6 784.6 898.2
Average cost of fuel and
purchased power per kWh $ .019 $ .018 $ .018
Natural Gas Distribution
Years ended December 31,
2003 2002 2001
Operating revenues:
Sales $ 270.2 $ 182.5 $ 251.3
Transportation and other 4.4 4.1 4.1
274.6 186.6 255.4
Operating expenses:
Purchased natural gas sold 211.1 132.9 200.7
Operation and maintenance 41.8 36.5 36.6
Depreciation, depletion and
amortization 10.0 9.9 9.4
Taxes, other than income 5.2 4.9 5.1
268.1 184.2 251.8
Operating income $ 6.5 $ 2.4 $ 3.6
Volumes (MMdk):
Sales 38.6 39.6 36.5
Transportation 13.9 13.7 14.3
Total throughput 52.5 53.3 50.8
Degree days (% of normal)* 97.3% 101.1% 94.5%
Average cost of natural gas,
including transportation
thereon, per dk $ 5.47 $ 3.22 $ 5.50
______________________________
* Degree days are a measure of the daily temperature-related
demand for energy for heating.
Utility Services
Years ended December 31,
2003 2002 2001
Operating revenues $ 434.2 $ 458.7 $ 364.8
Operating expenses:
Operation and maintenance 395.9 419.0 321.0
Depreciation, depletion and
amortization 10.3 9.9 8.4
Taxes, other than income 15.1 15.8 10.2
421.3 444.7 339.6
Operating income $ 12.9 $ 14.0 $ 25.2
Pipeline and Energy Services
Years ended December 31,
2003 2002 2001
Operating revenues:
Pipeline $ 97.2 $ 95.3 $ 87.1
Energy services 155.0 69.9 444.0
252.2 165.2 531.1
Operating expenses:
Purchased natural gas sold 149.5 58.3 433.5
Operation and maintenance 46.6 47.3 47.1
Depreciation, depletion and
amortization 15.0 14.8 14.3
Taxes, other than income 5.9 5.7 5.8
217.0 126.1 500.7
Operating income $ 35.2 $ 39.1 $ 30.4
Transportation volumes (MMdk):
Montana-Dakota 34.1 33.3 34.1
Other 56.1 66.6 63.1
90.2 99.9 97.2
Gathering volumes (MMdk) 75.9 72.7 61.1
Natural Gas and Oil Production
Years ended December 31,
2003 2002 2001
Operating revenues:
Natural gas $ 213.5 $ 131.0 $ 153.2
Oil 50.6 42.1 47.7
Other .2 30.5* 8.9
264.3 203.6 209.8
Operating expenses:
Purchased natural gas sold .1 .1 2.8
Operation and maintenance:
Lease operating costs 31.6 27.5 27.8
Gathering and transportation 14.7 12.3 5.8
Other 17.2 15.8 16.8
Depreciation, depletion and
amortization 61.0 48.7 41.7
Taxes, other than income:
Production and property
taxes 21.0 12.7 10.8
Other .4 .9 .2
146.0 118.0 105.9
Operating income $ 118.3 $ 85.6 $ 103.9
Production:
Natural gas (MMcf) 54,727 48,239 40,591
Oil (000's of barrels) 1,856 1,968 2,042
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 3.90 $ 2.72 $ 3.78
Oil (per barrel) $ 27.25 $ 22.80 $ 24.59
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.28 $ 2.54 $ 3.74
Oil (per barrel) $ 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
______________________________
*Includes the effects of a compromise agreement gain of $27.4
million ($16.6 million after tax).
Construction Materials and Mining
Years ended December 31,
2003 2002 2001
Operating revenues:
Construction materials $ 1,104.4 $ 962.3 $ 794.6
Coal ---* ---* 12.3*
1,104.4 962.3 806.9
Operating expenses:
Operation and maintenance 924.2 797.7 673.1
Depreciation, depletion and
amortization 63.6 54.4 46.6
Taxes, other than income 25.0 18.8 15.7
1,012.8 870.9 735.4
Operating income $ 91.6 $ 91.4 $ 71.5
Sales (000's):
Aggregates (tons) 38,438 35,078 27,565
Asphalt (tons) 7,275 7,272 6,228
Ready-mixed concrete
(cubic yards) 3,484 2,902 2,542
Coal (tons) ---* ---* 1,171*
______________________________
*Coal operations were sold effective April 30, 2001.
Independent Power Production and Other
Years ended December 31,
2003 2002 2001
Operating revenues $ 35.0 $ 6.8 $ ---
Operating expenses:
Operation and maintenance 15.0 6.4 ---
Depreciation, depletion and
amortization 8.2 .7 ---
23.2 7.1 ---
Operating income (loss)** $ 11.8 $ (.3) $ ---
Net generation capacity - kW*** 279,600 213,000 ---
Electricity produced and sold
(thousand kWh)*** 270,044 15,804 ---
______________________________
** Reflects international operations for 2003 and 2002 and
domestic operations acquired on November 1, 2002 and
January 31, 2003.
***Reflects domestic independent power production operations.
NOTE: The earnings from the Company's equity method investment
in Brazil were included in other income - net and, thus, are not
reflected in the above table.
Amounts presented in the preceding tables for operating
revenues, purchased natural gas sold and operation and
maintenance expense will not agree with the Consolidated
Statements of Income due to the elimination of intersegment
transactions. The amounts (dollars in millions) relating to the
elimination of intersegment transactions are as follows:
Years ended December 31,
2003 2002 2001
Operating revenues $ 191.1 $ 114.3 $ 113.2
Purchased natural gas sold 176.5 98.8 107.7
Operation and maintenance 14.6 15.5 5.5
For further information on intersegment eliminations, see
Item 8 -- Financial Statements and Supplementary Data - Note 14.
2003 compared to 2002
Electric
Electric earnings increased as a result of 48 percent higher
average sales for resale prices and 7 percent higher sales for
resale volumes, both due to stronger sales for resale markets.
Higher retail sales revenues, due primarily to higher retail
sales volumes, largely to residential, commercial and large
industrial customers, also added to the increase in earnings.
Partially offsetting the earnings increase was higher operation
and maintenance expenses, including repair and maintenance at
certain electric generating stations, insurance and payroll-
related costs. Increased fuel and purchased power costs related
to sales for resale also partially offset the earnings increase.
Natural Gas Distribution
Earnings at the natural gas distribution business increased
due to higher retail sales rates, the result of rate relief
approved by various public service commissions. Also adding to
the increase in earnings was the absence in 2003 of an adjustment
of $3.3 million (after tax) in 2002 related to certain pipeline
capacity charges. Partially offsetting the earnings increase
were higher operation and maintenance expenses, primarily due to
higher payroll-related costs, and higher income taxes in 2003,
the result of the reversal of certain tax contingency reserves in
2002. Decreased returns on natural gas held in storage and lower
retail sales volumes due to weather that was 4 percent warmer
than last year, also partially offset the earnings increase. The
pass-through of higher natural gas prices is reflected in the
increase in both sales revenues and purchased natural gas sold.
Utility Services
Utility services earnings decreased slightly as a result of
lower line construction workloads and margins in the Southwest
and Central regions and lower workloads and margins in the
telecommunications industry in the Rocky Mountain region.
Increased selling, general and administrative expenses and lower
inside electrical workloads and margins in the Central region
also contributed to the decrease in earnings. Partially
offsetting the earnings decrease were the absence in 2003 of the
2002 write-off of certain receivables and restructuring of the
engineering function of approximately $5.2 million (after tax)
and higher line construction margins in the Northwest and Rocky
Mountain regions. Lower margins are a reflection of the
continuing effects of the soft economy in this sector and the
downturn in the telecommunications market.
Pipeline and Energy Services
Earnings at the pipeline and energy services business
decreased as a result of reduced natural gas margins and lower
technology services revenues at the energy services businesses.
Also contributing to the decrease in earnings were lower
transportation volumes, largely resulting from lower volumes
transported to storage. Partially offsetting the earnings
decrease were increased revenues from higher transportation
reservation fees resulting from an increase in the level of firm
services provided, higher gathering volumes of 4 percent and
lower financing-related costs. The increase in energy services
revenues and the related increase in purchased natural gas sold
includes the effect of increases in natural gas prices since the
comparable prior period.
Natural Gas and Oil Production
Natural gas and oil production earnings increased due to
higher realized natural gas prices of 43 percent; higher natural
gas production of 13 percent, primarily from enhanced natural gas
production from operated properties located in the Rocky Mountain
area; and higher average realized oil prices of 20 percent.
Partially offsetting the earnings increase were the 2002
compromise agreement gain and the noncash transition charge in
2003, reflecting the cumulative effect of an accounting change,
both as previously discussed. Also partially offsetting the
earnings increase were increased depreciation, depletion and
amortization expense due to higher natural gas production volumes
and higher rates. The higher depreciation, depletion and
amortization rates are attributable to increased costs of reserve
additions and the effects of the adoption of Statement of
Financial Accounting Standards (SFAS) No. 143, "Accounting for
Asset Retirement Obligations." Higher lease operating expenses
due in part to increased production, higher general and
administrative costs, decreased oil production of 6 percent and
higher interest expense also partially offset the earnings
increase.
Construction Materials and Mining
Construction materials and mining earnings increased due to
higher aggregate and ready-mixed concrete volumes and margins and
higher construction activity, all at existing operations.
Earnings from companies acquired since the comparable period last
year also added to the earnings increase. Partially offsetting
the increase in earnings were higher selling, general and
administrative costs, including insurance, computer system
support and payroll-related costs; higher depreciation, depletion
and amortization expense primarily due to higher property, plant
and equipment balances; and higher aggregate volumes produced.
Lower asphalt margins from existing operations, due in part to
higher asphalt oil costs, also partially offset the earnings
increase.
Independent Power Production and Other
Earnings for the independent power production and other
businesses increased largely from the domestic businesses
acquired in late 2002 and early 2003, partially offset by higher
interest expense, resulting from higher average debt balances
relating to these acquisitions. Also adding to the earnings
increase was higher net income of $3.7 million from the Company's
share of its equity investment in Brazil due primarily to higher
margins from higher capacity revenues, which resulted from all
four units being in operation in 2003 compared to only two
operational units in 2002 (effective July 2002), as well as from
foreign currency gains from the revaluation of the Brazilian
real, partially offset by the mark-to-market loss on an embedded
derivative in the electric power contract and higher interest
expense due to a full year of debt in 2003.
2002 compared to 2001
Electric
Electric earnings decreased as a result of lower average
realized sales for resale prices, which were 34 percent lower
than the prior year, due to weaker demand in the sales for resale
markets; the absence in 2002 of 2001 insurance recovery proceeds
related to a 2000 outage at an electric generating station; and
lower sales for resale volumes, which were 13 percent lower than
the prior year. Partially offsetting the earnings decline were
increased retail sales volumes, which were 4 percent higher than
the prior year, primarily to residential, commercial and large
industrial customers; decreased fuel and purchased power costs,
largely lower demand charges resulting from the absence of a 2001
extended maintenance outage at an electric supplier's generating
station; and increased retail sales prices, primarily demand
revenue, which were partially offset by the North Dakota retail
rate reduction.
Natural Gas Distribution
Earnings at the natural gas distribution business increased as
a result of higher retail sales volumes, which were 8 percent
higher than the prior year, largely the result of weather that
was 9 percent colder than the prior period; increased return on
natural gas storage, demand and prepaid commodity balances;
increased retail sales prices, largely the result of rate
increases in Minnesota, Montana and North Dakota; higher service
and repair margins; and lower income taxes, largely the result of
the reversal of certain tax contingency reserves. An adjustment
of $3.3 million (after tax) related to certain pipeline capacity
charges partially offset the earnings increase. The pass-through
of lower natural gas prices resulted in the decrease in sales
revenues and purchased natural gas sold.
Utility Services
Utility services earnings decreased as a result of lower line
construction margins in the Rocky Mountain region related
primarily to decreased fiber optic construction work; lower
construction margins in the Central region due to decreased
inside electrical work; the write-off of certain receivables and
restructuring of the engineering function of approximately $5.2
million (after tax); and decreased equipment sales and margins.
Partially offsetting the earnings decline were increased
workloads in the Southwest and Northwest regions, the
discontinuance of the amortization of goodwill in 2002 ($1.4
million after tax in 2001), and decreased interest expense,
primarily due to lower debt balances. The increase in revenues
and the related increase in operation and maintenance expenses
resulted largely from businesses acquired since the comparable
prior period.
Pipeline and Energy Services
Earnings at the pipeline and energy services business
increased as a result of higher gathering revenues, largely
increased gathering volumes, which were 19 percent higher than
the prior year, at higher average rates, and higher stand-by
fees; increased volumes transported on-system and off-system, at
slightly higher average rates; and higher storage revenues. Also
contributing to the earnings improvement were lower corporate
development costs and the absence in 2002 of a 2001 write-off of
an investment in a software development company of $699,000
(after tax). Partially offsetting the earnings increase were the
net effects of the sale of certain smaller nonstrategic
properties in 2001 along with higher operation and maintenance
expenses and higher depreciation, depletion and amortization
expense, a result of gathering system expansion to accommodate
increasing natural gas volumes. The $374.1 million decrease in
energy services revenue and the related decrease in purchased
natural gas sold were due primarily to decreased energy marketing
volumes resulting from the sale of the vast majority of the
Company's energy marketing operations in the third quarter of
2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due
to lower realized natural gas and oil prices, which were 28
percent and 7 percent lower than the prior year, respectively,
along with lower oil production of 4 percent; partially offset by
higher natural gas production of 19 percent, largely from
operated properties in the Rocky Mountain area. Also adding to
the earnings decline were increased depreciation, depletion and
amortization expense due to higher natural gas production volumes
and higher rates; increased operation and maintenance expenses,
mainly higher lease operating expenses resulting from the
expansion of coalbed natural gas production; and lower sales
volumes of inventoried natural gas. Partially offsetting the
earnings decline were the effects of the previously discussed
2002 compromise agreement gain.
Construction Materials and Mining
Earnings for the construction materials and mining business
increased as a result of earnings from businesses acquired since
the comparable prior period; higher aggregate, asphalt and cement
sales volumes; increased construction revenues, largely the
result of several large projects mainly in California and Oregon;
and lower asphalt costs. Partially offsetting the increase in
earnings were the 2001 gain from the sale of the Company's coal
operations, as previously discussed, as well as earnings from
four months of coal operations included in 2001 earnings. Higher
selling, general and administrative costs, mainly due to higher
computer support, insurance and payroll costs; and higher
depreciation, depletion and amortization expense due to higher
sales volumes; partially offset by the discontinuance of the
amortization of goodwill in 2002 ($1.7 million after tax in
2001), also added to the partial offset in earnings.
Independent Power Production and Other
Earnings at the independent power production and other
businesses totaled $959,000. The majority of these earnings came
from the newly acquired 213-megawatt natural gas-fired electric
generating facilities in Colorado. The Brazilian operations also
contributed to earnings. The Company's 49 percent share of the
gain of $13.6 million (after tax) from an embedded derivative in
the electric power contract and margins at the Brazil facilities
were largely offset by the Company's 49 percent share of the
foreign currency losses of $9.4 million (after tax) resulting
from devaluation of the Brazilian real and net interest expense
of $3.6 million (after tax).
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-K to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking
statements include statements concerning plans, objectives,
goals, strategies, future events or performance, and underlying
assumptions (many of which are based, in turn, upon further
assumptions) and other statements that are other than statements
of historical facts. From time to time, the Company may publish
or otherwise make available forward-looking statements of this
nature, including statements contained within Prospective
Information. All these subsequent forward-looking statements,
whether written or oral and whether made by or on behalf of the
Company, are also expressly qualified by these factors and
cautionary statements.
Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation,
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs
or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document
speaks only as of the date on which the statement is made, and
the Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or
circumstances that occur after the date on which the statement is
made or to reflect the occurrence of unanticipated events. New
factors emerge from time to time, and it is not possible for
management to predict all of the factors, nor can it assess the
effect of each factor on the Company's business or the extent to
which any factor, or combination of factors, may cause actual
results to differ materially from those contained in any forward-
looking statement.
Following are some specific factors that should be considered
for a better understanding of the Company's financial condition.
These factors and the other matters discussed herein are
important factors that could cause actual results or outcomes for
the Company to differ materially from those discussed in the
forward-looking statements included elsewhere in this document.
Economic Risks
The Company's natural gas and oil production business is
dependent on factors, including commodity prices, which cannot be
predicted or controlled.
These factors include: price fluctuations in natural gas and
crude oil prices; availability of economic supplies of natural
gas; drilling successes in natural gas and oil operations; the
ability to contract for or to secure necessary drilling rig
contracts and to retain employees to drill for and develop
reserves; the ability to acquire natural gas and oil properties;
and other risks incidental to the operations of natural gas and
oil wells.
The current soft economic environment and the depressed
telecommunications market may have a general negative impact on
the Company's future revenues and may result in a goodwill
impairment for Innovatum, Inc. (Innovatum), an indirect wholly
owned subsidiary of the Company.
In response to the ongoing war against terrorism by the United
States and the bankruptcy of several large energy and
telecommunications companies and other large enterprises, the
financial markets have been volatile. A soft economy could
negatively affect the level of public and private expenditures on
projects and the timing of these projects which, in turn, would
negatively affect the demand for the Company's products and
services.
Innovatum, which specializes in cable and pipeline
magnetization and locating, is subject to the economic conditions
within the telecommunications and energy industries. Innovatum
has also developed a hand-held locating device that can detect
both magnetic and plastic materials. Innovatum could face a
future goodwill impairment if there is a continued downturn in
the telecommunications and energy industries or if it cannot find
a successful market for the hand-held locating device. At
December 31, 2003, the goodwill amount at Innovatum was
approximately $8.3 million. The determination of whether an
impairment will occur is dependent on a number of factors,
including the level of spending in the telecommunications and
energy industries, the success of the hand-held locating device
at Innovatum, rapid changes in technology, competitors and
potential new customers.
The Company relies on financing sources and capital markets. If
the Company were unable to access financing in the future, the
Company's ability to execute its business plans, make capital
expenditures or pursue acquisitions that the Company may
otherwise rely on for future growth could be impaired.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a source of liquidity for capital requirements not
satisfied by the cash flow from operations. If the Company is
not able to access capital at competitive rates, the ability to
implement its business plans may be adversely affected. Market
disruptions or a downgrade of the Company's credit ratings may
increase the cost of borrowing or adversely affect its ability to
access one or more financial markets. Such disruptions could
include:
- A severe prolonged economic downturn
- The bankruptcy of unrelated industry leaders in the same
line of business
- Capital market conditions generally
- Volatility in commodity prices
- Terrorist attacks
- Global events
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase its costs of
operations, impact or limit its business plans, or expose the
Company to environmental liabilities. One of the Company's
subsidiaries is subject to litigation in connection with its
coalbed natural gas development activities.
The Company is subject to extensive environmental laws and
regulations affecting many aspects of its present and future
operations including air quality, water quality, waste management
and other environmental considerations. These laws and
regulations can result in increased capital, operating and other
costs, as a result of compliance, remediation, containment and
monitoring obligations, particularly with regard to laws relating
to power plant emissions and coalbed natural gas development.
These laws and regulations generally require the Company to
obtain and comply with a wide variety of environmental licenses,
permits, inspections and other approvals. Public officials and
entities, as well as private individuals and organizations, may
seek to enforce applicable environmental laws and regulations.
The Company cannot predict the outcome (financial or operational)
of any related litigation that may arise.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs
are not fully recoverable from customers, could have a material
effect on the Company's results of operations.
Fidelity has been named as a defendant in, 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.
The Company is subject to extensive government regulations that
may have a negative impact on its business and its results of
operations.
The Company is subject to regulation by federal, state and
local regulatory agencies with respect to, among other things,
allowed rates of return, financings, industry rate structures,
and recovery of purchased power and purchased gas costs. These
governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs
from its customers. The Company is unable to predict the impact
on operating results from the future regulatory activities of any
of these agencies.
Changes in regulations or the imposition of additional
regulations could have an adverse impact on the Company's results
of operations.
Risks Relating to the Company's Independent Power Production
Business
The operation of power generation facilities involves many risks,
including start-up risks, breakdown or failure of equipment,
competition, inability to obtain required governmental permits
and approvals and inability to negotiate acceptable acquisition,
construction, fuel supply, off-take, transmission or other
material agreements, as well as the risk of performance below
expected levels of output or efficiency.
The Company 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. Unanticipated events could delay completion of
construction, start-up and/or operation of the project. Changes
in the market price for power from the Company's projections
could also negatively impact earnings to be derived from the
project.
Risks Relating to Foreign Operations
The value of the Company's investment in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes
in the political, regulatory or economic environment in these
countries could negatively affect the value of the Company's
investments located in these countries. Also, since the Company
is unable to predict the fluctuations in the foreign currency
exchange rates, these fluctuations may have an adverse impact on
the Company's results of operations.
The Company's 49 percent equity method investment in a 220-
megawatt natural gas-fired electric generation project in Brazil
includes a power purchase agreement that contains an embedded
derivative. This embedded derivative derives its value from an
annual adjustment factor that largely indexes the contract
capacity payments to the U.S. dollar. In addition, from time to
time, other derivative instruments may be utilized. The
valuation of these financial instruments, including the embedded
derivative, can involve judgments, uncertainties and the use of
estimates. As a result, changes in the underlying assumptions
could affect the reported fair value of these instruments. These
instruments could recognize financial losses as a result of
volatility in the underlying fair values, or if a counterparty
fails to perform.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased
competition. The independent power industry includes numerous
strong and capable competitors, many of which have greater
resources and more experience in the operation, acquisition and
development of power generation facilities. Utility services'
competition is based primarily on price and reputation for
quality, safety and reliability. The construction materials
products are marketed under highly competitive conditions and are
subject to such competitive forces as price, service, delivery
time and proximity to the customer. The electric utility and
natural gas industries are also experiencing increased
competitive pressures as a result of consumer demands,
technological advances, deregulation, greater availability of
natural gas-fired generation and other factors. Pipeline and
energy services competes with several pipelines for access to
natural gas supplies and gathering, transportation and storage
business. The natural gas and oil production business is subject
to competition in the acquisition and development of natural gas
and oil properties as well as in the sale of its production
output.
Weather conditions can adversely affect the Company's operations
and revenues.
The Company's results of operations can be affected by changes
in the weather. Weather conditions directly influence the demand
for electricity and natural gas, affect the wind-powered
operation at the independent power production business, affect
the price of energy commodities, affect the ability to perform
services at the utility services and construction materials and
mining businesses and affect ongoing operation and maintenance
activities for the pipeline and energy services and natural gas
and oil production businesses. In addition, severe weather can
be destructive, causing outages and/or property damage, which
could require additional costs to be incurred. As a result,
adverse weather conditions could negatively affect the Company's
results of operations and financial condition.
Prospective Information
The following information includes highlights of the key
growth strategies, projections and certain assumptions for the
Company and its subsidiaries over the next few years and other
matters for each of the Company's businesses. Many of these
highlighted points are forward-looking statements. There is no
assurance that the Company's projections, including estimates for
growth and increases in revenues and earnings, will in fact be
achieved. Reference is made to assumptions contained in this
section, as well as the various important factors listed under
the heading Risk Factors and Cautionary Statements that May
Affect Future Results, and other factors that are listed in Part
I. Changes in such assumptions and factors could cause actual
future results to differ materially from targeted growth, revenue
and earnings projections.
MDU Resources Group, Inc.
- - Earnings per common share for 2004, diluted, are projected
in the range of $1.55 to $1.68.
- - The Company expects the percentage of 2004 earnings per
common share, diluted, by quarter to be in the following
approximate ranges:
- First quarter - 13 percent to 18 percent
- Second quarter - 19 percent to 24 percent
- Third quarter - 35 percent to 40 percent
- Fourth quarter - 23 percent to 28 percent
- - 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.
- - The Company will consider issuing equity from time to time
to keep debt at the nonregulated businesses at no more than 40
percent of total capitalization.
- - The Company has formed an alliance with several electric
cooperatives in the region to evaluate potential utility
opportunities presented by the bankruptcy of NorthWestern.
NorthWestern filed for Chapter 11 bankruptcy protection on
September 14, 2003.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required. As franchises expire, Montana-Dakota may face
increasing competition in its service areas, particularly its
service to smaller towns, from rural electric cooperatives.
Montana-Dakota intends to protect its service area and seek
renewal of all expiring franchises and will continue to take
steps to effectively operate in an increasingly competitive
environment.
- - Expected returns in 2004 are anticipated to be generally
consistent with authorized levels.
- - Montana-Dakota filed an application with the NDPSC seeking
an increase in electric retail rates of $7.8 million annually or
9.1 percent above current rates. On December 18, 2003, the NDPSC
approved a Settlement Agreement for an increase of $1.0 million
annually and a sharing mechanism between Montana-Dakota and
retail customers of wholesale electric sales margins. For
further information on the electric rate increase application,
see Item 8 -- Financial Statements and Supplementary Data - Note
18.
- - Regulatory approval has been received from the NDPSC and the
SDPUC on the Company's plans to purchase energy from a 20-
megawatt wind energy farm in North Dakota. The contract provides
for this wind energy farm to be on-line by early to mid 2004.
- - The Company continues to evaluate potential needs for future
generation. The Company expects to build or acquire an
additional 175-megawatts to 200-megawatts of capacity over the
next 10 years to replace expiring contracts and meet system
growth requirements. The Company is working with the state of
North Dakota to determine the feasibility of constructing a
lignite-fired power plant in western North Dakota. The Company
also announced its involvement in a coalition with four other
utilities to study the feasibility of building a coal-based
electric generating 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 needed by the utility are expected to be
recovered in rates.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota
and Great Plains may face increasing competition in their service
areas. Montana-Dakota and Great Plains intend to protect their
service areas and seek renewal of all expiring franchises and
will continue to take steps to effectively operate in an
increasingly competitive environment.
- - Annual natural gas throughput for 2004 is expected to be
approximately 52 million decatherms.
- - The Company expects to seek natural gas rate increases from
time to time to offset higher expected operating costs.
- - Montana-Dakota filed an application with the SDPUC seeking
an increase in natural gas retail rates of $2.2 million annually
or 5.8 percent above current rates. On December 2, 2003, the
SDPUC approved a Settlement Stipulation for an increase of $1.3
million annually. Great Plains filed an application with the
MPUC seeking an increase in natural gas retail rates of $1.6
million annually or 6.9 percent above current rates. On October
9, 2003, the MPUC issued a Final Order authorizing an increase of
$1.1 million annually. For further information on the natural
gas rate increase applications, see Item 8 -- Financial
Statements and Supplementary Data - Note 18.
Utility services
- - Revenues for this segment are expected to be in the range of
$440 million to $490 million in 2004.
- - This segment anticipates margins to increase in 2004 as
compared to 2003 levels.
Pipeline and energy services
- - In 2004, total natural gas throughput is expected to
increase approximately 25 percent to 30 percent over 2003 levels
largely due to the 253-mile Grasslands Pipeline, which began
providing natural gas transmission service on December 23, 2003.
- - Firm capacity for the Grasslands Pipeline is currently 90
million cubic feet per day with expansion possible to 200 million
cubic feet per day.
- - 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.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk
Factors and Cautionary Statements that May Affect Future Results.
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.
Natural gas and oil production
- - In 2004, this segment expects a combined production increase
of approximately 10 percent over 2003 levels. Currently, this
segment's gross operated natural gas production is approximately
140,000 Mcf to 150,000 Mcf per day.
- - This segment continues to expand its operated production.
Natural gas production from operated properties was 74 percent
and 69 percent of total natural gas production for the years
ended December 31, 2003 and 2002, respectively.
- - This segment expects to participate in drilling more than
400 wells in 2004.
- - At December 31, 2003, this segment had 118 gross wells in
the process of drilling or under evaluation, 113 of which were
development wells and five of which were exploratory wells. This
segment expects to complete drilling and testing the majority of
these wells within the next 12 months.
- - 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.
During 2003, more than two-thirds of this segment's natural gas
production was priced using Rocky Mountain or other non-NYMEX
prices.
- - NYMEX crude oil prices for January through December 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 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.
- - 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.
- - The Company has hedged less than 5 percent of its 2005
estimated annual natural gas production and will continue to
evaluate additional opportunities.
Construction materials and mining
- - Aggregate volumes in 2004 are expected to be comparable to
2003 levels, while ready-mixed concrete and asphalt volumes are
expected to increase over 2003 levels.
- - Revenues in 2004 are expected to increase by approximately 5
percent to 10 percent over 2003 levels.
- - Knife River expects that the replacement funding legislation
for the Transportation Equity Act for the 21st Century (TEA-21)
will be at funding levels equal to or higher than the funding
under TEA-21.
- - On February 6, 2004, this segment acquired a ready-mixed
concrete producer and concrete and asphalt paving company in Iowa
and two aggregate mining and production companies in Minnesota.
The companies have combined annual revenues of approximately $90
million.
Independent power production and other
- - Earnings projections in 2004 for independent power
production and other operations include the estimated results
from the wind-powered electric generating facility in California,
the natural gas-fired electric generating facility in Colorado,
and the Company's 49-percent ownership in a 220-megawatt natural
gas-fired electric generating facility in Brazil. Earnings are
expected to be in the range of $18 million to $23 million in
2004.
- - The Company has begun construction of a 113-megawatt coal-
fired development project in Hardin, Montana, as previously
discussed in Risk Factors and Cautionary Statements that May
Affect Future Results. 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 the
plant. The Company is optimistic that this plant will be under
contract by the time of plant completion. The projected on-line
date for this plant is late 2005.
New Accounting Standards
In 2003, the Company adopted the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation," and began expensing the fair market value of stock
options for all awards granted on or after January 1, 2003.
Compensation expense recognized for awards granted on or after
January 1, 2003, for the year ended December 31, 2003, was
$41,000 (after tax).
In June 2001, the Financial Accounting Standards Board (FASB)
approved SFAS No. 143. Upon adoption of SFAS No. 143, the
Company recorded an additional discounted liability of $22.5
million and a regulatory asset of $493,000, increased net
property, plant and equipment by $9.6 million and recognized a
one-time cumulative effect charge of $7.6 million (net of
deferred income tax benefits of $4.8 million).
In April 2002, the FASB approved SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections." The adoption of SFAS No. 145 did
not have a material effect on the Company's financial position or
results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). The Company is applying the initial
recognition and initial measurement provisions of FIN 45 to
guarantees issued or modified after December 31, 2002.
In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities."
SFAS No. 149 is generally effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships
designated after June 30, 2003. The adoption of SFAS No. 149 did
not have a material effect on the Company's financial position or
results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both
Liabilities and Equity." SFAS No. 150 is effective for financial
instruments entered into or modified after May 31, 2003, and
otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. The Company will apply
SFAS No. 150 to any financial instruments entered into or
modified after May 31, 2003. Beginning in 2003, the Company
reported its preferred stock subject to mandatory redemption as a
liability in accordance with SFAS No. 150. The transition to
SFAS No. 150 did not have a material effect on the Company's
financial position or results of operations.
In December 2003, the FASB issued FASB Interpretation No. 46
(revised 2003), "Consolidation of Variable Interest Entities"
(FIN 46 (revised)), which revised FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" (FIN 46). FIN 46
(revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period
that ends after March 15, 2004. However, an entity that applied
FIN 46 to an entity prior to the effective date of FIN 46
(revised) shall either continue to apply FIN 46 until the
effective date of FIN 46 (revised) or apply FIN 46 (revised) at
an earlier date. The adoption of FIN 46 did not have a material
effect on the Company's financial position or results of
operations. The Company will continue to apply FIN 46 until the
effective date of FIN 46 (revised).
In December 2003, the FASB issued SFAS No. 132 (revised 2003),
"Employers' Disclosures about Pension and Other Postretirement
Benefits." SFAS No. 132 (revised 2003) is effective for
financial statements with fiscal years ending after December 15,
2003. The Company applied SFAS No. 132 (revised 2003) to its
consolidated financial statements issued after December 15, 2003.
In January 2004, the FASB issued FASB Staff Position No. FAS
106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003." FASB Staff Position No. FAS 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug
benefit to make a one-time election to defer accounting for the
effects of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (2003 Medicare Act). The Company
provides prescription drug benefits to certain eligible employees
and has elected the one-time deferral of accounting for the
effects of the 2003 Medicare Act. The Company intends to analyze
the 2003 Medicare Act, along with the authoritative guidance,
when issued, to determine if its benefit plans need to be amended
and how to record the effects of the 2003 Medicare Act.
For further information on SFAS No. 123, SFAS No. 143, SFAS
No. 145, FIN 45, SFAS No. 149, SFAS No. 150, FIN 46 (revised),
SFAS No. 132 (revised 2003) and FASB Staff Position No. FAS 106-
1, see Item 8 -- Financial Statements and Supplementary Data -
Note 1.
Critical Accounting Policies Involving Significant Estimates
The Company has prepared its financial statements in
conformity with accounting principles generally accepted in the
United States of America. The preparation of these financial
statements requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and
expenses during the reporting period. The Company's significant
accounting policies are discussed in Item 8 -- Financial
Statements and Supplementary Data - Note 1.
Estimates are used for items such as impairment testing of
long-lived assets, goodwill and natural gas and oil properties;
fair values of acquired assets and liabilities under the purchase
method of accounting; natural gas and oil reserves; property
depreciable lives; tax provisions; uncollectible accounts;
environmental and other loss contingencies; accumulated provision
for revenues subject to refund; costs on construction contracts;
unbilled revenues; actuarially determined benefit costs; asset
retirement obligations; the valuation of stock-based
compensation; and the fair value of derivative instruments,
including the fair value of an embedded derivative in a power
purchase agreement related to an equity method investment in
Brazil, as discussed in Item 8 -- Financial Statements and
Supplementary Data - Note 2. The Company's critical accounting
policies are subject to judgments and uncertainties that affect
the application of such policies. As discussed below, the
Company's financial position or results of operations may be
materially different when reported under different conditions or
when using different assumptions in the application of such
policies.
As additional information becomes available, or actual amounts
are determinable, the recorded estimates are revised.
Consequently, operating results can be affected by revisions to
prior accounting estimates. The following critical accounting
policies involve significant judgments and estimates.
Impairment of long-lived assets and intangibles
The Company reviews the carrying values of its long-lived
assets, including goodwill and identifiable intangibles, whenever
events or changes in circumstances indicate that such carrying
values may not be recoverable and annually for goodwill as
required by SFAS No. 142, "Goodwill and Other Intangible Assets."
Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived
assets and intangibles due to changes in estimates of future cash
flows could negatively affect the fair value of the Company's
assets and result in an impairment charge. If an impairment
indicator exists for tangible and intangible assets, excluding
goodwill, the asset group held and used is tested for
recoverability by comparing the carrying value to its fair value,
based on an estimate of undiscounted future cash flows
attributable to the assets. In the case of goodwill, the first
step, used to identify a potential impairment, compares the fair
value of the reporting unit using discounted cash flows, with its
carrying amount, including goodwill. The second step, used to
measure the amount of the impairment loss if step one indicates a
potential impairment, compares the implied fair value of the
reporting unit goodwill with the carrying amount of goodwill.
Fair value is the amount at which the asset could be bought or
sold in a current transaction between willing parties. The
Company uses critical estimates and assumptions when testing
assets for impairment, including present value techniques based
on estimates of cash flows, quoted market prices or valuations by
third parties, or multiples of earnings or revenue performance
measures. The fair value of the asset could be different using
different estimates and assumptions in these valuation
techniques.
There is risk involved when determining the fair value of
assets, tangible and intangible, as there may be unforeseen
events and changes in circumstances and market conditions and
changes in estimates of future cash flows.
The Company believes its estimates used in calculating the
fair value of long-lived assets, including goodwill and
identifiable intangibles, are reasonable based on the information
that is known at the point in time the estimates are made. In
addition, goodwill impairment testing is performed annually in
accordance with SFAS No. 142 and no impairment loss has been
recorded subsequent to the adoption of SFAS No. 141, "Business
Combinations" and SFAS No. 142.
Natural gas and oil properties
The Company uses the full-cost method of accounting for its
natural gas and oil production activities. Capitalized costs are
subject to a "ceiling test" that limits such costs to the
aggregate of the present value of future net revenues of proved
reserves based on single point-in-time spot market prices, as
mandated under the rules of the Securities and Exchange
Commission, and the lower of cost or fair value of unproved
properties. Judgments and assumptions are made when estimating
and valuing reserves. There is risk that sustained downward
movements in natural gas and oil prices and changes in estimates
of reserve quantities could result in a future write-down of the
Company's natural gas and oil properties.
Estimates of reserves are arrived at using actual historical
wellhead production trends and/or standard reservoir engineering
methods utilizing all available engineering and geologic data
derived from well tests. Other factors used in the reserve
estimates are current natural gas and oil prices, current
estimates of well operating and future development costs, and the
interest owned by the Company in the well. These estimates are
refined as new information becomes available.
Historically, the Company has not had any material revisions
to its reserve estimates. As a result, the Company has not
changed its practice in estimating reserves and does not
anticipate changing its methodologies in the future.
Revenue recognition
Revenue is recognized when the earnings process is complete,
as evidenced by an agreement between the customer and the
Company, when delivery has occurred or services have been
rendered, when the fee is fixed or determinable and when
collection is probable. The recognition of revenue in conformity
with accounting principles generally accepted in the United
States of America requires the Company to make estimates and
assumptions that affect the reported amounts of revenue.
Critical estimates related to the recognition of revenue include
the accumulated provision for revenues subject to refund and
costs on construction contracts under the percentage-of-
completion method.
Estimates for revenues subject to refund are established
initially for each regulatory rate proceeding and are subject to
change depending on the applicable regulatory agency's (Agency)
approval of final rates. These estimates are based on the
Company's analysis of its as-filed application compared to
previous Agency decisions in prior rate filings by the Company
and other regulated companies. The Company periodically reviews
the status of its outstanding regulatory proceedings and reserve
assumptions and may from time to time change its reserve
estimates subject to known developments as the regulatory
proceedings move through the regulatory review process. The
accuracy of the estimates is ultimately determined when the
Agency issues its final ruling on each regulatory proceeding for
which revenues were subject to refund. Estimates have changed
from time to time as additional information has become available
as to what the ultimate outcome may be and will likely continue
to change in the future as new information becomes available on
each outstanding regulatory proceeding that is subject to refund.
The Company recognizes construction contract revenue from
fixed price and modified fixed price construction contracts at
its construction businesses using the percentage-of-completion
method, measured by the percentage of costs incurred to date to
estimated total costs for each contract. This method depends
largely on the ability to make reasonably dependable estimates
related to the extent of progress toward completion of the
contract, contract revenues and contract costs. There are risks
involved when making these estimates as contract prices are
generally set before the work is performed, which means every
project could contain significant unknown risks such as volatile
labor and material costs, weather delays, adverse project site
conditions, unforeseen actions by regulatory agencies,
performance by subcontractors, job management and relations with
project owners.
Several factors are evaluated in determining the bid price for
contract work. These include, but are not limited to, the
complexities of the job, past history performing similar types of
work, seasonal weather patterns, competition and market
conditions, job site conditions, work force safety, reputation of
the project owner, availability of labor and materials, project
location and project completion dates. As a project commences,
estimates are continually monitored and revised as information
becomes available and actual costs and conditions surrounding the
job become known.
The Company believes its estimates surrounding percentage-of-
completion accounting are reasonable based on the information
that is known at the point in time the estimates are made. The
Company has contract administration, accounting and management
control systems in place that allow its estimates to be updated
and monitored on a regular basis. Because of the many factors
that are evaluated in determining bid prices, it is inherent that
the Company's estimates have changed in the past and will
continually change in the future as new information becomes
available for each job.
Purchase accounting
The Company accounts for its acquisitions under the purchase
method of accounting and, accordingly, the acquired assets and
liabilities assumed are recorded at their respective fair values.
The excess of the purchase price over the fair value of the
assets acquired and liabilities assumed is recorded as goodwill.
The recorded values of assets and liabilities are based on third-
party estimates and valuations when available. The remaining
values are based on management's judgments and estimates, and,
accordingly, the Company's financial position or results of
operations may be affected by changes in estimates and judgments.
Acquired assets and liabilities assumed by the Company that
are subject to critical estimates include property, plant and
equipment (including owned aggregate reserve deposits) and
intangible assets.
The fair value of owned recoverable aggregate reserve deposits
are determined using qualified internal personnel as well as
geologists. Reserve estimates are calculated based on the best
available data. This data is collected from drill holes and
other subsurface investigations as well as investigations of
surface features such as mine highwalls and other exposures of
the aggregate reserves. Mine plans, production history and
geologic data are also used to estimate reserve quantities.
Value is assigned to the aggregate reserves based on a review of
market royalty rates, expected cash flows and the number of years
of recoverable aggregate reserves at owned aggregate sites.
The fair value of property, plant and equipment is based on a
valuation performed either by qualified internal personnel and/or
outside appraisers. Fair values assigned to plant and equipment
are based on several factors including the age and condition of
the equipment, maintenance records of the equipment and auction
values for equipment with similar characteristics at the time of
purchase.
Intangible assets are identified and valued using the
guidelines of SFAS No. 141. The fair value of intangible assets
is based on estimates including royalty rates, lease terms and
other discernible factors for acquired leasehold rights, and
estimated cash flows.
While the allocation of the purchase price of an acquisition
is subject to a high level of judgment and uncertainty, the
Company does not expect the estimates to vary significantly once
an acquisition has been completed. The Company believes its
estimates have been reasonable in the past as there have been no
significant valuation adjustments subsequent to the final
allocation of the purchase price to the acquired assets and
liabilities. In addition, goodwill impairment testing is
performed annually in accordance with SFAS No. 142. No
impairment loss has been recorded subsequent to the adoption of
SFAS No. 141 and SFAS No. 142, as previously discussed.
Asset retirement obligations
SFAS No. 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in
which it is incurred. The Company has recorded obligations
related to the plugging and abandonment of natural gas and oil
wells, decommissioning of certain electric generating facilities,
reclamation of certain aggregate properties and certain other
obligations associated with leased properties.
The liability for future asset retirement obligations bears
the risk of change as many factors go into the development of the
estimate of these obligations and the possibility that over time
these factors can and will change. Factors used in the
estimation of future asset retirement obligations include
estimates of current retirement costs, future inflation factors,
life of the asset and discount rates. These factors determine
both a present value of the retirement liability and the
accretion to the retirement liability in subsequent years.
Long-lived assets are reviewed to determine if a legal
retirement obligation exists. If a legal retirement obligation
exists, a determination of the liability is made if a reasonable
estimate of the present value of the obligation can be made. The
present value of the retirement obligation is calculated by
inflating current estimated retirement costs of the long-lived
asset over its expected life to determine the expected future
cost and then discounting the expected future cost back to the
present value using a discount rate equal to the credit-adjusted
risk-free interest rate in effect when the liability was
initially recognized.
These estimates and assumptions are subject to a number of
variables and are expected to change in the future. Estimates
and assumptions will change as the estimated useful lives of the
assets change, the current estimated retirement costs change, new
legal retirement obligations occur and/or as existing legal asset
retirement obligations, for which a reasonable estimate of fair
value could not initially be made because of uncertainty, become
less uncertain and a reasonable estimate of the future liability
can be made.
Pension and other postretirement benefits
The Company has noncontributory defined benefit pension plans
and other postretirement benefit plans for certain eligible
employees. Various actuarial assumptions are used in calculating
the benefit expense (income) and liability (asset) related to
these plans. Costs of providing pension and other postretirement
benefits bear the risk of change, as they are dependent upon
numerous factors based on assumptions of future conditions.
The Company makes various assumptions when determining plan
costs, including the current discount rates and the expected long-
term return on plan assets, the rate of compensation increases
and healthcare cost trend rates. In selecting the expected long-
term return on plan assets, which is considered to be one of the
key variables in determining benefit expense or income, the
Company considers both current market conditions and expected
future market trends, including changes in interest rates and
equity and bond market performance. Another key variable in
determining benefit expense or income is the discount rate. In
selecting the discount rate, the Company uses the yield of a
fixed-income debt security, which has a rating of "Aa" or higher
published by a recognized rating agency, as well as other
factors, as a basis. The pension and other postretirement
benefit plan assets are primarily made up of equity and fixed
income investments. Fluctuations in actual equity and bond
market returns as well as changes in general interest rates may
result in increased or decreased pension and other postretirement
benefit costs in the future. Management estimates the rate of
compensation increase based on long-term assumed wage increases
and the healthcare cost trend rates are determined by historical
and future trends.
The Company believes the estimates made for its pension and
other postretirement benefits are reasonable based on the
information that is known at the point in time the estimates are
made. These estimates and assumptions are subject to a number of
variables and are expected to change in the future. Estimates
and assumptions will be affected by changes in the discount rate,
the expected long-term return on plan assets, the rate of
compensation increase and healthcare cost trend rates. The
Company plans to continue to use its current methodologies to
determine plan costs.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in 2003 increased
$92.1 million compared to 2002, primarily the result of higher
deferred income taxes of $33.8 million due in part to additional
tax depreciation allowed in 2003. Also adding to the increase in
cash flows provided by operating activities were higher
depreciation, depletion and amortization expense of $30.4
million, resulting largely from increased property, plant and
equipment balances and higher mineral production volumes, and an
increase in cash from net income of $26.9 million.
In 2002, cash flows from operating activities decreased $22.2
million compared to 2001, largely the result of a decrease in
cash from working capital items of $58.4 million. The working
capital decrease was primarily due to lower natural gas prices
compared to 2001. Higher depreciation, depletion and
amortization expense of $18.0 million, resulting largely from
increased property, plant and equipment balances, along with an
increase in other noncurrent changes of $15.7 million, partially
offset the decrease in cash flows from operating activities.
Investing activities --
Cash flows used in investing activities in 2003 increased
$67.1 million compared to 2002, the result of an increase in net
capital expenditures (capital expenditures; acquisitions, net of
cash acquired; and net proceeds from the sale or disposition of
property) of $78.1 million, partially offset by an increase in
cash flows from investments of $7.2 million and proceeds from
notes receivable of $3.8 million. Net capital expenditures
exclude the noncash transactions related to acquisitions,
including the issuance of the Company's equity securities. The
noncash transactions were $42.4 million and $47.2 million for the
years ended December 31, 2003 and 2002, respectively.
In 2002, cash flows used in investing activities increased
$6.2 million compared to 2001, the result of an increase in net
capital expenditures of $22.6 million and an increase in
investments of $7.4 million, partially offset by a decrease in
notes receivable of $23.8 million. Net capital expenditures
exclude the noncash transactions related to acquisitions,
including the issuance of the Company's equity securities. The
noncash transactions were $47.2 million and $57.4 million for the
years ended December 31, 2002 and 2001, respectively.
Financing activities --
Cash flows provided by financing activities in 2003 decreased
$31.9 million compared to 2002, the result of a decrease of
proceeds from issuance of common stock of $54.6 million, a net
decrease in short-term borrowings of $40.0 million and an
increase in the repayment of long-term debt of $23.2 million.
The increase in the issuance of long-term debt of $90.8 million
partially offset the decrease in cash provided by financing
activities.
In 2002, cash flows provided by financing activities increased
$48.8 million compared to 2001. This increase was primarily the
result of the decrease of the repayment of long-term debt of
$32.5 million and the net increase of short-term borrowings of
$28.0 million, partially offset by the decrease in proceeds from
issuance of common stock of $12.0 million.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit
pension plans (Pension Plans) for certain employees. Plan assets
consist of investments in equity and fixed income securities.
Various actuarial assumptions are used in calculating the benefit
expense (income) and liability (asset) related to the Pension
Plans. Actuarial assumptions include assumptions about the
discount rate, expected return on plan assets and rate of future
compensation increases as determined by the Company within
certain guidelines. At December 31, 2003, certain Pension Plans'
accumulated benefit obligations exceeded these plans' assets by
approximately $4.3 million. Pretax pension expense (income)
reflected in the years ended December 31, 2003, 2002 and 2001 was
$153,000, ($2.4) million and ($4.4) million, respectively. The
Company's pension expense is currently projected to be
approximately $4.0 million to $5.0 million in 2004. A reduction
in the Company's assumed discount rate for Pension Plans along
with declines in the equity markets experienced in 2002 and 2001
have combined to largely produce the increase in these costs.
Funding for the Pension Plans is actuarially determined. The
minimum required contributions for 2003, 2002 and 2001 were
approximately $1.6 million, $1.2 million and $442,000,
respectively. For further information on the Company's Pension
Plans, see Item 8 -- Financial Statements and Supplementary Data
- - Note 16.
Capital expenditures
The Company's capital expenditures (in millions) for 2001
through 2003 and as anticipated for 2004 through 2006 are
summarized in the following table, which also includes the
Company's capital needs for the retirement of maturing long-term
debt.
Actual Estimated*
2001 2002 2003 Capital expenditures: 2004 2005 2006
$ 14.4 $ 27.8 $ 28.5 Electric $ 23.3 $ 46.3 $123.0
14.7 11.0 15.7 Natural gas distribution 13.5 16.8 16.2
70.2 17.3 7.8 Utility services 9.5 10.3 10.9
Pipeline and energy
51.0 21.5 93.0 services 38.3 29.7 32.8
Natural gas and oil
118.7 136.4 101.7 production 139.9 138.7 123.2
Construction materials
170.6 106.9 128.5 and mining 90.0 82.4 80.7
Independent power
--- 95.7 112.8 production and other 66.1 80.9 50.7
439.6 416.6 488.0 380.6 405.1 437.5
Net proceeds from sale or
(51.6) (16.2) (14.4) disposition of property (10.7) (3.0) (1.6)
388.0 400.4 473.6 Net capital expenditures 369.9 402.1 435.9
Retirement of
115.2 82.6 105.7 long-term debt 27.6 70.9 173.2
$503.2 $483.0 $579.3 $397.5 $473.0 $609.1
_________________________________
*The estimated 2004 through 2006 capital expenditures reflected
in the above table include potential future acquisitions. The
Company continues to evaluate potential future acquisitions;
however, these acquisitions are dependent upon the availability
of economic opportunities and, as a result, actual acquisitions
and capital expenditures may vary significantly from the above
estimates.
Capital expenditures for 2003, 2002 and 2001, related to
acquisitions, in the preceding table include the following
noncash transactions: issuance of the Company's equity
securities of $42.4 million in 2003, $47.2 million in 2002 and
$57.4 million in 2001.
In 2003, the Company acquired a number of businesses, none of
which was individually material, including construction materials
and mining businesses in Montana, North Dakota and Texas and a
wind-powered electric generating facility in California. The
total purchase consideration for these businesses and adjustments
with respect to certain other acquisitions acquired in 2002,
including the Company's common stock and cash, was $175.0
million. Pro forma financial amounts reflecting the effects of
the above acquisitions are not presented, as such acquisitions
were not material to the Company's financial position or results
of operations.
The 2003 capital expenditures, including those for the
previously mentioned acquisitions and retirements of long-term
debt, were met from internal sources, the issuance of long-term
debt and the Company's equity securities. Estimated capital
expenditures for the years 2004 through 2006 include those for:
- Potential future acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Land and building improvements
- Pipeline and gathering expansion projects
- The further enhancement of natural gas and oil production
and reserve growth
- Power generation opportunities, including the construction
or acquisition of an additional 175-megawatts to 200-megawatts of
capacity over the next 10 years and certain construction costs
for a 113-megawatt coal-fired development project, as previously
discussed
- Other growth opportunities
The Company continues to evaluate potential future
acquisitions and other growth opportunities; however, they are
dependent upon the availability of economic opportunities and, as
a result, capital expenditures may vary significantly from the
estimates in the preceding table. It is anticipated that all of
the funds required for capital expenditures and retirements of
long-term debt for the years 2004 through 2006 will be met from
various sources. These sources include internally generated
funds; commercial paper credit facilities at Centennial and MDU
Resources Group, Inc., as described below; and through the
issuance of long-term debt and the Company's equity securities.
Capital resources
Certain debt instruments of the Company and its subsidiaries,
including those discussed below, contain restrictive covenants,
all of which the Company and its subsidiaries were in compliance
with at December 31, 2003.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various
banks totaling $90 million at December 31, 2003. There were no
amounts outstanding under the credit agreement at December 31,
2003. The credit agreement supports the Company's $75 million
commercial paper program. Under the Company's commercial paper
program, $40.0 million was outstanding at December 31, 2003. The
commercial paper borrowings are classified as long-term debt as
the Company intends to refinance these borrowings on a long-term
basis through continued commercial paper borrowings and as
further supported by the credit agreement, which expires on July
18, 2006.
The Company's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If the Company were to experience a minor
downgrade of its credit ratings, it would not anticipate any
change in its ability to access the capital markets. However, in
such event, the Company would expect a nominal basis point
increase in overall interest rates with respect to its cost of
borrowings. If the Company were to experience a significant
downgrade of its credit ratings, which it does not currently
anticipate, it may need to borrow under its credit agreement.
To the extent the Company needs to borrow under its credit
agreement, it would be expected to incur increased annualized
interest expense on its variable rate debt of approximately
$60,000 (after tax) based on December 31, 2003, variable rate
borrowings. Based on the Company's overall interest rate
exposure at December 31, 2003, this change would not have a
material effect on the Company's results of operations or cash
flows.
Prior to the maturity of the credit agreement, the Company
plans to negotiate the extension or replacement of this agreement
that provides credit support to access the capital markets. In
the event the Company was unable to successfully negotiate the
credit agreement, or in the event the fees on this facility
became too expensive, which it does not currently anticipate, the
Company would seek alternative funding. One source of
alternative funding might involve the securitization of certain
Company assets.
In order to borrow under the Company's credit agreement, the
Company must be in compliance with the applicable covenants and
certain other conditions. The significant covenants include
maximum leverage ratios, minimum interest coverage ratio,
limitation on sale of assets and limitation on investments. The
Company was in compliance with these covenants and met the
required conditions at December 31, 2003. In the event the
Company does not comply with the applicable covenants and other
conditions, alternative sources of funding may need to be
pursued, as previously described.
There are no credit facilities that contain cross-default
provisions between the Company and any of its subsidiaries.
On December 23, 2003, the Company issued $30 million in
aggregate principal amount of its 5.98% Senior Notes due 2033
(Senior Notes). The Senior Notes were issued as a series of debt
securities under an Indenture, dated as of December 15, 2003,
between the Company and The Bank of New York, as trustee
(Indenture Trustee). The Senior Notes are secured by the lien of
a matching aggregate principal amount of the Company's First
Mortgage Bonds that were issued to the Indenture Trustee for the
benefit of the holders of the Senior Notes and a junior lien on
the Company's electric and natural gas utility property. The
liens securing the Senior Notes may be released in certain
circumstances.
On February 10, 2004, the Company issued 2.3 million shares of
its common stock and appurtenant preference share purchase rights
to the public at a price per share of $23.32 in an underwritten
public offering and received net proceeds from the offering of
approximately $51.5 million, after deducting underwriting
discounts and commissions and offering expenses payable by the
Company. Approximately $24 million of the net proceeds was used
to repay outstanding indebtedness. The remainder of the net
proceeds of the sale of these shares was added to the Company's
general funds and may be used for the repayment of outstanding
debt obligations, for corporate development purposes (including
the acquisition of other businesses and/or business assets), and
for other general corporate purposes.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of
its Indenture of Mortgage. Generally, those restrictions require
the Company to pledge $1.43 of unfunded property to the trustee
for each dollar of indebtedness incurred under the Indenture and
that annual earnings (pretax and before interest charges), as
defined in the Indenture, equal at least two times its annualized
first mortgage bond interest costs. Under the more restrictive
of the two tests, as of December 31, 2003, the Company could have
issued approximately $313 million of additional first mortgage
bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.7 times and 4.8 times for the years ended
December 31, 2003 and 2002, respectively. Additionally, the
Company's first mortgage bond interest coverage was 7.4 times and
7.7 times for the years ended December 31, 2003 and 2002,
respectively. Common stockholders' equity as a percent of total
capitalization was 60 percent at December 31, 2003 and 2002.
Centennial Energy Holdings, Inc.
Centennial has two revolving credit agreements with various
banks that supports $275 million of Centennial's $350 million
commercial paper program. There were no outstanding borrowings
under the Centennial credit agreements at December 31, 2003.
Under the Centennial commercial paper program, $32.5 million was
outstanding at December 31, 2003. The Centennial commercial
paper borrowings are classified as long-term debt as Centennial
intends to refinance these borrowings on a long-term basis
through continued Centennial commercial paper borrowings and as
further supported by the Centennial credit agreements. The
Centennial credit agreements are for $137.5 million each. One of
these agreements expires on September 3, 2004, and allows for
subsequent borrowings up to a term of one year. The other
agreement expires on September 5, 2006. Centennial intends to
negotiate the extension or replacement of these agreements prior
to their maturities.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $400 million. Under the
terms of the master shelf agreement, $384.0 million was
outstanding at December 31, 2003. To meet potential future
financing needs, Centennial may pursue other financing
arrangements, including private and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If Centennial were to experience a minor
downgrade of its credit ratings, it would not anticipate any
change in its ability to access the capital markets. However, in
such event, Centennial would expect a nominal basis point
increase in overall interest rates with respect to its cost of
borrowings. If Centennial were to experience a significant
downgrade of its credit ratings, which it does not currently
anticipate, it may need to borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt of approximately
$49,000 (after tax) based on December 31, 2003, variable rate
borrowings. Based on Centennial's overall interest rate exposure
at December 31, 2003, this change would not have a material
effect on the Company's results of operations or cash flows.
Prior to the maturity of the Centennial credit agreements,
Centennial plans to negotiate the extension or replacement of
these agreements that provide credit support to access the
capital markets. In the event Centennial was unable to
successfully negotiate these agreements, or in the event the fees
on such facilities became too expensive, which Centennial does
not currently anticipate, it would seek alternative funding. One
source of alternative funding might involve the securitization of
certain Centennial assets.
In order to borrow under Centennial's credit agreements and
the Centennial uncommitted long-term master shelf agreement,
Centennial and certain of its subsidiaries must be in compliance
with the applicable covenants and certain other conditions. The
significant covenants include maximum capitalization ratios,
minimum interest coverage ratios, minimum consolidated net worth,
limitation on priority debt, limitation on sale of assets and
limitation on loans and investments. Centennial and such
subsidiaries were in compliance with these covenants and met the
required conditions at December 31, 2003. In the event
Centennial or such subsidiaries do not comply with the applicable
covenants and other conditions, alternative sources of funding
may need to be pursued as previously described.
Certain of Centennial's financing agreements contain cross-
default provisions. These provisions state that if Centennial or
any subsidiary of Centennial fails to make any payment with
respect to any indebtedness or contingent obligation, in excess
of a specified amount, under any agreement that causes such
indebtedness to be due prior to its stated maturity or the
contingent obligation to become payable, the applicable
agreements will be in default. Certain of Centennial's financing
agreements and Centennial's practice limit the amount of
subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $100 million.
Under the terms of the master shelf agreement, $55.0 million was
outstanding at December 31, 2003.
In order to borrow under Williston Basin's uncommitted long-
term master shelf agreement, it must be in compliance with the
applicable covenants and certain other conditions. The
significant covenants include limitation on consolidated
indebtedness, limitation on priority debt, limitation on sale of
assets and limitation on investments. Williston Basin was in
compliance with these covenants and met the required conditions
at December 31, 2003. In the event Williston Basin does not
comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued.
Off balance sheet arrangements
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the natural gas-fired electric generating
facility in Brazil, as discussed in Item 8 -- Financial
Statements and Supplementary Data - Note 2. The Company, through
MDU Brasil, owns 49 percent of MPX. The main business purpose of
Centennial extending the guarantee to MPX's creditors is to
enable MPX to obtain lower borrowing costs. At December 31,
2003, the aggregate amount of borrowings outstanding subject to
these guarantees was $45.5 million and the scheduled repayment of
these borrowings is $11.0 million in 2004, $10.7 million in 2005,
$10.7 million in 2006, $10.7 million in 2007 and $2.4 million in
2008. The individual investor (who through EBX Empreendimentos
Ltda. (EBX), a Brazilian company, owns 51 percent of MPX) has
also guaranteed a portion of these loans. In the event MPX
defaults under its obligation, Centennial and the individual
investor would be required to make payments under their
guarantees. Centennial and the individual investor have entered
into reimbursement agreements under which they have agreed to
reimburse each other to the extent they may be required to make
any guarantee payments in excess of their proportionate ownership
share in MPX. These guarantees are not reflected on the
Consolidated Balance Sheets.
As of December 31, 2003, Centennial was contingently liable
for the performance of certain of its subsidiaries under
approximately $360 million of surety bonds. These bonds are
principally for construction contracts and reclamation
obligations of these subsidiaries entered into in the normal
course of business. Centennial indemnifies the respective surety
bond companies against any exposure under the bonds. The purpose
of Centennial's indemnification is to allow the subsidiaries to
obtain bonding at competitive rates. In the event a subsidiary
of the Company does not fulfill its obligations in relation to
its bonded contract or obligation, Centennial may be required to
make payments under its indemnification. A large portion of
these contingent commitments are expected to expire within the
next 12 months; however, Centennial will likely continue to enter
into surety bonds for its subsidiaries in the future. The surety
bonds were not reflected on the Consolidated Balance Sheets.
Contractual obligations and commercial commitments
For more information on the Company's contractual obligations
on long-term debt, operating leases and purchase commitments, see
Item 8 -- Financial Statements and Supplementary Data - Notes 8
and 19. At December 31, 2003, the Company's commitments under
these obligations were as follows:
There-
2004 2005 2006 2007 2008 after Total
(In millions)
Long-term debt $ 27.6 $ 70.9 $173.2 $105.8 $160.2 $429.4 $ 967.1
Operating leases 18.1 12.4 8.7 5.1 3.9 22.1 70.3
Purchase
commitments 167.2 67.2 50.1 31.0 30.9 146.3 492.7
$212.9 $150.5 $232.0 $141.9 $195.0 $597.8 $1,530.1
Effects of Inflation
Inflation did not have a significant effect on the Company's
operations in 2003, 2002 or 2001.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices, interest rates and foreign
currency. The Company has policies and procedures to assist in
controlling these market risks and utilizes derivatives to manage
a portion of its risk.
The Company's policy allows the use of derivative instruments
as part of an overall energy price, foreign currency and interest
rate risk management program to efficiently manage and minimize
commodity price, foreign currency and interest rate risk. The
Company's policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions and
the Company has procedures in place to monitor compliance with
its policies. The Company is exposed to credit-related losses in
relation to derivative instruments in the event of nonperformance
by counterparties. The Company's policy requires settlement of
natural gas and oil price derivative instruments monthly and all
interest rate derivative transactions must be settled over a
period that will not exceed 90 days, and any foreign currency
derivative transaction settlement periods may not exceed a 12-
month period. The Company has policies and procedures that
management believes minimize credit-risk exposure. These
policies and procedures include an evaluation of potential
counterparties' credit ratings and credit exposure limitations.
Accordingly, the Company does not anticipate any material effect
to its financial position or results of operations as a result of
nonperformance by counterparties.
In the event a derivative instrument being accounted for as a
cash flow hedge does not qualify for hedge accounting because it
is no longer highly effective in offsetting changes in cash flows
of a hedged item; or if the derivative instrument expires or is
sold, terminated or exercised; or if management determines that
designation of the derivative instrument as a hedge instrument is
no longer appropriate, hedge accounting will be discontinued, and
the derivative instrument would continue to be carried at fair
value with changes in its fair value recognized in earnings. In
these circumstances, the net gain or loss at the time of
discontinuance of hedge accounting would remain in other
accumulated comprehensive income (loss) until the period or
periods during which the hedged forecasted transaction affects
earnings, at which time the net gain or loss would be
reclassified into earnings. In the event a cash flow hedge is
discontinued because it is unlikely that a forecasted transaction
will occur, the derivative instrument would continue to be
carried on the balance sheet at its fair value, and gains and
losses that had accumulated in other comprehensive income (loss)
would be recognized immediately in earnings. In the event of a
sale, termination or extinguishment of a foreign currency
derivative, the resulting gain or loss would be recognized
immediately in earnings. The Company's policy requires approval
to terminate a derivative instrument prior to its original
maturity.
Commodity price risk --
A subsidiary of the Company utilizes natural gas and oil price
swap and collar agreements to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil
on the subsidiary's forecasted sales of natural gas and oil
production. Each of the natural gas and oil price swap and
collar agreements were designated as a hedge of the forecasted
sale of natural gas and oil production.
On an ongoing basis, the balance sheet is adjusted to reflect
the current fair market value of the swap and collar agreements.
The related gains or losses on these agreements are recorded in
common stockholders' equity as a component of other comprehensive
income (loss). At the date the underlying transaction occurs,
the amounts accumulated in other comprehensive income (loss) are
reported in the Consolidated Statements of Income. To the extent
that the hedges are not effective, the ineffective portion of the
changes in fair market value is recorded directly in earnings.
The following table summarizes hedge agreements entered into
by an indirect wholly owned subsidiary of the Company, as of
December 31, 2003. These agreements call for the subsidiary of
the Company to receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2004 $ 5.17 11,890 $ (1,645)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2004 $4.34/$4.94 6,771 $ (3,481)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2004 $ 29.25 366 $ (341)
The following table summarizes hedge agreements entered into
by the subsidiary of the Company, as of December 31, 2002. These
agreements call for the subsidiary to receive fixed prices and
pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2003 $ 3.96 1,186 $ (731)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2003 $3.33/$3.89 22,365 $ (6,256)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2003 $24.50/$27.62 639 $ (457)
Interest rate risk --
The Company uses fixed and variable rate long-term debt to
partially finance capital expenditures and mandatory debt
retirements. These debt agreements expose the Company to market
risk related to changes in interest rates. The Company manages
this risk by taking advantage of market conditions when timing
the placement of long-term or permanent financing. The Company
has also historically used interest rate swap agreements to
manage a portion of the Company's interest rate risk and may take
advantage of such agreements in the future to minimize such risk.
The following table shows the amount of debt, including
current portion, and related weighted average interest rates,
both by expected maturity dates, as of December 31, 2003.
Weighted average variable rates are based on forward rates as of
December 31, 2003.
There- Fair
2004 2005 2006 2007 2008 after Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $27.6 $ 70.9 $100.7 $105.8 $160.2 $429.4 $894.6 $941.5
Weighted average
interest rate 5.8% 8.0% 6.5% 8.2% 4.4% 6.4% 6.4% -
Variable rate - - $ 72.5 - - - $ 72.5 $ 71.0
Weighted average
interest rate - - 1.1% - - - 1.1% -
For further information on derivative instruments and fair
value of other financial instruments, see Item 8 -- Financial
Statements and Supplementary Data - Notes 5 and 6.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-
megawatt natural gas-fired electric generating facility (Brazil
Generating Facility) in Brazil, which has a portion of its
borrowings and payables denominated in U.S. dollars. MDU Brasil
has exposure to currency exchange risk as a result of
fluctuations in currency exchange rates between the U.S. dollar
and the Brazilian real. The functional currency for the Brazil
Generating Facility is the Brazilian real. For further
information on this investment, see Item 8 -- Financial
Statements and Supplementary Data - Note 2.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on
transactions denominated in a currency other than the Brazilian
real, including the effects of changes in currency exchange rates
with respect to the Brazil Generating Facility's U.S. dollar
denominated obligations, excluding a U.S. dollar denominated loan
from Centennial Energy Resources International Inc (Centennial
International), an indirect wholly owned subsidiary of the
Company, as discussed below. At December 31, 2003, these U.S.
dollar denominated obligations approximated $66.9 million. If,
for example, the value of the Brazilian real decreased in
relation to the U.S. dollar by 10 percent, MDU Brasil, with
respect to its interest in the Brazil Generating Facility, would
record a foreign currency transaction loss in net income of
approximately $3.0 million (after tax) based on the above U.S.
dollar denominated obligations at December 31, 2003. The Brazil
Generating Facility also had approximately US$9.5 million of
Brazilian real denominated obligations at December 31, 2003.
Adjustments attributable to the translation from the Brazilian
real to the U.S. dollar for assets, liabilities, revenues and
expenses were recorded in accumulated other comprehensive income
(loss) at December 31, 2003. Foreign currency translation
adjustments on the Brazil Generating Facility's U.S. dollar
denominated borrowings payable to the subsidiary of $20.0 million
at December 31, 2003, are recorded in accumulated other
comprehensive income (loss).
The investment of Centennial International in the Brazil
Generating Facility at December 31, 2003, was approximately $25.2
million including undistributed earnings of $4.6 million.
Centennial has guaranteed Brazil Generating Facility obligations
and loans of approximately $45.5 million as of December 31, 2003.
A portion of the Brazil Generating Facility's foreign currency
exchange risk is being managed through contractual provisions,
which are largely indexed to the U.S. dollar, contained in the
Brazil Generating Facility's power purchase agreement with
Petrobras. The Brazil Generating Facility has also historically
used derivative instruments to manage a portion of its foreign
currency risk and may utilize such instruments in the future.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Management
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in this
Annual Report. The financial statements have been prepared in conformity
with accounting principles generally accepted in the United States of
America as applied to the company's regulated and nonregulated businesses
and necessarily include some amounts that are based on informed judgments
and estimates of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls
designed to provide assurance, on a cost-effective basis, that
transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an organizational
structure which provides an appropriate segregation of responsibilities,
effective selection and training of personnel, written policies and
procedures and periodic reviews by the Internal Auditing Department. In
addition, the company has a policy which requires certain employees to
acknowledge their responsibility for ethical conduct. Management believes
that these measures provide for a system that is effective and reasonably
assures that all transactions are properly recorded for the preparation of
financial statements. Management modifies and improves its system of
internal accounting controls in response to changes in business
conditions. The company's Internal Auditing Department is charged with
the responsibility for determining compliance with company procedures.
The Board of Directors, through its Audit Committee which is comprised
entirely of outside directors, oversees management's responsibilities for
financial reporting. The Audit Committee meets regularly with management;
the internal auditors; and Deloitte & Touche LLP, independent auditors, to
discuss auditing and financial matters and to assure that each is carrying
out its responsibilities. The internal auditors and Deloitte & Touche LLP
have full and free access to the Audit Committee, without management
present, to discuss auditing, internal accounting control and financial
reporting matters.
/s/MARTIN A. WHITE /s/WARREN L. ROBINSON
Martin A. White Warren L. Robinson
Chairman of the Board Executive Vice President
President and Chief and Chief Financial
Executive Officer Officer
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2003 2002 2001
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas
distribution and
pipeline and energy
services $ 641,062 $ 459,409 $ 903,334
Utility services, natural
gas and oil production,
construction materials
and mining and other 1,711,127 1,572,128 1,320,298
2,352,189 2,031,537 2,223,632
Operating expenses:
Fuel and purchased power 62,037 56,010 57,393
Purchased natural gas sold 184,171 92,528 529,356
Operation and maintenance:
Electric, natural gas
distribution and
pipeline and energy
services 141,307 129,845 129,372
Utility services, natural
gas and oil production,
construction materials
and mining and other 1,384,015 1,263,183 1,038,899
Depreciation, depletion and
amortization 188,337 157,961 139,917
Taxes, other than income 80,250 65,893 55,427
2,040,117 1,765,420 1,950,364
Operating income 312,072 266,117 273,268
Other income -- net (Note 1) 22,207 13,572 26,821
Interest expense 52,794 45,015 45,899
Income before income taxes 281,485 234,674 254,190
Income taxes 98,572 86,230 98,341
Income before cumulative effect
of accounting change 182,913 148,444 155,849
Cumulative effect of accounting
change (Note 9) (7,589) --- ---
Net income 175,324 148,444 155,849
Dividends on preferred stocks 717 756 762
Earnings on common stock $ 174,607 $ 147,688 $ 155,087
Earnings per common share --
basic:
Earnings before cumulative
effect of accounting change $ 1.64 $ 1.39 $ 1.54
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share --
basic $ 1.57 $ 1.39 $ 1.54
Earnings per common share --
diluted:
Earnings before cumulative
effect of accounting change $ 1.62 $ 1.38 $ 1.52
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share --
diluted $ 1.55 $ 1.38 $ 1.52
Dividends per common share $ .6600 $ .6266 $ .6000
Weighted average common shares
outstanding -- basic 111,483 106,115 100,908
Weighted average common shares
outstanding -- diluted 112,460 106,863 101,803
Pro forma amounts assuming
retroactive application of
accounting change:
Net income $ 182,913 $ 146,052 $ 152,933
Earnings per common share --
basic $ 1.64 $ 1.37 $ 1.51
Earnings per common share --
diluted $ 1.62 $ 1.36 $ 1.49
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
December 31, 2003 2002
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 86,341 $ 67,556
Receivables, net 357,677 325,395
Inventories 114,051 93,123
Deferred income taxes 3,104 8,877
Prepayments and other current assets 52,367 42,597
613,540 537,548
Investments 44,975 42,864
Property, plant and equipment 3,397,619 2,961,808
Less accumulated depreciation,
depletion and amortization 1,175,326 1,019,438
2,222,293 1,942,370
Deferred charges and other assets:
Goodwill (Note 3) 199,427 190,999
Other intangible assets, net (Note 3) 193,454 176,164
Other 106,903 106,976
499,784 474,139
$3,380,592 $2,996,921
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings (Note 7) $ --- $ 20,000
Long-term debt and preferred
stock due within one year 27,646 22,183
Accounts payable 150,316 132,120
Taxes payable 15,358 13,108
Dividends payable 19,442 17,959
Other accrued liabilities 101,299 94,275
314,061 299,645
Long-term debt (Note 8) 939,450 819,558
Deferred credits and other liabilities:
Deferred income taxes 444,779 374,097
Other liabilities 231,666 203,676
676,445 577,773
Preferred stock subject to mandatory
redemption (Note 10) --- 1,200
Commitments and contingencies (Notes 16, 18 and 19)
Stockholders' equity:
Preferred stocks (Note 10) 15,000 15,000
Common stockholders' equity:
Common stock (Note 11)
Authorized -- 250,000,000 shares,
$1.00 par value
Issued - 113,716,632 shares in 2003 and
74,282,038 shares in 2002 113,717 74,282
Other paid-in capital 757,787 748,095
Retained earnings 575,287 474,798
Accumulated other comprehensive loss (7,529) (9,804)
Treasury stock at cost - 359,281 shares
in 2003 and 239,521 shares in 2002 (3,626) (3,626)
Total common stockholders' equity 1,435,636 1,283,745
Total stockholders' equity 1,450,636 1,298,745
$3,380,592 $2,996,921
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Years ended December 31, 2003, 2002 and 2001
Accumu-
lated
Other
Compre-
Other hensive
Common Stock Paid-in Retained Income Treasury Stock
Shares Amount Capital Earnings (Loss) Shares Amount Total
(In thousands, except shares)
Balance at
December 31, 2000 65,267,567 $ 65,268 $518,771 $300,647 $ --- (239,521) $(3,626) $ 881,060
Comprehensive income:
Net income --- --- --- 155,849 --- --- --- 155,849
Other comprehensive
income, net of tax -
Net unrealized gain on
derivative instruments
qualifying as hedges --- --- --- --- 2,218 --- --- 2,218
Total comprehensive
income --- --- --- --- --- --- --- 158,067
Dividends on
preferred stocks --- --- --- (762) --- --- --- (762)
Dividends on
common stock --- --- --- (61,093) --- --- --- (61,093)
Issuance of
common stock, net 4,749,284 4,749 127,750 --- --- --- --- 132,499
Balance at
December 31, 2001 70,016,851 70,017 646,521 394,641 2,218 (239,521) (3,626) 1,109,771
Comprehensive income:
Net income --- --- --- 148,444 --- --- --- 148,444
Other comprehensive
loss, net of tax -
Net unrealized loss on
derivative instruments
qualifying as hedges --- --- --- --- (6,759) --- --- (6,759)
Minimum pension liability
adjustment --- --- --- --- (4,464) --- --- (4,464)
Foreign currency
translation adjustment --- --- --- --- (799) --- --- (799)
Total comprehensive
income --- --- --- --- --- --- --- 136,422
Dividends on
preferred stocks --- --- --- (756) --- --- --- (756)
Dividends on
common stock --- --- --- (67,531) --- --- --- (67,531)
Issuance of
common stock, net 4,265,187 4,265 101,574 --- --- --- --- 105,839
Balance at
December 31, 2002 74,282,038 74,282 748,095 474,798 (9,804) (239,521) (3,626) 1,283,745
Comprehensive income:
Net income --- --- --- 175,324 --- --- --- 175,324
Other comprehensive
income, net of tax -
Net unrealized gain on
derivative instruments
qualifying as hedges --- --- --- --- 1,206 --- --- 1,206
Minimum pension liability
adjustment --- --- --- --- 21 --- --- 21
Foreign currency
translation adjustment --- --- --- --- 1,048 --- --- 1,048
Total comprehensive
income --- --- --- --- --- --- --- 177,599
Dividends on
preferred stocks --- --- --- (717) --- --- --- (717)
Dividends on
common stock --- --- --- (74,118) --- --- --- (74,118)
Issuance of common stock,
net (pre-split) 1,442,220 1,442 45,260 --- --- --- --- 46,702
Three-for-two common
stock split (Note 11) 37,862,129 37,862 (37,862) --- --- (119,760) --- ---
Issuance of common stock,
net (post-split) 130,245 131 2,294 --- --- --- --- 2,425
Balance at
December 31, 2003 113,716,632 $113,717 $757,787 $575,287 $(7,529) (359,281) $(3,626) $1,435,636
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2003 2002 2001
(In thousands)
Operating activities:
Net income $ 175,324 $ 148,444 $155,849
Cumulative effect of accounting
change 7,589 --- ---
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 188,337 157,961 139,917
Deferred income taxes 64,587 30,759 21,014
Changes in current assets and
liabilities, net of
acquisitions:
Receivables (9,572) (19,739) 127,267
Inventories (13,023) 6,537 (26,540)
Other current assets (13,383) (5,562) (2,792)
Accounts payable 2,748 11,600 (90,576)
Other current liabilities 10,486 (9,499) 34,331
Other noncurrent changes 5,304 5,830 (9,916)
Net cash provided by operating
activities 418,397 326,331 348,554
Investing activities:
Capital expenditures (313,053) (276,776) (269,542)
Acquisitions, net of cash acquired (132,653) (92,657) (112,743)
Net proceeds from sale or
disposition of property 14,439 16,217 51,641
Investments 2,491 (4,666) 2,760
Additions to notes receivable --- --- (23,813)
Proceeds from notes receivable 7,812 4,000 4,000
Net cash used in investing
activities (420,964) (353,882) (347,697)
Financing activities:
Net change in short-term borrowings (20,000) 20,000 (8,000)
Issuance of long-term debt 219,895 129,072 122,283
Repayment of long-term debt (105,740) (82,523) (115,062)
Retirement of preferred stock --- (100) (100)
Proceeds from issuance of
common stock, net 568 55,134 67,176
Dividends paid (73,371) (68,287) (61,855)
Net cash provided by
financing activities 21,352 53,296 4,442
Increase in cash and cash equivalents 18,785 25,745 5,299
Cash and cash equivalents --
beginning of year 67,556 41,811 36,512
Cash and cash equivalents --
end of year $ 86,341 $ 67,556 $ 41,811
The accompanying notes are an integral part of these consolidated
financial statements.
NOTE 1
Summary of Significant Accounting Policies
Basis of presentation
The consolidated financial statements of MDU Resources Group, Inc. and
its subsidiaries (Company) include the accounts of the following
businesses: electric, natural gas distribution, utility services,
pipeline and energy services, natural gas and oil production,
construction materials and mining, and independent power production and
other. The electric, natural gas distribution, and pipeline and energy
services businesses are substantially all regulated. Utility services,
natural gas and oil production, construction materials and mining, and
independent power production and other are nonregulated. For further
descriptions of the Company's businesses, see Note 14. The statements
also include the ownership interests in the assets, liabilities and
expenses of two jointly owned electric generation stations.
The Company uses the equity method of accounting for certain
investments including its 49 percent interest in MPX Participacoes,
Ltda. (MPX), which was formed to develop electric generation and
transmission, steam generation, power equipment and coal mining
projects in Brazil. For more information on the Company's equity
investments, see new accounting standards in Note 1, as well as Note 2.
The Company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the Company's
nonregulated businesses.
The Company's regulated businesses account for certain income and
expense items under the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Regulation."
SFAS No. 71 requires these businesses to defer as regulatory assets or
liabilities certain items that would have otherwise been reflected as
expense or income, respectively, based on the expected regulatory
treatment in future rates. The expected recovery or flowback of these
deferred items generally is based on specific ratemaking decisions or
precedent for each item. Regulatory assets and liabilities are being
amortized consistently with the regulatory treatment established by the
FERC and the applicable state public service commissions. See Note 4
for more information regarding the nature and amounts of these
regulatory deferrals.
Prior to the sale of the Company's coal operations in 2001, as
discussed in Note 14, intercompany coal sales, which were made at
prices approximately the same as those charged to others, and the
related utility fuel purchases were not eliminated in accordance with
the provisions of SFAS No. 71. All other significant intercompany
balances and transactions have been eliminated in consolidation.
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of December 31, 2003
and 2002, was $8.1 million and $8.2 million, respectively.
Natural gas in underground storage
Natural gas in underground storage for the Company's regulated
operations is carried at cost using the last-in, first-out method. The
portion of the cost of natural gas in underground storage expected to
be used within one year was included in inventories and amounted to
$19.6 million at December 31, 2003, and $18.2 million at December 31,
2002. The remainder of natural gas in underground storage was included
in other assets and was $42.6 million at December 31, 2003, and $42.2
million at December 31, 2002.
Inventories
Inventories, other than natural gas in underground storage for the
Company's regulated operations, consisted primarily of aggregates held
for resale of $54.7 million and $39.6 million, materials and supplies
of $27.2 million and $23.0 million, and other inventories of $12.6
million and $12.3 million, as of December 31, 2003 and 2002,
respectively. These inventories were stated at the lower of average
cost or market.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost when
first placed in service. Acquired aggregate reserves at the Company's
construction materials and mining business are classified based on type
of ownership. Owned mineral rights are classified as property, plant
and equipment, whereas leased mineral rights are classified as other
intangible assets, net. For more information on other intangible
assets, net, see Note 3. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost of the asset is charged to accumulated depreciation. With
respect to the retirement or disposal of all other assets, except
for natural gas and oil production properties as described in
natural gas and oil properties in Note 1, the resulting gains or
losses are recognized as a component of income. The Company is
permitted to capitalize an allowance for funds used during
construction (AFUDC) on regulated construction projects and to
include such amounts in rate base when the related facilities are
placed in service. In addition, the Company capitalizes interest, when
applicable, on certain construction projects associated with its other
operations. The amount of AFUDC and interest capitalized was $7.4
million, $7.6 million and $6.6 million in 2003, 2002 and 2001,
respectively. Generally, property, plant and equipment are depreciated
on a straight-line basis over the average useful lives of the assets,
except for depletable reserves, which are depleted based on the units-
of-production method based on recoverable deposits, and natural gas and
oil production properties, which are amortized on the units-of-
production method based on total reserves.
Property, plant and equipment at December 31, 2003 and 2002, was as
follows:
Estimated
Depreciable
Life
2003 2002 in Years
(Dollars in thousands, as applicable)
Regulated:
Electric:
Electric generation, distribution
and transmission plant $ 639,893 $ 619,230 4-50
Natural gas distribution:
Natural gas distribution plant 252,591 244,930 4-40
Pipeline and energy services:
Natural gas transmission,
gathering and storage
facilities 340,841 262,971 3-70
Nonregulated:
Utility services:
Land 2,505 2,601 ---
Buildings and improvements 10,123 8,768 10-40
Machinery, vehicles and equipment 58,843 54,833 2-10
Other 5,400 4,458 3-10
Pipeline and energy services:
Natural gas gathering
and other facilities 119,613 108,179 3-20
Energy services 1,339 1,270 3-15
Natural gas and oil production:
Natural gas and oil properties 862,839 748,843 (a)
Other 8,518 6,945 5-7
Construction materials and mining:
Land 89,545 85,376 ---
Buildings and improvements 48,907 43,144 1-40
Machinery, vehicles and equipment 569,295 493,349 1-25
Construction in progress 14,392 10,151 ---
Depletable reserves 171,841 172,235 (b)
Independent power production and
other:
Electric generation 153,947 58,000 5-30
Construction in progress 29,805 19,342 ---
Land 2,001 2,001 ---
Other 15,381 15,182 3-20
Less accumulated depreciation,
depletion and amortization 1,175,326 1,019,438
Net property, plant and equipment $2,222,293 $1,942,370
(a) Amortized on the units-of-production method based on total proved
reserves at an Mcf equivalent rate of $.89, $.80, and $.78 for the
years ended December 31, 2003, 2002 and 2001, respectively.
Includes natural gas and oil production properties accounted for
under the full-cost method, of which $104,339 and $145,692 were
excluded from amortization at December 31, 2003 and 2002,
respectively.
(b) Depleted based on the units-of-production method based on
recoverable deposits.
Impairment of long-lived assets
The Company reviews the carrying values of its long-lived assets,
excluding goodwill, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable. The
determination of whether an impairment has occurred is based on an
estimate of undiscounted future cash flows attributable to the assets,
compared to the carrying value of the assets. If an impairment has
occurred, the amount of the impairment recognized is determined by
estimating the fair value of the assets and recording a loss if the
carrying value is greater than the fair value. No long-lived assets
have been impaired and, accordingly, no impairment losses have been
recorded in 2003, 2002 and 2001. Unforeseen events and changes in
circumstances could require the recognition of other impairment losses
at some future date.
Goodwill
Goodwill represents the excess of the purchase price over the fair
value of identifiable net tangible and intangible assets acquired in a
business combination. On January 1, 2002, the Company adopted SFAS No.
142, "Goodwill and Other Intangibles," and ceased amortization of its
goodwill. Goodwill is required to be tested for impairment annually or
more frequently if events or changes in circumstances indicate that
goodwill may be impaired. In accordance with SFAS No. 142, the Company
performed its transitional goodwill impairment testing as of January 1,
2002, and performed its annual goodwill impairment testing as of
October 31, 2003 and 2002, and determined that no impairments existed
at those dates. Therefore, no impairment loss has been recorded for
the years ended December 31, 2003 and 2002. For more information on
goodwill, see Note 3.
Natural gas and oil properties
The Company uses the full-cost method of accounting for its natural gas
and oil production activities. Under this method, all costs incurred
in the acquisition, exploration and development of natural gas and oil
properties are capitalized and amortized on the units-of-production
method based on total proved reserves. Any conveyances of properties,
including gains or losses on abandonments of properties, are treated as
adjustments to the cost of the properties with no gain or loss
recognized. Capitalized costs are subject to a "ceiling test" that
limits such costs to the aggregate of the present value of future net
revenues of proved reserves based on single point-in-time spot market
prices, as mandated under the rules of the Securities and Exchange
Commission, and the lower of cost or fair value of unproved properties.
Future net revenue is estimated based on end-of-quarter spot market
prices adjusted for contracted price changes. If capitalized costs
exceed the full-cost ceiling at the end of any quarter, a permanent
noncash write-down is required to be charged to earnings in that
quarter unless subsequent price changes eliminate or reduce an
indicated write-down.
At December 31, 2003 and 2002, the Company's full-cost ceiling exceeded
the Company's capitalized cost. However, sustained downward movements
in natural gas and oil prices subsequent to December 31, 2003, could
result in a future write-down of the Company's natural gas and oil
properties.
The following table summarizes the Company's natural gas and oil
properties not subject to amortization at December 31, 2003, in total
and by year in which such costs were incurred:
Year Costs Incurred
2000
Total 2003 2002 2001 and prior
(In thousands)
Acquisition $ 48,355 $ 630 $17,108 $--- $30,617
Development 39,160 28,351 5,120 --- 5,689
Exploration 4,885 4,828 --- 23 34
Capitalized interest 11,939 5,642 6,297 --- ---
Total costs not subject
to amortization $104,339 $39,451 $28,525 $ 23 $36,340
Costs not subject to amortization as of December 31, 2003, consisted
primarily of lease acquisition costs, unevaluated drilling costs and
capitalized interest associated with coalbed development in the Powder
River Basin of Montana and Wyoming. The Company expects that the
majority of these costs will be evaluated over the next three- to five-
year period and included in the amortization base as the properties are
developed and evaluated and proved reserves are established or
impairment is determined.
Revenue recognition
Revenue is recognized when the earnings process is complete, as
evidenced by an agreement between the customer and the Company, when
delivery has occurred or services have been rendered, when the fee is
fixed or determinable and when collection is probable. The Company
recognizes utility revenue each month based on the services provided to
all utility customers during the month. The Company recognizes
construction contract revenue at its construction businesses using the
percentage-of-completion method as discussed later. The Company
recognizes revenue from natural gas and oil production activities only
on that portion of production sold and allocable to the Company's
ownership interest in the related well. Revenues at the independent
power production operations are recognized based on electricity
delivered and capacity provided, pursuant to contractual commitments.
The Company recognizes all other revenues when services are rendered or
goods are delivered.
Percentage-of-completion method
The Company recognizes construction contract revenue from fixed price
and modified fixed price construction contracts at its construction
businesses using the percentage-of-completion method, measured by the
percentage of costs incurred to date to estimated total costs for each
contract. Costs in excess of billings on uncompleted contracts of
$31.8 million and $19.4 million for the years ended December 31, 2003
and 2002, respectively, represents revenues recognized in excess of
amounts billed and was included in receivables, net. Billings in
excess of costs on uncompleted contracts of $20.4 million and $24.5
million for the years ended December 31, 2003 and 2002, respectively,
represents billings in excess of revenues recognized and was included
in accounts payable. Also included in receivables, net were amounts
representing balances billed but not paid by customers under retainage
provisions in contracts that amounted to $34.3 million and
$25.6 million as of December 31, 2003 and 2002, respectively, which are
expected to be paid within one year or less.
Derivative instruments
The Company's policy allows the use of derivative instruments as part
of an overall energy price, foreign currency and interest rate risk
management program to efficiently manage and minimize commodity price,
foreign currency and interest rate risk. The Company's policy
prohibits the use of derivative instruments for speculating to take
advantage of market trends and conditions and the Company has
procedures in place to monitor compliance with its policies. The
Company is exposed to credit-related losses in relation to derivative
instruments in the event of nonperformance by counterparties. The
Company's policy requires settlement of natural gas and oil price
derivative instruments monthly and all interest rate derivative
transactions must be settled over a period that will not exceed 90
days, and any foreign currency derivative transaction settlement
periods may not exceed a 12-month period. The Company has policies and
procedures that management believes minimize credit-risk exposure.
These policies and procedures include an evaluation of potential
counterparties' credit ratings and credit exposure limitations.
Accordingly, the Company does not anticipate any material effect to its
financial position or results of operations as a result of
nonperformance by counterparties.
Advertising
The Company expenses advertising costs as incurred and the amount of
advertising expense for the years 2003, 2002 and 2001, was $3.9
million, $3.4 million and $2.9 million, respectively.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public
service commissions, the Company is deferring natural gas commodity,
transportation and storage costs that are greater or less than amounts
presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or
refundable through rate adjustments within a period ranging from 24
months to 28 months from the time such costs are paid. Natural gas
costs recoverable through rate adjustments amounted to $10.5 million at
December 31, 2003, which is included in prepayments and other current
assets. Natural gas costs refundable through rate adjustments amounted
to $2.4 million at December 31, 2002, which is included in other
accrued liabilities.
Insurance
Certain subsidiaries of the Company are insured for workers'
compensation losses, subject to deductibles ranging up to $500,000 per
occurrence. Automobile liability and general liability losses are
insured, subject to deductibles ranging up to $500,000 per accident or
occurrence. These subsidiaries have excess coverage on a claims first-
made basis beyond the deductible levels. The subsidiaries of the
Company are retaining losses up to the deductible amounts accrued on
the basis of estimates of liability for claims incurred and claims
incurred but not reported.
Other income - net
Other income - net consisted of the following:
Years ended December 31, 2003 2002 2001
(In thousands)
Interest and dividend income $ 6,722 $ 8,160 $ 5,734
Earnings from equity method
investments (Note 2) 5,968 1,341 154
Other income 9,517 4,071 20,933
Total other income - net $22,207 $13,572 $26,821
Income taxes
The Company provides deferred federal and state income taxes on all
temporary differences between the book and tax basis of the Company's
assets and liabilities. Excess deferred income tax balances associated
with the Company's rate-regulated activities resulting from the
Company's adoption of SFAS No. 109, "Accounting for Income Taxes," have
been recorded as a regulatory liability and are included in other
liabilities. These regulatory liabilities are expected to be reflected
as a reduction in future rates charged to customers in accordance with
applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax
credits and amortizes the credits on electric and natural gas
distribution plant over various periods that conform to the ratemaking
treatment prescribed by the applicable state public service
commissions.
Foreign currency translation adjustment
The functional currency of the Company's investment in a 220-megawatt
natural gas-fired electric generating facility in Brazil, as further
discussed in Note 2, is the Brazilian real. Translation from the
Brazilian real to the U.S. dollar for assets and liabilities is
performed using the exchange rate in effect at the balance sheet date.
Revenues and expenses have been translated using the weighted average
exchange rate for each month prevailing during the period reported.
Adjustments resulting from such translations are reported as a separate
component of other comprehensive income (loss) in common stockholders'
equity.
Transaction gains and losses resulting from the effect of exchange rate
changes on transactions denominated in a currency other than the
functional currency of the reporting entity are recorded in income.
Common stock split
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 Note 11.
Earnings per common share
Basic earnings per common share were computed by dividing earnings on
common stock by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share were
computed by dividing earnings on common stock by the total of the
weighted average number of shares of common stock outstanding during
the year, plus the effect of outstanding stock options, restricted
stock grants and performance share awards. For the years ended
December 31, 2003, 2002 and 2001, 209,805 shares, 3,674,925 shares and
225,945 shares, respectively, with an average exercise price of $24.56,
$20.08 and $24.57, respectively, attributable to the exercise of
outstanding options, were excluded from the calculation of diluted
earnings per share because their effect was antidilutive. For the
years ended December 31, 2003, 2002 and 2001, no adjustments were made
to reported earnings in the computation of earnings per share. Common
stock outstanding includes issued shares less shares held in treasury.
Stock-based compensation
The Company has stock option plans for directors, key employees and
employees. In 2003, the Company adopted the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation,"
and began expensing the fair market value of stock options for all
awards granted on or after January 1, 2003. Compensation expense
recognized for awards granted on or after January 1, 2003, for the year
ended December 31, 2003, was $41,000 (after tax).
As permitted by SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of SFAS
No. 123," the Company accounts for stock options granted prior to
January 1, 2003, under APB Opinion No. 25, "Accounting for Stock Issued
to Employees." No compensation expense has been recognized for stock
options granted prior to January 1, 2003, as the options granted had an
exercise price equal to the market value of the underlying common stock
on the date of the grant.
Since the Company adopted SFAS No. 123 effective January 1, 2003, for
newly granted options only, the following table illustrates the effect
on earnings and earnings per common share for the years ended
December 31, 2003, 2002 and 2001, as if the Company had applied SFAS
No. 123 and recognized compensation expense for all outstanding and
unvested stock options based on the fair value at the date of grant:
2003 2002 2001
(In thousands, except per share amounts)
Earnings on common stock, as
reported $174,607 $147,688 $155,087
Stock-based compensation expense
included in reported earnings,
net of related tax effects 41 --- ---
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (2,139) (2,862) (3,799)
Pro forma earnings on common stock $172,509 $144,826 $151,288
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect
of accounting change $ 1.64 $ 1.39 $ 1.54
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share -- basic $ 1.57 $ 1.39 $ 1.54
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect
of accounting change $ 1.62 $ 1.36 $ 1.50
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share -- basic $ 1.55 $ 1.36 $ 1.50
Earnings per common share -- diluted
-- as reported:
Earnings before cumulative effect
of accounting change $ 1.62 $ 1.38 $ 1.52
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share --
diluted $ 1.55 $ 1.38 $ 1.52
Earnings per common share -- diluted
-- pro forma:
Earnings before cumulative effect
of accounting change $ 1.60 $ 1.36 $ 1.49
Cumulative effect of accounting
change (.07) --- ---
Earnings per common share --
diluted $ 1.53 $ 1.36 $ 1.49
For more information on the Company's stock-based compensation, see
Note 12.
Use of estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
the Company to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Estimates are used for items such as impairment testing of long-lived
assets, goodwill and natural gas and oil properties; fair values of
acquired assets and liabilities under the purchase method of
accounting; natural gas and oil reserves; property depreciable lives;
tax provisions; uncollectible accounts; environmental and other loss
contingencies; accumulated provision for revenues subject to refund;
costs on construction contracts; unbilled revenues; actuarially
determined benefit costs; asset retirement obligations; the valuation
of stock-based compensation; and the fair value of derivative
instruments, including the fair value of an embedded derivative in a
power purchase agreement related to an equity method investment in
Brazil, as discussed in Note 2. As additional information becomes
available, or actual amounts are determinable, the recorded estimates
are revised. Consequently, operating results can be affected by
revisions to prior accounting estimates.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 2003 2002 2001
(In thousands)
Interest, net of amount capitalized $47,474 $37,788 $42,267
Income taxes $31,737 $60,988 $75,284
Reclassifications
The Consolidated Statements of Income have been reclassified to include
additional disclosures relating to the components comprising operating
revenues and operation and maintenance expense.
Certain other reclassifications have been made in the financial
statements for prior years to conform to the current presentation.
Such reclassifications had no effect on net income or stockholders'
equity as previously reported.
New accounting standards
The Company has stock option plans for directors, key employees and
employees. In 2003, the Company adopted the fair value recognition
provisions of SFAS No. 123, and began expensing the fair market value
of stock options for all awards granted on or after January 1, 2003.
For a discussion of the effect of the adoption of the fair value
recognition provisions of SFAS No. 123 on earnings and earnings per
share, see stock-based compensation in Note 1.
In June 2001, the Financial Accounting Standards Board (FASB) approved
SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No.
143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity capitalizes a cost
by increasing the carrying amount of the related long-lived asset.
Over time, the liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either
settles the obligation for the recorded amount or incurs a gain or
loss. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002. For more information on the adoption of SFAS No. 143,
see Note 9.
In April 2002, the FASB approved SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." FASB No. 4 required all gains or losses from
extinguishment of debt to be classified as extraordinary items net of
income taxes. SFAS No. 145 requires that gains and losses from
extinguishment of debt be evaluated under the provisions of APB Opinion
No. 30, and be classified as ordinary items unless they are unusual or
infrequent or meet the specific criteria for treatment as an
extraordinary item. SFAS No. 145 is effective for fiscal years
beginning after May 15, 2002. The adoption of SFAS No. 145 did not
have a material effect on the Company's financial position or results
of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others" (FIN 45).
FIN 45 clarifies the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under
certain guarantees that it has issued. FIN 45 also requires a
guarantor to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing certain
types of guarantees. Certain types of guarantees are not subject to
the initial recognition and measurement provisions of FIN 45 but are
subject to its disclosure requirements. The initial recognition and
initial measurement provisions of FIN 45 are applicable on a
prospective basis to guarantees issued or modified after December 31,
2002, regardless of the guarantor's fiscal year-end. The guarantor's
previous accounting for guarantees issued prior to the date of the
initial application of FIN 45 is not required to be revised or
restated. The disclosure requirements in FIN 45 are effective for
financial statements of interim or annual periods ended after December
15, 2002. The Company is applying the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or modified after
December 31, 2002. For more information on the Company's guarantees
and the disclosure requirements of FIN 45, as applicable to the
Company, see Note 19.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149
provides clarification on the financial accounting and reporting of
derivative instruments, including certain derivative instruments
embedded in other contracts, and hedging activities; and requires
contracts with similar characteristics to be accounted for on a
comparable basis. SFAS No. 149 is generally effective for contracts
entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of SFAS No.
149 did not have a material effect on the Company's financial position
or results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and
Equity." SFAS No. 150 establishes standards for how an issuer
classifies and measures certain financial instruments with
characteristics of both liabilities and equity. It requires that an
issuer classify a financial instrument that is within the scope of SFAS
No. 150 as a liability (or an asset in some circumstances). SFAS No.
150 is effective for financial instruments entered into or modified
after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003. The Company will
apply SFAS No. 150 to any financial instruments entered into or
modified after May 31, 2003. Beginning in 2003, the Company reported
its preferred stock subject to mandatory redemption as a liability in
accordance with SFAS No. 150. The transition to SFAS No. 150 did not
have a material effect on the Company's financial position or results
of operations.
In December 2003, the FASB issued FASB Interpretation No. 46 (revised
2003), "Consolidation of Variable Interest Entities" (FIN 46
(revised)), which revised FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46). FIN 46 (revised) clarifies the
application of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements," to certain entities in which equity investors do
not have the characteristics of a controlling financial interest or do
not have sufficient equity at risk for the entity to finance its
activities without additional subordinated support. An enterprise
shall consolidate a variable interest entity if that enterprise is the
primary beneficiary. An enterprise is considered the primary
beneficiary if it has a variable interest that will absorb a majority
of the entity's expected losses, receive a majority of the entity's
expected residual returns or both.
FIN 46 (revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period that ends
after March 15, 2004. However, an entity that applied FIN 46 to an
entity prior to the effective date of FIN 46 (revised) shall either
continue to apply FIN 46 until the effective date of FIN 46 (revised)
or apply FIN 46 (revised) at an earlier date.
The Company had evaluated the provisions of FIN 46 and determined that
MPX is a variable interest entity. MPX was formed in August 2001, as a
result of MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned
Brazilian subsidiary of the Company, entering into a joint venture
agreement with a Brazilian firm. MDU Brasil has a 49 percent interest
in MPX. Although the Company has determined that MPX is a variable
interest entity, MDU Brasil is not considered the primary beneficiary
of MPX because MDU Brasil does not absorb a majority of MPX's expected
losses, receive a majority of MPX's expected residual returns or both.
Therefore, MDU Brasil does not have a controlling financial interest in
MPX and is not required to consolidate MPX in its financial statements.
MPX is being accounted for under the equity method of accounting. For
more information on this equity method investment, see Note 2. The
adoption of FIN 46 did not have an effect on the Company's financial
position or results of operations. The Company will continue to apply
FIN 46 until the effective date of FIN 46 (revised).
In December 2003, the FASB issued SFAS No. 132 (revised 2003),
"Employers' Disclosures about Pension and Other Postretirement
Benefits." SFAS No. 132 (revised 2003) retains the disclosure
requirements contained in SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits," and requires additional
disclosures about the assets, obligations, cash flows and net periodic
benefit cost of defined benefit pension plans and other postretirement
benefit plans. SFAS No. 132 (revised 2003) is effective for financial
statements with fiscal years ending after December 15, 2003. The
interim-period disclosures required by SFAS No. 132 (revised 2003) are
effective for interim periods beginning after December 15, 2003. The
Company applied SFAS No. 132 (revised 2003) to its consolidated
financial statements issued after December 15, 2003. For more
information on the Company's pension and other postretirement benefits,
see Note 16.
In January 2004, the FASB issued FASB Staff Position No. FAS 106-1,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003." FASB
Staff Position No. FAS 106-1 permits a sponsor of a postretirement
health care plan that provides a prescription drug benefit to make a
one-time election to defer accounting for the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (2003
Medicare Act). SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other than Pension," requires enacted changes in relevant laws
to be considered in current period measurements of postretirement
benefit costs and accumulated postretirement benefit obligation. The
Company provides prescription drug benefits to certain eligible
employees and has elected the one-time deferral of accounting for the
effects of the 2003 Medicare Act. These consolidated financial
statements and accompanying notes do not reflect the effects of the
2003 Medicare Act on the postretirement benefit plans. The Company
intends to analyze the 2003 Medicare Act, along with the authoritative
guidance, when issued, to determine if its benefit plans need to be
amended and how to record the effects of the 2003 Medicare Act.
Specific guidance on the accounting for the federal subsidy provided by
the 2003 Medicare Act is pending and that guidance, when issued, could
require the Company to change previously reported postretirement
benefit information. For more information on the Company's
postretirement benefits, see Note 16.
Comprehensive income
Comprehensive income is the sum of net income as reported and other
comprehensive income (loss). The Company's other comprehensive income
(loss) resulted from gains and losses on derivative instruments
qualifying as hedges, minimum pension liability adjustments and foreign
currency translation adjustments.
The components of other comprehensive income (loss), and their related
tax effects for the years ended December 31, 2003, 2002 and 2001, were
as follows:
2003 2002 2001
(In thousands)
Other comprehensive income (loss):
Net unrealized gain (loss) on
derivative instruments
qualifying as hedges:
Unrealized loss on derivative
instruments at January 1,
2001, due to cumulative
effect of a change in
accounting principle,
net of tax of $3,970 in 2001 $ --- $ --- $(6,080)
Net unrealized gain (loss)
on derivative instruments
arising during the period,
net of tax of $2,132,
$2,903 and $1,448 in 2003,
2002 and 2001, respectively (3,335) (4,541) 2,218
Less: Reclassification adjustment
for gain (loss) on derivative
instruments included in
net income, net of tax of $2,903,
$1,448 and $3,970 in 2003, 2002
and 2001, respectively (4,541) 2,218 (6,080)
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges 1,206 (6,759) 2,218
Minimum pension liability
adjustment, net of tax of $38
and $2,876 in 2003 and 2002,
respectively 21 (4,464) ---
Foreign currency translation
adjustment 1,048 (799) ---
Total other comprehensive income
(loss) $ 2,275 $(12,022) $ 2,218
The after-tax components of accumulated other comprehensive income
(loss) as of December 31, 2003, 2002 and 2001, were as follows:
Net
Unrealized
Gain (Loss) on Total
Derivative Minimum Foreign Accumulated
Instruments Pension Currency Other
Qualifying Liability Translation Comprehensive
as Hedges Adjustment Adjustment Income (Loss)
(In thousands)
Balance at December 31, 2001 $ 2,218 $ --- $ --- $ 2,218
Balance at December 31, 2002 $(4,541) $(4,464) $ (799) $(9,804)
Balance at December 31, 2003 $(3,335) $(4,443) $ 249 $(7,529)
NOTE 2
Equity Method Investments
The Company has a number of equity method investments, including MPX,
which was formed in August 2001 when MDU Brasil entered into a joint
venture agreement with a Brazilian firm. MDU Brasil has a 49 percent
interest in MPX, which is being accounted for under the equity method
of accounting, as discussed in Note 1. 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.
At December 31, 2003, MPX has assets of approximately $109.6 million
and long-term debt of approximately $86.8 million, including a loan of
$20.0 million from Centennial Energy Resources International Inc, an
indirect wholly owned subsidiary of the Company. 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. The functional
currency for the Brazil Generating Facility is the Brazilian real. The
power purchase agreement with Petrobras contains an embedded
derivative, which derives its value from an annual adjustment factor,
which largely indexes the contract capacity payments to the U.S.
dollar. For the year ended December 31, 2003, the Company's 49 percent
share of the loss from the change in the fair value of the embedded
derivative in the power purchase agreement was $11.3 million (after
tax). For the year ended December 31, 2002, the Company's 49 percent
share of the gain from the change in the fair value of the embedded
derivative in the power purchase agreement was $13.6 million (after
tax). The Company's 49 percent share of the foreign currency gain
resulting from the revaluation of the Brazilian real was $2.8 million
(after tax) for the year ended December 31, 2003. The Company's 49
percent share of the foreign currency loss resulting from devaluation
of the Brazilian real was $9.4 million (after tax) for the year ended
December 31, 2002. The Company's investment in the Brazil Generating
Facility was approximately $25.2 million, including undistributed
earnings of $4.6 million at December 31, 2003. The Company's
investment in the Brazil Generating Facility was approximately
$27.8 million at December 31, 2002.
The Company's share of income from its equity method investments,
including MPX, was $6.0 million, $1.3 million and $154,000 for the
years ended December 31, 2003, 2002 and 2001, respectively, and was
included in other income - net.
NOTE 3
Goodwill and Other Intangible Assets
On January 1, 2002, in accordance with SFAS No. 142, "Goodwill and
Other Intangible Assets," the Company ceased amortization of its
goodwill recorded in business combinations that occurred on or before
June 30, 2001. The following information is presented as if SFAS No.
142 was adopted as of January 1, 2001. The reconciliation of
previously reported earnings and earnings per common share to the
amounts adjusted for the exclusion of goodwill amortization, net of the
related income tax effects, for the years ended December 31, 2003, 2002
and 2001, were as follows:
2003 2002 2001
(In thousands, except per share amounts)
Reported earnings on common stock $174,607 $147,688 $155,087
Add: Goodwill amortization, net of tax --- --- 3,649
Adjusted earnings on common stock $174,607 $147,688 $158,736
Reported earnings per common
share -- basic $ 1.57 $ 1.39 $ 1.54
Add: Goodwill amortization, net of tax --- --- .03
Adjusted earnings per common
share -- basic $ 1.57 $ 1.39 $ 1.57
Reported earnings per common
share -- diluted $ 1.55 $ 1.38 $ 1.52
Add: Goodwill amortization, net of tax --- --- .04
Adjusted earnings per common
share -- diluted $ 1.55 $ 1.38 $ 1.56
The changes in the carrying amount of goodwill for the year ended
December 31, 2003, were as follows:
Balance Goodwill Balance
as of Acquired as of
January 1, During December 31,
2003 the Year 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 117 62,604
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 8,311 120,198
Independent power production
and other 7,131 --- 7,131
Total $190,999 $8,428 $199,427
The changes in the carrying amount of goodwill for the year ended
December 31, 2002, were as follows:
Balance Goodwill Balance
as of Acquired as of
January 1, During December 31,
2002 the Year 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 578 62,487
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 9,135 111,887
Independent power production
and other --- 7,131 7,131
Total $173,997 $17,002 $190,999
Other intangible assets at December 31, 2003 and 2002, were as follows:
2003 2002
(In thousands)
Amortizable intangible assets:
Leasehold rights $186,419 $172,496
Accumulated amortization (11,779) (7,494)
174,640 165,002
Noncompete agreements 12,075 12,075
Accumulated amortization (9,690) (9,366)
2,385 2,709
Other 17,734 7,224
Accumulated amortization (2,265) (374)
15,469 6,850
Unamortizable intangible assets 960 1,603
Total $193,454 $176,164
Acquired aggregate reserves at our construction materials and mining
business are classified based on type of ownership. Owned mineral
rights are classified as property, plant and equipment, whereas leased
mineral rights are classified as leasehold rights in other intangible
assets, net.
The unamortizable intangible assets were recognized in accordance with
SFAS No. 87, "Employers' Accounting for Pensions," which requires that
if an additional minimum liability is recognized an equal amount shall
be recognized as an intangible asset, provided that the asset
recognized shall not exceed the amount of unrecognized prior service
cost. The unamortizable intangible asset will be eliminated or
adjusted as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for the years
ended December 31, 2003 and 2002, was $5.9 million and $3.4 million,
respectively. Estimated amortization expense for amortizable
intangible assets is $6.2 million in 2004, $6.4 million in 2005, $5.2
million in 2006, $5.2 million in 2007, $5.2 million in 2008 and $164.3
million thereafter.
SFAS No. 142 discontinues the practice of amortizing goodwill and
indefinite lived intangible assets and initiates an annual review for
impairment. Intangible assets with a determinable useful life will
continue to be amortized over that period. The amortization provisions
apply to goodwill and intangible assets acquired after June 30, 2001.
SFAS No. 141, "Business Combinations," and SFAS No. 142 clarify that
more assets should be distinguished and classified between tangible and
intangible. The Company did not change or reclassify contractual
mineral rights included in property, plant and equipment related to its
natural gas and oil production business upon adoption of SFAS No. 142.
The Company has included such mineral rights as part of property, plant
and equipment under the full-cost method of accounting for natural gas
and oil properties. An issue has arisen within the natural gas and oil
industry as to whether contractual mineral rights under SFAS No. 142
should be classified as intangible rather than as part of property,
plant and equipment. This accounting matter is anticipated to be
addressed by the FASB's Emerging Issues Task Force. The resolution of
this matter may result in certain reclassifications of amounts in the
Consolidated Balance Sheets, as well as changes to Notes to
Consolidated Financial Statements in the future. The applicable
provisions of SFAS No. 141 and SFAS No. 142 only affect the balance
sheet and associated footnote disclosure, so any reclassifications that
might be required in the future will not affect the Company's cash
flows or results of operations. The Company believes that the
resolution of this matter will not have a material effect on the
Company's financial position because the mineral rights acquired by its
natural gas and oil production business after the June 30, 2001,
effective date of SFAS No. 142 were not material.
NOTE 4
Regulatory Assets and Liabilities
The following table summarizes the individual components of unamortized
regulatory assets and liabilities as of December 31:
2003 2002
(In thousands)
Regulatory assets:
Deferred income taxes $ 29,850 $ 27,378
Natural gas costs recoverable
through rate adjustments 10,519 ---
Long-term debt refinancing costs 4,519 5,627
Plant costs 2,697 2,330
Postretirement benefit costs 562 616
Other 7,159 4,788
Total regulatory assets 55,306 40,739
Regulatory liabilities:
Plant removal and decommissioning costs 76,176 68,551
Reserves for regulatory matters 11,970 9,856
Taxes refundable to customers 11,751 11,699
Deferred income taxes 10,663 5,491
Natural gas costs refundable
through rate adjustments --- 2,396
Other 658 2,779
Total regulatory liabilities 111,218 100,772
Net regulatory position $ (55,912) $ (60,033)
As of December 31, 2003, substantially all of the Company's regulatory
assets, other than certain deferred income taxes, were being reflected
in rates charged to customers and are being recovered over the next one
to 19 years.
If, for any reason, the Company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 5
Derivative Instruments
The Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, on January 1, 2001.
SFAS No. 133 establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative instrument's fair value
be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows
derivative gains and losses to offset the related results on the hedged
item in the income statement and requires that a company must formally
document, designate and assess the effectiveness of transactions that
receive hedge accounting treatment.
SFAS No. 133 requires that as of the date of initial adoption, the
difference between the fair market value of derivative instruments
recorded on the balance sheet and the previous carrying amount of those
derivative instruments be reported in net income or other comprehensive
income (loss), as appropriate, as the cumulative effect of a change in
accounting principle in accordance with APB Opinion No. 20, "Accounting
Changes." On January 1, 2001, the Company reported a net-of-tax
cumulative-effect adjustment of $6.1 million in accumulated other
comprehensive loss to recognize at fair value all derivative
instruments that are designated as cash flow hedging instruments, which
the Company reclassified into earnings during the year ended
December 31, 2001. The transition to SFAS No. 133 did not have an
effect on the Company's net income at adoption.
In the event a derivative instrument being accounted for as a cash flow
hedge does not qualify for hedge accounting because it is no longer
highly effective in offsetting changes in cash flows of a hedged item;
or if the derivative instrument expires or is sold, terminated or
exercised; or if management determines that designation of the
derivative instrument as a hedge instrument is no longer appropriate,
hedge accounting will be discontinued, and the derivative instrument
would continue to be carried at fair value with changes in its fair
value recognized in earnings. In these circumstances, the net gain or
loss at the time of discontinuance of hedge accounting would remain in
accumulated other comprehensive income (loss) until the period or
periods during which the hedged forecasted transaction affects
earnings, at which time the net gain or loss would be reclassified into
earnings. In the event a cash flow hedge is discontinued because it is
unlikely that a forecasted transaction will occur, the derivative
instrument would continue to be carried on the balance sheet at its
fair value, and gains and losses that had accumulated in other
comprehensive income (loss) would be recognized immediately in
earnings. In the event of a sale, termination or extinguishment of a
foreign currency derivative, the resulting gain or loss would be
recognized immediately in earnings. The Company's policy requires
approval to terminate a derivative instrument prior to its original
maturity.
As of December 31, 2003, an indirect wholly owned subsidiary of the
Company held derivative instruments designated as cash flow hedging
instruments.
Hedging activities
The subsidiary of the Company utilizes natural gas and oil price swap
and collar agreements to manage a portion of the market risk associated
with fluctuations in the price of natural gas and oil on the
subsidiary's forecasted sales of natural gas and oil production. Each
of the natural gas and oil price swap and collar agreements was
designated as a hedge of the forecasted sale of natural gas and oil
production.
On an ongoing basis, the balance sheet is adjusted to reflect the
current fair market value of the swap and collar agreements. The
related gains or losses on these agreements are recorded in common
stockholders' equity as a component of other comprehensive income
(loss). At the date the underlying transaction occurs, the amounts
accumulated in other comprehensive income (loss) are reported in the
Consolidated Statements of Income. To the extent that the hedges are
not effective, the ineffective portion of the changes in fair market
value is recorded directly in earnings.
For the years ended December 31, 2003, 2002 and 2001, the subsidiary of
the Company recognized the ineffectiveness of cash flow hedges, which
is included in operating revenues for the natural gas and oil price
swap and collar agreements. For the years ended December 31, 2003,
2002 and 2001, the amount of hedge ineffectiveness recognized was
immaterial. For the years ended December 31, 2003, 2002 and 2001, the
subsidiary did not exclude any components of the derivative
instruments' gain or loss from the assessment of hedge effectiveness
and there were no reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are reclassified from
accumulated other comprehensive income (loss) to current-period
earnings are included in the line item in which the hedged item is
recorded. As of December 31, 2003, the maximum term of the
subsidiary's swap and collar agreements, in which the subsidiary of the
Company is hedging its exposure to the variability in future cash flows
for forecasted transactions, is 12 months. The subsidiary of the
Company estimates that over the next 12 months net losses of
approximately $3.3 million will be reclassified from accumulated other
comprehensive income (loss) into earnings, subject to changes in
natural gas and oil market prices, as the hedged transactions affect
earnings.
Foreign currency derivative
MDU Brasil has a 49 percent equity investment in the Brazil Generating
Facility, which has a portion of its borrowings and payables
denominated in U.S. dollars. MDU Brasil has exposure to currency
exchange risk as a result of fluctuations in currency exchange rates
between the U.S. dollar and the Brazilian real. On August 12, 2002,
MDU Brasil entered into a foreign currency collar agreement for a
notional amount of $21.3 million with a fixed price floor of R$3.10 and
a fixed price ceiling of R$3.40 to manage a portion of its foreign
currency risk. The term of the collar agreement was from August 12,
2002, through February 3, 2003, and the collar agreement settled on
February 3, 2003. The foreign currency collar agreement was not
designated as a hedge and was recorded at fair value on the
Consolidated Balance Sheets. Gains or losses on this derivative
instrument were recorded in other income - net. The Company recorded a
gain of $39,000 (after tax) on the foreign currency collar agreement
for the year ended December 31, 2003, and a gain of $566,000 (after
tax) for the year ended December 31, 2002.
Energy marketing
The Company had entered into other derivative instruments that were not
designated as hedges in its energy marketing operations. In the third
quarter of 2001, the Company sold the vast majority of its energy
marketing operations. Net unrealized gains and losses on these
derivative instruments were not material for the year ended
December 31, 2001.
NOTE 6
Fair Value of Other Financial Instruments
The estimated fair value of the Company's long-term debt and preferred
stock subject to mandatory redemption is based on quoted market prices
of the same or similar issues. As discussed in Note 1, the Company,
upon adoption of SFAS No. 150 in 2003, began reporting its preferred
stock subject to mandatory redemption as a liability. The estimated
fair values of the Company's natural gas and oil price swap and collar
agreements were included in current liabilities at December 31, 2003
and 2002. The estimated fair value of the Company's foreign currency
collar agreement was included in current assets at December 31, 2002.
The estimated fair values of the Company's natural gas and oil price
swap and collar agreements and foreign currency collar agreement
reflect the estimated amounts the Company would receive or pay to
terminate the contracts at the reporting date based upon quoted market
prices of comparable contracts.
The estimated fair value of the Company's long-term debt, preferred
stock subject to mandatory redemption, natural gas and oil price swap
and collar agreements and foreign currency collar agreement at
December 31 was as follows:
2003 2002
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $967,096 $1,012,547 $841,641 $888,066
Preferred stock
subject to mandatory
redemption $ --- $ --- $ 1,300 $ 1,168
Natural gas and oil
price swap and
collar agreements $ (5,467) $ (5,467) $ (7,444) $ (7,444)
Foreign currency
collar agreement $ --- $ --- $ 903 $ 903
The carrying amounts of the Company's remaining financial instruments
included in current assets and current liabilities (excluding unsettled
derivative instruments) approximate their fair values because of their
short-term nature.
NOTE 7
Short-term Borrowings
MDU Resources Group, Inc.
At December 31, 2002, $8.0 million of MDU Resources Group, Inc. (MDU
Resources) commercial paper program borrowings were classified as short-
term borrowings. The commercial paper borrowings classified as short
term were supported by short-term bank lines of credit. There were no
amounts outstanding under the bank lines of credit at December 31,
2002. MDU Resources did not have any short-term bank lines of credit
at December 31, 2003. For more information on MDU Resources'
commercial paper program, see Note 8.
International operations
A subsidiary of the Company had a short-term credit agreement that
expired in 2003. Under this agreement $12.0 million was outstanding at
December 31, 2002.
NOTE 8
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 was as follows:
2003 2002
(In thousands)
First mortgage bonds and notes:
Pollution Control Refunding Revenue
Bonds, Series 1992,
6.65%, due June 1, 2022 $ 20,850 $ 20,850
Secured Medium-Term Notes,
Series A at a weighted
average rate of 7.59%, due on
dates ranging from October 1, 2004
to April 1, 2012 110,000 110,000
Senior Notes, 5.98%, due December 15, 2033 30,000 ---
Total first mortgage bonds and notes 160,850 130,850
Senior notes at a weighted
average rate of 6.24%, due on
dates ranging from October 30, 2004
to October 30, 2018 718,000 549,100
Commercial paper at a weighted average
rate of 1.12%, supported by revolving
credit agreements 72,500 151,900
Term credit agreements at a weighted
average rate of 5.14%, due on dates
ranging from July 15, 2004
to December 1, 2013 14,286 7,873
Pollution control note obligation,
6.20%, due March 1, 2004 1,500 2,000
Discount (40) (82)
Total long-term debt 967,096 841,641
Less current maturities 27,646 22,083
Net long-term debt $939,450 $819,558
The amounts of scheduled long-term debt maturities for the five years
and thereafter following December 31, 2003, aggregate $27.6 million in
2004; $70.9 million in 2005; $173.2 million in 2006; $105.8 million in
2007; $160.2 million in 2008 and $429.4 million thereafter.
Certain debt instruments of the Company and its subsidiaries, including
those discussed below, contain restrictive covenants, all of which the
Company and its subsidiaries were in compliance with at December 31,
2003.
MDU Resources Group, Inc.
MDU Resources has a revolving credit agreement with various banks
totaling $90 million at December 31, 2003. There were no amounts
outstanding under the credit agreement at December 31, 2003 and 2002.
The credit agreement supports MDU Resources' $75 million commercial
paper program. Under the MDU Resources' commercial paper program, $40
million was outstanding at December 31, 2003, which was classified as
long-term debt, and $58.0 million was outstanding at December 31, 2002,
of which $8.0 million was classified as short-term borrowings and $50.0
million was classified as long-term debt. As discussed in Note 7, the
commercial paper borrowings classified as short term were supported by
short-term bank lines of credit. The commercial paper borrowings
classified as long-term debt are intended to be refinanced on a long-
term basis through continued MDU Resources commercial paper borrowings
and as further supported by the credit agreement, which expires on
July 18, 2006.
In order to borrow under the MDU Resources credit agreement, MDU
Resources must be in compliance with the applicable covenants and
certain other conditions. The significant covenants include maximum
leverage ratios, minimum interest coverage ratio, limitation on sale of
assets and limitation on investments. MDU Resources was in compliance
with these covenants and met the required conditions at December 31,
2003.
There are no credit facilities that contain cross-default provisions
between MDU Resources and any of its subsidiaries.
MDU Resources' issuance of first mortgage debt is subject to certain
restrictions imposed under the terms and conditions of its Indenture of
Mortgage. Generally, those restrictions require MDU Resources to
pledge $1.43 of unfunded property to the trustee for each dollar of
indebtedness incurred under the Indenture and that annual earnings
(pretax and before interest charges), as defined in the Indenture,
equal at least two times its annualized first mortgage bond interest
costs. Under the more restrictive of the two tests, as of December 31,
2003, MDU Resources could have issued approximately $313 million of
additional first mortgage bonds.
Approximately $421.2 million of the Company's net electric and natural
gas distribution properties at December 31, 2003, 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 trustee, 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.
Centennial Energy Holdings, Inc.
Centennial Energy Holdings, Inc. (Centennial) has two revolving credit
agreements with various banks that support $275 million of Centennial's
$350 million commercial paper program. There were no outstanding
borrowings under the Centennial credit agreements at December 31, 2003
or 2002. Under the Centennial commercial paper program, $32.5 million
and $101.9 million were outstanding at December 31, 2003 and 2002,
respectively. The Centennial commercial paper borrowings are
classified as long-term debt as Centennial intends to refinance these
borrowings on a long-term basis through continued Centennial commercial
paper borrowings and as further supported by the Centennial credit
agreements. The Centennial credit agreements are for $137.5 million
each. One of these agreements expires on September 3, 2004, and allows
for subsequent borrowings up to a term of one year. The other
agreement expires on September 5, 2006. Centennial intends to
negotiate the extension or replacement of these agreements prior to
their maturities.
Centennial has an uncommitted long-term master shelf agreement that
allows for borrowings of up to $400 million. Under the terms of the
master shelf agreement, $384.0 million was outstanding at December 31,
2003, and $360.6 million was outstanding at December 31, 2002. The
amount outstanding under the uncommitted long-term master shelf
agreement is included in senior notes in the preceding long-term debt
table.
In order to borrow under Centennial's credit agreements and the
Centennial uncommitted long-term master shelf agreement, Centennial and
certain of its subsidiaries must be in compliance with the applicable
covenants and certain other conditions. The significant covenants
include maximum capitalization ratios, minimum interest coverage
ratios, minimum consolidated net worth, limitation on priority debt,
limitation on sale of assets and limitation on loans and investments.
Centennial and such subsidiaries were in compliance with these
covenants and met the required conditions at December 31, 2003.
Certain of Centennial's financing agreements contain cross-default
provisions. These provisions state that if Centennial or any
subsidiary of Centennial fails to make any payment with respect to any
indebtedness or contingent obligation, in excess of a specified amount,
under any agreement that causes such indebtedness to be due prior to
its stated maturity or the contingent obligation to become payable, the
applicable agreements will be in default. Certain of Centennial's
financing agreements and Centennial's practice limit the amount of
subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin Interstate Pipeline Company (Williston Basin), an
indirect wholly owned subsidiary of the Company, has an uncommitted
long-term master shelf agreement that allows for borrowings of up to
$100 million. Under the terms of the master shelf agreement, $55.0
million and $30.0 million was outstanding at December 31, 2003 and
2002, respectively.
In order to borrow under Williston Basin's uncommitted long-term master
shelf agreement, it must be in compliance with the applicable covenants
and certain other conditions. The significant covenants include
limitation on consolidated indebtedness, limitation on priority debt,
limitation on sale of assets and limitation on investments. Williston
Basin was in compliance with these covenants and met the required
conditions at December 31, 2003.
NOTE 9
Asset Retirement Obligations
The Company adopted SFAS No. 143 on January 1, 2003, as discussed in
Note 1. The Company recorded obligations related to the plugging and
abandonment of natural gas and oil wells, decommissioning of certain
electric generating facilities, reclamation of certain aggregate
properties and certain other obligations associated with leased
properties. Removal costs associated with certain natural gas
distribution, transmission, storage and gathering facilities have not
been recognized as these facilities have been determined to have
indeterminate useful lives.
Upon adoption of SFAS No. 143, the Company recorded an additional
discounted liability of $22.5 million and a regulatory asset of
$493,000, increased net property, plant and equipment by $9.6 million
and recognized a one-time cumulative effect charge of $7.6 million (net
of deferred income tax benefits of $4.8 million). The Company believes
that any expenses under SFAS No. 143 as they relate to regulated
operations will be recovered in rates over time and accordingly,
deferred such expenses as a regulatory asset upon adoption. The
Company will continue to defer those SFAS No. 143 expenses that it
believes will be recovered in rates over time. In addition to the
$22.5 million liability recorded upon the adoption of SFAS No. 143, the
Company had previously recorded a $7.5 million liability related to
retirement obligations.
A reconciliation of the Company's liability for the year ended
December 31 was as follows:
2003
(In thousands)
Balance at January 1, 2003 $29,997
Liabilities incurred 2,405
Liabilities acquired 1,803
Liabilities settled (1,555)
Accretion expense 1,906
Revisions in estimates 77
Balance at December 31, 2003 $34,633
This liability is included in other liabilities. If SFAS No. 143 had
been in effect during 2002 and 2001, the Company's liability would have
been approximately $30.0 million at December 31, 2002, and $27.0
million at December 31, 2001.
The fair value of assets that are legally restricted for purposes of
settling asset retirement obligations at December 31, 2003, was $5.1
million.
NOTE 10
Preferred Stocks
Preferred stocks at December 31 were as follows:
2003 2002
(Dollars in thousands)
Authorized:
Preferred --
500,000 shares, cumulative,
par value $100, issuable in series
Preferred stock A --
1,000,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Preference --
500,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Outstanding:
Subject to mandatory redemption --
Preferred --
5.10% Series - 13,000 shares in 2002 $ --- $ 1,300
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000
15,000 15,000
Total preferred stocks 15,000 16,300
Less sinking fund requirements --- 100
Net preferred stocks $15,000 $16,200
As discussed in Note 1, the Company upon adoption of SFAS No. 150 in
2003, began reporting its preferred stock subject to mandatory
redemption as a liability. Restatement of prior year information is
not permitted under SFAS No. 150.
The 4.50% Series and 4.70% Series preferred stocks outstanding are
subject to redemption, in whole or in part, at the option of the
Company with certain limitations on 30 days notice on any quarterly
dividend date at a redemption price, plus accrued dividends, of $105
and $102, respectively.
In the event of a voluntary or involuntary liquidation, all preferred
stock series holders are entitled to $100 per share, plus accrued
dividends.
The affirmative vote of two-thirds of a series of the Company's
outstanding preferred stock is necessary for amendments to the
Company's charter or by-laws that adversely affect that series;
creation of or increase in the amount of authorized stock ranking
senior to that series (or an affirmative majority vote where the
authorization relates to a new class of stock that ranks on parity with
such series); a voluntary liquidation or sale of substantially all of
the Company's assets; a merger or consolidation, with certain
exceptions; or the partial retirement of that series of preferred stock
when all dividends on that series of preferred stock have not been
paid. The consent of the holders of a particular series is not
required for such corporate actions if the equivalent vote of all
outstanding series of preferred stock voting together has consented to
the given action and no particular series is affected differently than
any other series.
Subject to the foregoing, the holders of common stock exclusively
possess all voting power. However, if cumulative dividends on
preferred stock are in arrears, in whole or in part, for one year the
holders of preferred stock would obtain the right to one vote per share
until all dividends in arrears have been paid and current dividends
have been declared and set aside.
NOTE 11
Common Stock
On August 14, 2003, the Company's Board of Directors approved a three-
for-two common stock split to be effected in the form of a 50 percent
common stock dividend. The additional shares of common stock were
distributed on October 29, 2003, to common stockholders of record on
October 10, 2003. Common stock information appearing in the
accompanying consolidated financial statements has been restated to
give retroactive effect to the stock split. Additionally, preference
share purchase rights have been appropriately adjusted to reflect the
effects of the split.
At the Annual Meeting of Stockholders held on April 23, 2002, the
Company's common stockholders approved an amendment to the Certificate
of Incorporation increasing the authorized number of common shares from
150 million shares to 250 million shares with a par value of $1.00 per
share.
The Company's Dividend Reinvestment and Direct Stock Purchase Plan
(Stock Purchase Plan) provides interested investors the opportunity to
make optional cash investments and to reinvest all or a percentage of
their cash dividends in shares of the Company's common stock. The
Company's 401(k) Retirement Plan (K-Plan) is partially funded with the
Company's common stock. Since January 1, 2001, the Stock Purchase Plan
and K-Plan, with respect to Company stock, have been funded by the
purchase of shares of common stock on the open market. At December 31,
2003, there were 12.1 million shares of common stock reserved for
original issuance under the Stock Purchase Plan and K-Plan.
In November 1998, the Company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) for each outstanding share of the Company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for two-thirds of one one-thousandth of a share of
Series B Preference Stock of the Company, without par value, at an
exercise price of $125, subject to certain adjustments. The rights are
currently not exercisable and will be exercisable only if a person or
group (acquiring person) either acquires ownership of 15 percent or
more of the Company's common stock or commences a tender or exchange
offer that would result in ownership of 15 percent or more. In the
event the Company is acquired in a merger or other business combination
transaction or 50 percent or more of its consolidated assets or
earnings power are sold, each right entitles the holder to receive,
upon the exercise thereof at the then current exercise price of the
right multiplied by the number of two-thirds of one one-thousandth of a
Series B Preference Stock for which a right is then exercisable, in
accordance with the terms of the rights agreement, such number of
shares of common stock of the acquiring person having a market value of
twice the then current exercise price of the right. The rights, which
expire on December 31, 2008, are redeemable in whole, but not in part,
for a price of $.00667 per right, at the Company's option at any time
until any acquiring person has acquired 15 percent or more of the
Company's common stock.
NOTE 12
Stock-based Compensation
The Company has stock option plans for directors, key employees and
employees. In 2003, the Company adopted the fair value recognition
provisions of SFAS No. 123 and began expensing the fair market value of
stock options for all awards granted on or after January 1, 2003. As
permitted by SFAS No. 148, the Company accounts for stock options
granted prior to January 1, 2003, under APB Opinion No. 25.
For a discussion of the adoption of SFAS No. 123 and the effect on
earnings and earnings per common share for the years ended December 31,
2003, 2002 and 2001, as if the Company had applied SFAS No. 123, and
recognized compensation expense for all outstanding and unvested stock
options based on the fair value at the date of grant, see Note 1.
Options granted to key employees automatically vest after nine years,
but the plan provides for accelerated vesting based on the attainment
of certain performance goals or upon a change in control of the
Company, and expire 10 years after the date of grant. Options granted
to directors and employees vest at date of grant and three years after
date of grant, respectively, and expire 10 years after the date of
grant.
A summary of the status of the stock option plans at December 31, 2003,
2002 and 2001, and changes during the years then ended was as follows:
2003 2002 2001
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 4,861,268 $18.58 5,208,311 $18.60 1,837,439 $13.74
Granted 27,015 17.29 160,605 19.15 4,039,680 20.09
Forfeited (188,486) 20.05 (453,840) 19.77 (111,423) 18.16
Exercised (517,341) 13.88 (53,808) 12.20 (557,385) 13.49
Balance at end
of year 4,182,456 19.09 4,861,268 18.58 5,208,311 18.60
Exercisable at
end of year 611,404 $15.06 1,135,050 $14.56 1,155,213 $14.27
Summarized information about stock options outstanding and exercisable
as of December 31, 2003, was as follows:
Options Outstanding Options Exercisable
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercisable Prices Outstanding in Years Price Exercisable Price
$ 8.22 - 13.00 23,451 2.5 $ 9.77 23,451 $ 9.77
13.01 - 17.00 647,085 4.3 14.13 511,453 14.15
17.01 - 21.00 3,302,115 7.2 19.77 36,000 19.54
21.01 - 25.70 209,805 7.2 24.56 40,500 25.70
Balance at end of year 4,182,456 6.7 19.09 611,404 15.06
The fair value of each option is estimated on the date of grant using
the Black-Scholes option pricing model. The weighted average fair
value of the options granted and the assumptions used to estimate the
fair value of options were as follows:
2003 2002 2001
Weighted average fair value of
options at grant date $4.67 $5.38 $4.92
Weighted average risk-free
interest rate 3.91% 5.14% 5.19%
Weighted average expected
price volatility 32.28% 30.80% 26.05%
Weighted average expected
dividend yield 3.43% 3.43% 3.53%
Expected life in years 7 7 7
In addition, the Company granted restricted stock awards under a long-
term incentive plan and deferred compensation agreements totaling
525,588 shares in 2001. The restricted stock awards granted vest to
the participants at various times ranging from two years to nine years
from date of issuance, but certain grants may vest early based upon the
attainment of certain performance goals or upon a change in control of
the Company. The weighted average grant date fair value of the
restricted stock grant in 2001 was $21.03. The Company also has
granted stock awards totaling 31,855 shares, 21,390 shares and 19,009
shares in 2003, 2002 and 2001, respectively, under a nonemployee
director stock compensation plan. The weighted average grant date fair
value of the stock grants was $21.40, $19.20 and $20.09, in 2003, 2002
and 2001, respectively. Nonemployee directors may receive shares of
common stock instead of cash in payment for directors' fees under the
nonemployee director stock compensation plan. Compensation expense
recognized for restricted stock grants and stock grants was $4.8
million, $5.2 million and $4.9 million in 2003, 2002 and 2001,
respectively.
In 2003, key employees of the Company were awarded performance share
awards. Entitlement to performance shares is based on the Company's
total shareholder return over designated performance periods as
measured against a selected peer group. Target grants of performance
shares were made for the following performance periods:
Target Grant
Grant Date Performance Period of Shares
February 2003 2003-2004 57,655
February 2003 2003-2005 57,655
Participants may earn additional performance shares if the Company's
total shareholder return exceeds that of the selected peer group. The
final value of the performance units may vary according to the number
of shares of Company stock that are ultimately granted based on the
performance criteria. Compensation expense recognized for the
performance share awards for the year ended December 31, 2003, was
$879,000.
The Company is authorized to grant options, restricted stock and stock
for up to 14.3 million shares of common stock and has granted options,
restricted stock and stock on 6.2 million shares through December 31,
2003.
NOTE 13
Income Taxes
Income tax expense for the years ended December 31 was as follows:
2003 2002 2001
(In thousands)
Current:
Federal $26,313 $46,389 $66,211
State 7,408 9,082 11,160
Foreign 264 --- (44)
33,985 55,471 77,327
Deferred:
Income taxes --
Federal 55,660 26,373 16,972
State 9,861 4,632 4,773
Foreign (338) 338 ---
Investment tax credit (596) (584) (731)
64,587 30,759 21,014
Total income tax expense $98,572 $86,230 $98,341
Components of deferred tax assets and deferred tax liabilities
recognized at December 31 were as follows:
2003 2002
(In thousands)
Deferred tax assets:
Regulatory matters $ 37,072 $ 34,792
Accrued pension costs 12,122 12,112
Deferred compensation 9,090 6,395
Asset retirement obligations 7,017 263
Bad debts 3,188 2,798
Deferred investment tax credit 954 1,185
Other 21,269 18,444
Total deferred tax assets 90,712 75,989
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 406,589 354,842
Basis differences on natural gas
and oil producing properties 105,826 70,464
Regulatory matters 10,663 5,491
Other 9,309 10,412
Total deferred tax liabilities 532,387 441,209
Net deferred income tax liability $(441,675) $(365,220)
As of December 31, 2003 and 2002, no valuation allowance has been
recorded associated with the above deferred tax assets.
The following table reconciles the change in the net deferred income
tax liability from December 31, 2002, to December 31, 2003, to deferred
income tax expense:
2003
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 76,455
Deferred taxes associated with acquisitions (15,056)
Deferred taxes associated with the cumulative effect of
accounting change 4,821
Deferred taxes associated with other comprehensive income (809)
Other (824)
Deferred income tax expense for the period $ 64,587
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for this difference were as follows:
Years ended December 31, 2003 2002 2001
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $98,520 35.0 $82,136 35.0 $88,966 35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit 11,857 4.2 10,279 4.4 11,311 4.5
Investment tax credit
amortization (596) (.2) (584) (.3) (731) (.3)
Depletion allowance (3,117) (1.1) (2,200) (.9) (1,820) (.7)
Renewable electricity
production credit (3,395) (1.2) --- --- --- ---
Other items (4,697) (1.7) (3,401) (1.5) 615 .2
Total income tax expense $98,572 35.0 $86,230 36.7 $98,341 38.7
The Company considers earnings from its foreign equity method
investment in a natural gas-fired electric generating facility in
Brazil to be reinvested indefinitely outside of the United States and,
accordingly, no U.S. deferred income taxes are recorded with respect to
such earnings. Should the earnings be remitted as dividends, the
Company may be subject to additional U.S. taxes, net of allowable
foreign tax credits.
NOTE 14
Business Segment Data
The Company's reportable segments are those that are based on the
Company's method of internal reporting, which generally segregates the
strategic business units due to differences in products, services and
regulation. The Company 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 vast majority of the Company's operations are located within the
United States. The Company also has investments in foreign countries,
which largely consist of an investment in a natural gas-fired electric
generating facility in Brazil, as discussed in Note 2. The electric
segment generates, transmits and distributes electricity, and the
natural gas distribution segment distributes natural gas. These
operations also supply related value-added products and services in the
northern Great Plains. The utility services segment specializes in
electrical line construction, pipeline construction, inside electrical
wiring and cabling and the manufacture and distribution of specialty
equipment. 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. The construction materials and mining segment 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. The 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. Electric capacity and energy produced at these facilities
are primarily sold under long-term contracts to nonaffiliated entities.
These operations also include investments in opportunities that are
not directly being pursued by the Company's other businesses.
In 2001, the Company sold its coal operations to Westmoreland Coal
Company for $28.2 million in cash and recorded a gain of $10.3 million
($6.2 million after tax) included in other income - net. The sale of
the Company's coal operations 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 sale 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.
The information below follows the same accounting policies as described
in the Summary of Significant Accounting Policies. Information on the
Company's businesses as of December 31 and for the years then ended was
as follows:
2003 2002 2001
(In thousands)
External operating revenues:
Electric $ 178,562 $ 162,616 $ 168,837
Natural gas distribution 274,608 186,569 255,389
Pipeline and energy services 187,892 110,224 479,108
641,062 459,409 903,334
Utility services 434,177 458,660 364,746
Natural gas and oil production 140,281 148,158 148,653
Construction materials and mining 1,104,408 962,312 806,899(a)
Independent power production
and other 32,261 2,998 ---
1,711,127 1,572,128 1,320,298
Total external operating revenues $2,352,189 $2,031,537 $2,223,632
Intersegment operating revenues:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- --- 4
Pipeline and energy services 64,300 55,034 52,006
Natural gas and oil production 124,077 55,437 61,178
Construction materials and mining --- --- ---
Independent power production
and other 2,728 3,778 ---
Intersegment eliminations (191,105) (114,249) (113,188)
Total intersegment
operating revenues $ --- $ --- $ ---
Depreciation, depletion and
amortization:
Electric $ 20,150 $ 19,537 $ 19,488
Natural gas distribution 10,044 9,940 9,337
Utility services 10,353 9,871 8,395
Pipeline and energy services 15,016 14,846 14,341
Natural gas and oil production 61,019 48,714 41,690
Construction materials and mining 63,601 54,334 46,666
Independent power production
and other 8,154 719 ---
Total depreciation, depletion
and amortization $ 188,337 $ 157,961 $ 139,917
Interest expense:
Electric $ 8,013 $ 7,621 $ 8,531
Natural gas distribution 3,936 4,364 3,727
Utility services 3,668 3,568 3,807
Pipeline and energy services 7,952 7,670 9,136
Natural gas and oil production 4,767 2,464 1,359
Construction materials and mining 18,747 18,422 19,339
Independent power production
and other 5,865 1,122 ---
Intersegment eliminations (154) (216) ---
Total interest expense $ 52,794 $ 45,015 $ 45,899
Income taxes:
Electric $ 9,862 $ 9,501 $ 10,511
Natural gas distribution 1,823 (1,325) 1,067
Utility services 3,905 4,781 9,131
Pipeline and energy services 11,188 12,462 11,633
Natural gas and oil production 42,993 30,604 40,486
Construction materials and mining 28,168 29,415 25,513
Independent power production
and other 633 792 ---
Total income taxes $ 98,572 $ 86,230 $ 98,341
Cumulative effect of accounting
change (Note 9):
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- --- ---
Pipeline and energy services --- --- ---
Natural gas and oil production (7,740) --- ---
Construction materials and mining 151 --- ---
Independent power production
and other --- --- ---
Total cumulative effect of
accounting change $ (7,589) $ --- $ ---
Earnings on common stock:
Electric $ 16,950 $ 15,780 $ 18,717
Natural gas distribution 3,869 3,587 677
Utility services 6,170 6,371 12,910
Pipeline and energy services 18,158 19,097 16,406
Natural gas and oil production 63,027 53,192 63,178
Construction materials and mining 54,412 48,702 43,199
Independent power production
and other 12,021 959 ---
Total earnings on common stock $ 174,607 $ 147,688 $ 155,087
Capital expenditures:
Electric $ 28,537 $ 27,795 $ 14,373
Natural gas distribution 15,672 11,044 14,685
Utility services 7,820 17,242 70,232
Pipeline and energy services 93,004 21,449 51,054
Natural gas and oil production 101,698 136,424 118,719
Construction materials and mining 128,487 106,893 170,585
Independent power production
and other 112,858 95,748 ---
Net proceeds from sale or
disposition of property (14,439) (16,217) (51,641)
Total net capital expenditures $ 473,637 $ 400,378 $ 388,007
Identifiable assets:
Electric(b) $ 327,899 $ 322,475 $ 301,982
Natural gas distribution(b) 234,948 208,502 217,402
Utility services 221,824 230,888 239,069
Pipeline and energy services 405,904 312,858 354,336
Natural gas and oil production 602,389 554,420 476,105
Construction materials and mining 1,248,607 1,137,697 1,035,929
Independent power production
and other 263,941 148,770 ---
Corporate assets(c) 75,080 81,311 51,155
Total identifiable assets $3,380,592 $2,996,921 $2,675,978
Property, plant and equipment:
Electric(b) $ 639,893 $ 619,230 $ 597,080
Natural gas distribution(b) 252,591 244,930 235,771
Utility services 76,871 70,660 59,190
Pipeline and energy services 461,793 372,420 369,775
Natural gas and oil production 871,357 755,788 630,826
Construction materials and mining 893,980 804,255 711,410
Independent power production
and other 201,134 94,525 ---
Less accumulated depreciation,
depletion and amortization 1,175,326 1,019,438 889,816
Net property, plant and equipment $2,222,293 $1,942,370 $1,714,236
(a) In accordance with the provision of SFAS No. 71, intercompany coal
sales of $5,016 in 2001 were not eliminated.
(b) Includes allocations of common utility property.
(c) Corporate assets consist of assets not directly assignable to a
business (i.e., cash and cash equivalents, certain accounts receivable
and other miscellaneous current and deferred assets).
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. Capital expenditures for
2003, 2002 and 2001, related to acquisitions, in the preceding table
included the following noncash transactions: issuance of the Company's
equity securities of $42.4 million, $47.2 million and $57.4 million in
2003, 2002 and 2001, respectively.
NOTE 15
Acquisitions
In 2003, the Company acquired a number of businesses, none of which was
individually material, including construction materials and mining
businesses in Montana, North Dakota and Texas and a wind-powered
electric generation facility in California. The total purchase
consideration for these businesses and adjustments with respect to
certain other acquisitions acquired in 2002, including the Company's
common stock and cash, was $175.0 million.
In 2002, the Company acquired a number of businesses, none of which was
individually material, including utility services companies in
California and Ohio, construction materials and mining businesses in
Minnesota and Montana, an energy development company in Montana and
natural gas-fired electric generating facilities in Colorado. The
total purchase consideration for these businesses, consisting of the
Company's common stock and cash, was $139.8 million.
In 2001, the Company acquired a number of businesses, none of which was
individually material, including construction materials and mining
businesses in Hawaii, Minnesota and Oregon; utility services businesses
based in Missouri and Oregon; and an energy services company
specializing in cable and pipeline locating and tracking systems. The
total purchase consideration for these businesses, consisting of the
Company's common stock and cash, was $170.1 million.
On April 1, 2000, Fidelity Exploration & Production Company (Fidelity),
an indirect wholly owned subsidiary of the Company, purchased
substantially all of the assets of Preston Reynolds & Co., Inc.
(Preston), a coalbed natural gas development operation based in
Colorado with related oil and gas leases and properties in Montana and
Wyoming. Pursuant to the asset purchase and sale agreement, Preston
could, but was not obligated to purchase, acquire and own an undivided
25 percent working interest (Seller's Option Interest) in certain oil
and gas leases or properties acquired and/or generated by Fidelity.
Fidelity had the right, but not the obligation, to purchase Seller's
Option Interest from Preston for an amount as specified in the
agreement. On July 10, 2002, Fidelity purchased the Seller's Option
Interest.
The above acquisitions were accounted for under the purchase method of
accounting and, accordingly, the acquired assets and liabilities
assumed have been preliminarily recorded at their respective fair
values as of the date of acquisition. Final fair market values are
pending the completion of the review of the relevant assets,
liabilities and issues identified as of the acquisition date on certain
of the above acquisitions made in 2003. The results of operations of
the acquired businesses are included in the financial statements since
the date of each acquisition. Pro forma financial amounts reflecting
the effects of the above acquisitions are not presented, as such
acquisitions were not material to the Company's financial position or
results of operations.
NOTE 16
Employee Benefit Plans
The Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. The
Company uses a measurement date of December 31 for all of its pension
and postretirement benefit plans. These financial statements and this
Note do not reflect the effects of the 2003 Medicare Act on the
postretirement benefit plans. For more information on the 2003
Medicare Act, see new accounting standards in Note 1. Changes in
benefit obligation and plan assets for the years ended December 31 and
amounts recognized in the Consolidated Balance Sheets at December 31
were as follows:
Other
Pension Postretirement
Benefits Benefits
2003 2002 2003 2002
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $224,766 $204,046 $74,917 $67,019
Service cost 5,897 5,135 1,857 1,460
Interest cost 15,211 14,877 5,281 4,915
Plan participants' contributions --- --- 977 834
Amendments 210 372 754 ---
Actuarial loss 27,701 12,324 10,338 5,678
Benefits paid (12,450) (11,988) (5,743) (4,989)
Benefit obligation at
end of year 261,335 224,766 88,381 74,917
Change in plan assets:
Fair value of plan assets at
beginning of year 189,143 224,667 40,889 45,175
Actual gain (loss) on plan assets 43,087 (26,543) 6,148 (4,196)
Employer contribution 3,263 3,007 4,963 4,065
Plan participants' contributions --- --- 977 834
Benefits paid (12,450) (11,988) (5,743) (4,989)
Fair value of plan assets at end
of year 223,043 189,143 47,234 40,889
Funded status - over (under) (38,292) (35,623) (41,147) (34,028)
Unrecognized actuarial loss 41,422 35,662 11,862 3,484
Unrecognized prior service cost 8,556 9,501 706 ---
Unrecognized net transition
obligation (asset) (297) (1,247) 19,362 21,513
Prepaid (accrued) benefit cost $ 11,389 $ 8,293 $(9,217) $(9,031)
Amounts recognized in the
Consolidated Balance Sheets
at December 31:
Prepaid benefit cost $ 19,671 $ 16,175 $ 614 $ 780
Accrued benefit liability (8,282) (7,882) (9,831) (9,811)
Additional minimum liability --- (4,905) --- ---
Intangible asset --- 533 --- ---
Accumulated other
comprehensive loss --- 4,372 --- ---
Net amount recognized $ 11,389 $ 8,293 $(9,217) $(9,031)
Employer contributions and benefits paid in the above table include
only those amounts contributed directly to, or paid directly from, plan
assets.
The accumulated benefit obligation for the defined benefit pension
plans reflected above was $212.0 million and $186.4 million at
December 31, 2003 and 2002, respectively.
The projected benefit obligation, accumulated benefit obligation and
fair value of plan assets for the pension plans with accumulated
benefit obligations in excess of plan assets at December 31, 2003, were
as follows:
2003 2002
(In thousands)
Projected benefit obligation $38,845 $32,768
Accumulated benefit obligation $28,840 $24,656
Fair value of plan assets $24,508 $20,615
Components of net periodic benefit cost (income) for the Company's
pension and other postretirement benefit plans were as follows:
Other
Pension Postretirement
Benefits Benefits
Years ended December 31, 2003 2002 2001 2003 2002 2001
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 5,897 $ 5,135 $ 4,716 $ 1,857 $ 1,460 $ 1,376
Interest cost 15,211 14,877 14,498 5,281 4,915 4,691
Expected return on assets (20,730) (21,110) (20,672) (3,933) (3,843) (3,619)
Amortization of prior
service cost 1,156 1,148 1,247 48 --- ---
Recognized net actuarial
gain (417) (1,855) (2,687) (255) (566) (930)
Settlement (gain) loss --- --- (884) --- --- 15
Amortization of net
transition obligation
(asset) (950) (947) (965) 2,151 2,151 2,227
Net periodic benefit cost
(income) 167 (2,752) (4,747) 5,149 4,117 3,760
Less amount capitalized 14 (352) (391) 601 404 329
Net periodic benefit cost
(income) $ 153 $(2,400) $(4,356) $ 4,548 $ 3,713 $ 3,431
Weighted average assumptions used to determine benefit obligations at
December 31 were as follows:
Other
Pension Postretirement
Benefits Benefits
2003 2002 2003 2002
Discount rate 6.00% 6.75% 6.00% 6.75%
Rate of compensation increase 4.70% 4.50% 4.50% 4.50%
Weighted average assumptions used to determine net periodic benefit
cost for the years ended December 31 were as follows:
Other
Pension Postretirement
Benefits Benefits
2003 2002 2003 2002
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 4.50% 5.00% 4.50% 5.00%
The expected rate of return on plan assets is based on the targeted
asset allocation of 70 percent equity securities and 30 percent fixed
income securities and the expected rate of return from these asset
categories. The expected return on plan assets for other
postretirement benefits reflects insurance-related investment costs.
Health care rate assumptions for the Company's other postretirement
benefit plans as of December 31 were as follows:
2003 2002
Health care trend rate assumed for next year 6.0%-9.5% 6.0%-11.0%
Health care cost trend rate - ultimate 5.0%-6.0% 5.0%-6.0%
Year in which ultimate trend rate achieved 1999-2012 1999-2011
The Company's other postretirement benefit plans include health care
and life insurance benefits for certain employees. The plans
underlying these benefits may require contributions by the employee
depending on such employee's age and years of service at retirement or
the date of retirement. The accounting for the health care plans
anticipates future cost-sharing changes that are consistent with the
Company's expressed intent to generally increase retiree contributions
each year by the excess of the expected health care cost trend rate
over 6 percent.
Assumed health care cost trend rates may have a significant effect on
the amounts reported for the health care plans. A one percentage point
change in the assumed health care cost trend rates would have had the
following effects at December 31, 2003:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 250 $ (972)
Effect on postretirement benefit
obligation $3,479 $(9,554)
The Company's defined benefit pension plans asset allocation at
December 31, 2003 and 2002, and weighted average targeted asset
allocations at December 31, 2003, were as follows:
Weighted Average
Percentage Targeted Asset
of Plan Allocation
Assets Percentage
Asset Category 2003 2002 2003
Equity securities 72% 56% 70%
Fixed income securities 25 40 30*
Other 3 4 ---
Total 100% 100% 100%
*Includes target for both fixed income securities and other.
The Company's pension assets are managed by nine outside investment
managers. The Company's other postretirement assets are managed by one
outside investment manager. The Company's investment policy with
respect to pension and other postretirement assets is to make
investments solely in the interest of the participants and
beneficiaries of the plans and for the exclusive purpose of providing
benefits accrued and defraying the reasonable expenses of
administration. The Company strives to maintain investment
diversification to assist in minimizing the risk of large losses. The
Company's policy guidelines allow for investment of funds in cash
equivalents, fixed income securities and equity securities. The
guidelines prohibit investment in commodities and future contracts,
equity private placement, employer securities and leveraged or
derivative securities. The guidelines also prohibit short selling and
margin transactions. The Company's practice is to periodically review
and rebalance asset categories based on its targeted asset allocation
percentage policy.
The Company's other postretirement benefit plans asset allocation at
December 31, 2003 and 2002, and weighted average targeted asset
allocation at December 31, 2003, were as follows:
Weighted Average
Percentage Targeted Asset
of Plan Allocation
Assets Percentage
Asset Category 2003 2002 2003
Equity securities 66% 50% 70%
Fixed income securities 30 45 30*
Other 4 5 ---
Total 100% 100% 100%
*Includes target for both fixed income securities and other.
The Company expects to contribute approximately $1.6 million to its
defined benefit pension plans and approximately $5.0 million to its
postretirement benefit plans in 2004.
In addition to company-sponsored plans, certain employees are covered
under multi-employer defined benefit plans administered by a union.
Amounts contributed to the multi-employer plans were $27.2 million,
$27.8 million and $19.9 million in 2003, 2002 and 2001, respectively.
In addition to the qualified plan defined pension benefits reflected in
the table at the beginning of Note 16, the Company also has an
unfunded, nonqualified benefit plan for executive officers and certain
key management employees that provides for defined benefit payments
upon the employee's retirement or to their beneficiaries upon death for
a 15-year period or as an equivalent life annuity. Investments consist
of life insurance carried on plan participants, which is payable to the
Company upon the employee's death. The cost of these benefits was
$5.3 million, $5.1 million and $4.3 million in 2003, 2002 and 2001,
respectively. The total projected obligation for this plan was $51.1
million and $40.5 million at December 31, 2003 and 2002, respectively.
The accumulated benefit obligation for this plan was $40.7 million and
$33.3 million at December 31, 2003 and 2002, respectively. The
additional minimum liability relating to this plan was $8.2 million and
$4.0 million at December 31, 2003 and 2002, respectively. The Company
has a related intangible asset recognized as of December 31, 2003 and
2002, of $1.0 million and $1.1 million, respectively. A discount rate
of 6.0 percent and 6.75 percent at December 31, 2003 and 2002,
respectively, and a rate of compensation increase of 4.75 percent and
4.50 percent at December 31, 2003 and 2002, respectively, were used to
determine benefit obligations.
A discount rate of 6.75 percent and 7.25 percent at December 31, 2003
and 2002, respectively, and a rate of compensation increase of 4.50
percent and 5.00 percent at December 31, 2003 and 2002, respectively,
were used to determine net periodic benefit cost. The increase in
minimum liability included in other comprehensive income was $2.6
million in 2003 and $1.8 million in 2002.
The Company sponsors various defined contribution plans for eligible
employees. Costs incurred by the Company under these plans were
$9.8 million in 2003, $9.6 million in 2002 and $7.2 million in 2001.
The costs incurred in each year reflect additional participants as a
result of business acquisitions.
NOTE 17
Jointly Owned Facilities
The consolidated financial statements include the Company's 22.7
percent and 25.0 percent ownership interests in the assets, liabilities
and expenses of the Big Stone Station and the Coyote Station,
respectively. Each owner of the Big Stone and Coyote stations is
responsible for financing its investment in the jointly owned
facilities.
The Company's share of the Big Stone Station and Coyote Station
operating expenses was reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the Company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
2003 2002
(In thousands)
Big Stone Station:
Utility plant in service $ 52,154 $ 53,018
Less accumulated depreciation 34,993 34,456
$ 17,161 $ 18,562
Coyote Station:
Utility plant in service $124,086 $122,476
Less accumulated depreciation 72,850 70,778
$ 51,236 $ 51,698
NOTE 18
Regulatory Matters and Revenues Subject To Refund
On May 30, 2003, Montana-Dakota Utilities Co. (Montana-Dakota), a
public utility division of MDU Resources, filed an application with the
North Dakota Public Service Commission (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.
In December 2002, Montana-Dakota filed an application with the South
Dakota Public Utilities Commission (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 Natural Gas Co. (Great Plains), a public
utility division of MDU Resources, filed an application with the
Minnesota Public Utilities Commission (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 issued 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.
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 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.
NOTE 19
Commitments and Contingencies
Litigation
In January 2002, Fidelity Oil Co. (FOC), one of the Company's natural
gas and oil production subsidiaries, entered into a compromise
agreement with the former operator of certain of FOC's oil production
properties in southeastern Montana. The compromise agreement resolved
litigation involving the interpretation and application of contractual
provisions regarding net proceeds interests paid by the former operator
to FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the compromise
agreement, the natural gas and oil production segment reflected a
nonrecurring gain in its financial results for the first quarter of
2002 of approximately $16.6 million after tax. As part of the
settlement, FOC gave the former operator a full and complete release,
and FOC is not asserting any such claim against the former operator for
periods after 1997.
In 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 the 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 Federal 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 United States Environmental Protection Agency
(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.
The Company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that the outcomes with
respect to these other legal proceedings will not have a material
adverse effect upon the Company's financial position or results of
operations.
Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned
subsidiary of the Company, was named by the 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 that 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.
Operating leases
The Company leases certain equipment, facilities and land under
operating lease agreements. The amounts of annual minimum lease
payments due under these leases as of December 31, 2003, were
$18.1 million in 2004, $12.4 million in 2005, $8.7 million in 2006,
$5.1 million in 2007, $3.9 million in 2008 and $22.1 million
thereafter. Rent expense was approximately $27.2 million, $26.9
million and $31.5 million for the years ended December 31, 2003, 2002
and 2001, respectively.
Purchase commitments
The Company has entered into various commitments, largely natural gas
and coal supply, purchased power, natural gas transportation,
construction materials supply and electric generation construction
contracts. These commitments range from one to 21 years. The
commitments under these contracts as of December 31, 2003, were
$167.2 million in 2004, $67.2 million in 2005, $50.1 million in 2006,
$31.0 million in 2007, $30.9 million in 2008 and $146.3 million
thereafter. Amounts purchased under these various commitments for the
years ended December 31, 2003, 2002 and 2001, were approximately $204.6
million, $152.1 million and $193.0 million, respectively. These
commitments are not reflected in the Company's consolidated financial
statements.
Guarantees
Centennial has unconditionally guaranteed a portion of certain bank
borrowings of MPX in connection with the Company's equity method
investment in the natural gas-fired electric generating facility in
Brazil, as discussed in Note 2. The Company, through MDU Brasil, owns
49 percent of MPX. The main business purpose of Centennial extending
the guarantee to MPX's creditors is to enable MPX to obtain lower
borrowing costs. At December 31, 2003, the aggregate amount of
borrowings outstanding subject to these guarantees was $45.5 million
and the scheduled repayment of these borrowings is $11.0 million in
2004, $10.7 million in 2005, $10.7 million in 2006, $10.7 million in
2007 and $2.4 million in 2008. The individual investor (who through
EBX Empreendimentos Ltda. (EBX), a Brazilian company, owns 51 percent
of MPX) has also guaranteed a portion of these loans. In the event MPX
defaults under its obligation, Centennial and the individual investor
would be required to make payments under their guarantees. Centennial
and the individual investor have entered into reimbursement agreements
under which they have agreed to reimburse each other to the extent they
may be required to make any guarantee payments in excess of their
proportionate ownership share in MPX. These guarantees are not
reflected on the Consolidated Balance Sheets.
In addition, WBI Holdings, Inc. (WBI Holdings), an indirect wholly
owned subsidiary of the Company, has guaranteed certain of its
subsidiary's natural gas and oil price swap and collar agreement
obligations. The amount of the subsidiary's obligations at
December 31, 2003, was $1.8 million. There is no fixed maximum amount
guaranteed in relation to the natural gas and oil price swap and collar
agreements, as the amount of the obligation is dependent upon natural
gas and oil commodity prices. The amount of hedging activity entered
into by the subsidiary is limited by corporate policy. The guarantees
of the natural gas and oil price swap and collar agreements at
December 31, 2003, expire in 2004; however, the subsidiary continues to
enter into additional hedging activities and, as a result, WBI Holdings
from time to time may issue additional guarantees on these hedging
obligations. At December 31, 2003, the amount outstanding was
reflected on the Consolidated Balance Sheets. In the event the above
subsidiary defaults under its obligations, WBI Holdings would be
required to make payments under its guarantees.
Certain subsidiaries of the Company have outstanding guarantees to
third parties that guarantee the performance of other subsidiaries of
the Company that are related to natural gas transportation and sales
agreements, electric power supply agreements, insurance policies and
certain other guarantees. At December 31, 2003, the fixed maximum
amounts guaranteed under these agreements aggregated $46.4 million.
The amounts of scheduled expiration of the maximum amounts guaranteed
under these agreements aggregate $20.1 million in 2004; $5.9 million in
2005; $3.5 million in 2006; $500,000 in 2007; $900,000 in 2009; $12.0
million in 2012; $500,000, which is subject to expiration 30 days after
the receipt of written notice and $3.0 million, which has no scheduled
maturity date. The amount outstanding by subsidiaries of the Company
under the above guarantees was $372,000 and was reflected on the
Consolidated Balance Sheets at December 31, 2003. In the event of
default under these guarantee obligations, the subsidiary issuing the
guarantee for that particular obligation would be required to make
payments under its guarantee.
Fidelity and WBI Holdings have outstanding guarantees to Williston
Basin. These guarantees are related to natural gas transportation and
storage agreements that guarantee the performance of Prairielands
Energy Marketing, Inc. (Prairielands), an indirect wholly owned
subsidiary of the Company. At December 31, 2003, the fixed maximum
amounts guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under these
agreements aggregate $2.9 million in 2005 and $20.0 million in 2009.
In the event of Prairielands' default in its payment obligations, the
subsidiary issuing the guarantee for that particular obligation would
be required to make payments under its guarantee. The amount
outstanding by Prairielands under the above guarantees was $837,000,
which was not reflected on the Consolidated Balance Sheet at
December 31, 2003, because these intercompany transactions are
eliminated in consolidation.
In addition, Centennial has issued guarantees related to the Company's
purchase of maintenance items to third parties for which no fixed
maximum amounts have been specified. These guarantees have no
scheduled maturity date. In the event a subsidiary of the Company
defaults under its obligation in relation to the purchase of certain
maintenance items, Centennial would be required to make payments under
these guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the Consolidated
Balance Sheet at December 31, 2003.
As of December 31, 2003, Centennial was contingently liable for the
performance of certain of its subsidiaries under approximately
$360 million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries entered into in the normal course of business. Centennial
indemnifies the respective surety bond companies against any exposure
under the bonds. The purpose of Centennial's indemnification is to
allow the subsidiaries to obtain bonding at competitive rates. In the
event a subsidiary of the Company does not fulfill its obligations in
relation to its bonded contract or obligation, Centennial may be
required to make payments under its indemnification. A large portion
of these contingent commitments are expected to expire within the next
12 months; however, Centennial will likely continue to enter into
surety bonds for its subsidiaries in the future. The surety bonds were
not reflected on the Consolidated Balance Sheets.
Independent Auditors' Report
To the Board of Directors and Stockholders of
MDU Resources Group, Inc.:
We have audited the accompanying consolidated balance sheets
of MDU Resources Group, Inc. (the "Company") as of December
31, 2003 and 2002, and the related consolidated statements
of income, common stockholders' equity, and cash flows for
the years then ended. Our audits also included the 2003 and
2002 financial statement schedules listed in the Index at
Item 15. These consolidated financial statements and financial
statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.
The consolidated financial statements and financial statement
schedule of the Company for the year ended December 31, 2001,
before the adjustments described in Note 11, additional transitional
disclosures described in Notes 3 and 9, and the reclassifications
to the consolidated financial statements described in Note 1, were
audited by other auditors who have ceased operations. Those
auditors expressed an unqualified opinion on those
consolidated financial statements and stated that such 2001
financial statement schedule, when considered in relation to
the 2001 basic consolidated financial statements taken as a
whole, presented fairly, in all material respects, the
information set forth therein, in their reports dated
January 23, 2002.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the consolidated
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the 2003 and 2002 consolidated financial
statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2003
and 2002, and the results of its operations and its cash
flows for the years then ended in conformity with accounting
principles generally accepted in the United States of
America. Also, in our opinion, the 2003 and 2002 financial
statement schedules, when considered in relation to the 2003
and 2002 consolidated financial statements taken as a whole,
present fairly, in all material respects, the information
set forth therein.
As discussed above, the consolidated financial statements of
the Company for the year ended December 31, 2001 were
audited by other auditors who have ceased operations. As
described in Note 11, those consolidated financial
statements have been revised to give effect to the stock
split on October 29, 2003. We audited the adjustments
described in Note 11 that were applied to revise the 2001
consolidated financial statements for such stock split. Our
audit procedures included (1) comparing the amounts shown in
the earnings per share disclosures for 2001 to the Company's
underlying accounting analysis obtained from management,
(2) comparing the previously reported shares outstanding and
income statement amounts per the Company's accounting
analysis to the previously issued consolidated financial
statements, and (3) recalculating the additional shares to
give effect to the stock split and testing the mathematical
accuracy of the underlying analysis. Also, as described in
Note 3, these consolidated financial statements have been revised
to include the transitional disclosures required by Statement
of Financial Accounting Standards ("SFAS") No. 142, Goodwill
and Other Intangible Assets, which was adopted by the
Company as of January 1, 2002. Our audit procedures, with
respect to the disclosures in Note 3 with respect to the
2001 disclosures, included (a) comparing the previously
reported net income to the previously issued consolidated
financial statements and the adjustments to reported net
income representing amortization expense (including any
related tax effects) recognized in those periods related to
goodwill that is no longer being amortized as a result of
initially applying SFAS No. 142 (including any tax effects)
to the Company's underlying analysis obtained from
management, and (b) testing the mathematical accuracy of (i)
the reconciliation of adjusted net income to reported net
income and (ii) the related earnings per share amounts.
Also, as described in Note 1, these consolidated financial
statements have been reclassified to include additional
disclosures relating to the components comprising operating
revenues and operation and maintenance expenses. Our audit
procedures with respect to 2001 as it relates to the
reclassifications described in Note 1 included (1) comparing
the previously reported operating revenues and operation and
maintenance expenses to previously issued consolidated
financial statements, (2) comparing the operating revenues
and operation and maintenance expenses to the Company's
underlying analysis obtained from management, and
(3) testing the mathematical accuracy of the underlying
analysis. Also, as described in Note 9, these consolidated
financial statements have been revised to include
disclosures required by SFAS No. 143, Accounting for Asset
Retirement Obligations, which was adopted by the Company as
of January 1, 2003. Our audit procedures with respect to
the disclosures in Note 9 as they relate to 2001 included
testing the mathematical accuracy of the underlying
analysis. In our opinion, the 2001 adjustments for the
stock split described in Note 11 have been properly applied,
the goodwill disclosures for 2001 in Note 3 and the asset
retirement disclosures for 2001 in Note 9 are appropriate,
and the reclassifications to the consolidated financial
statements described in Note 1 have been properly applied.
However, we were not engaged to audit, review, or apply any
procedures to the 2001 consolidated financial statements of
the Company other than with respect to such adjustments,
reclassifications, and disclosures and, accordingly, we do
not express an opinion or any other form of assurance on the
2001 consolidated financial statements taken as a whole.
As discussed in Notes 1 and 9 to the consolidated financial
statements, effective January 1, 2003, the Company changed
its method of accounting for asset retirement obligations;
and as discussed in Notes 1 and 3 to the consolidated
financial statements, effective January 1, 2002, the Company
changed its method of accounting for goodwill.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 17, 2004
THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR
ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT
TO THE INCLUSION OF ITS REPORT IN THIS ANNUAL REPORT.
Report of Independent Public Accountants
To MDU Resources Group, Inc.:
We have audited the accompanying consolidated balance sheets
of MDU Resources Group, Inc. (a Delaware corporation) and
Subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, common
stockholders' equity and cash flows for each of the three
years in the period ended December 31, 2001. These financial
statements are the responsibility of the company's
management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing
standards generally accepted in the United States. Those
standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used
and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial
position of MDU Resources Group, Inc. and Subsidiaries as of
December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United
States.
As explained in Note 1 to the consolidated financial
statements, effective January 1, 2001, the company changed
its method of accounting for derivative instruments due to
the adoption of a new accounting pronouncement.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 23, 2002
THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR
ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT
TO THE INCLUSION OF ITS REPORT IN THIS ANNUAL REPORT.
To MDU Resources Group, Inc.:
We have audited in accordance with auditing standards generally
accepted in the United States, the financial statements included in MDU
Resources Group, Inc.'s annual report to stockholders incorporated by
reference in this Form 10-K, and have issued our report thereon dated
January 23, 2002. Our audit was made for the purpose of forming an
opinion on those statements taken as a whole. Schedule II is the
responsibility of the company's management and is presented for
purposes of complying with the Securities and Exchange Commission's
rules and is not part of the basic financial statements. This schedule
has been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly states in
all material respects the financial data required to be set forth
therein in relation to the basic financial statements taken as a whole.
/S/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 23, 2002
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter for
the years 2003 and 2002:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2003
Operating revenues $467,753 $548,219 $716,099 $620,118
Operating expenses 414,806 473,534 600,433 551,344
Operating income 52,947 74,685 115,666 68,774
Income before cumulative effect
of accounting change 27,697 43,473 65,521 46,222
Cumulative effect of accounting
change (7,589) --- --- ---
Net income 20,108 43,473 65,521 46,222
Earnings per common share --
basic:
Earnings before cumulative
effect of accounting change .25 .39 .58 .41
Cumulative effect of accounting
change (.07) --- --- ---
Earnings per common share --
basic .18 .39 .58 .41
Earnings per common share --
diluted:
Earnings before cumulative
effect of accounting change .25 .39 .58 .40
Cumulative effect of accounting
change (.07) --- --- ---
Earnings per common share --
diluted .18 .39 .58 .40
Weighted average common shares
outstanding:
Basic 110,318 110,602 112,359 112,618
Diluted 111,094 111,532 113,368 113,804
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2002
Operating revenues $381,935 $480,218 $612,398 $556,986
Operating expenses 336,138 429,023 522,227 478,032
Operating income 45,797 51,195 90,171 78,954
Net income 23,722 24,853 53,931 45,938
Earnings per common share:
Basic .23 .23 .51 .42
Diluted .22 .23 .50 .42
Weighted average common shares
outstanding:
Basic 104,203 105,684 106,385 108,142
Diluted 105,020 106,540 107,017 108,864
Pro forma amounts assuming
retroactive application of
accounting change:
Net income $ 23,126 $ 24,255 $ 53,332 $ 45,339
Earnings per common share --
basic .22 .23 .50 .42
Earnings per common share --
diluted .22 .23 .50 .41
Certain Company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
Natural Gas and Oil Activities (Unaudited)
Fidelity is involved in the acquisition, exploration, development and
production of natural gas and oil resources. Fidelity's activities
include the acquisition of producing properties with potential
development opportunities, exploratory drilling and the operation and
development of natural gas production properties. Fidelity shares
revenues and expenses from the development of specified properties
located primarily in the Rocky Mountain region of the United States and
in 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.
The information that follows includes Fidelity's proportionate share of
all its natural gas and oil interests.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to natural gas and oil
producing activities at December 31:
2003 2002 2001
(In thousands)
Subject to amortization $758,500 $603,151 $506,155
Not subject to amortization 104,339 145,692 122,354
Total capitalized costs 862,839 748,843 628,509
Less accumulated depreciation,
depletion and amortization 305,349 239,964 195,469
Net capitalized costs $557,490 $508,879 $433,040
Capital expenditures, including those not subject to amortization,
related to natural gas and oil producing activities were as follows:
Years ended December 31, 2003* 2002 2001
(In thousands)
Acquisitions $ 3,027 $ 31,439 $ 1,695
Exploration 19,193 5,325 13,938
Development** 77,583 94,943 102,670
Total capital expenditures $99,803 $131,707 $118,303
* Excludes $14,724 of additions to property, plant and equipment
related to the recognition of future liabilities associated with
the plugging and abandonment of natural gas and oil wells in
accordance with SFAS No. 143, as discussed in Note 9.
**Includes expenditures for proved undeveloped reserves of $23.3
million, $10.1 million and $15.0 million for the years ended
December 31, 2003, 2002 and 2001, respectively.
The following summary reflects income resulting from the Company's
operations of natural gas and oil producing activities, excluding
corporate overhead and financing costs:
Years ended December 31, 2003 2002* 2001
(In thousands)
Revenues:
Sales to external customers $140,034 $145,170 $139,939
Sales to affiliates 124,077 55,437 61,178
Production costs 67,292 52,520 44,435
Depreciation, depletion and
amortization 60,072** 48,064 41,223
Pretax income 136,747 100,023 115,459
Income tax expense 51,925 36,886 45,245
Results of operations for
producing activities before
cumulative effect of accounting
change 84,822 63,137 70,214
Cumulative effect of accounting
change (7,740) --- ---
Results of operations for
producing activities $ 77,082 $ 63,137 $ 70,214
* Includes the compromise agreement as discussed in Note 19.
**Includes $1,356 of accretion of discount for asset retirement
obligations in 2003 in accordance with SFAS No. 143, as discussed
in Note 1.
The following table summarizes the Company's estimated quantities of
proved natural gas and oil reserves at December 31, 2003, 2002 and
2001, and reconciles the changes between these dates. Estimates of
economically recoverable natural gas and oil reserves and future net
revenues therefrom are based upon a number of variable factors and
assumptions. For these reasons, estimates of economically recoverable
reserves and future net revenues may vary from actual results.
2003 2002 2001
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(In thousands of Mcf/barrels)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 372,500 17,500 324,100 17,500 309,800 15,100
Production (54,700) (1,900) (48,200) (2,000) (40,600) (2,000)
Extensions and
discoveries 113,300 3,300 80,100 2,200 66,400 2,000
Purchases of proved
reserves 900 --- 1,200 100 1,000 100
Sales of reserves
in place --- (100) (4,400) (300) --- ---
Revisions of previous
estimates (20,300) 100 19,700 --- (12,500) 2,300
Balance at end
of year 411,700 18,900 372,500 17,500 324,100 17,500
Proved developed reserves:
January 1, 2001 263,400 14,200
December 31, 2001 291,300 17,100
December 31, 2002 331,300 14,800
December 31, 2003 342,800 15,000
All of the Company's interests in natural gas and oil reserves are
located in the United States and in and around the Gulf of Mexico.
The standardized measure of the Company's estimated discounted future
net cash flows of total proved reserves associated with its various
natural gas and oil interests at December 31 was as follows:
2003 2002 2001
(In thousands)
Future cash inflows $2,547,400 $1,726,000 $ 974,200
Future production costs 651,300 513,200 361,600
Future development costs 67,100 61,200 64,600
Future net cash flows before
income taxes 1,829,000 1,151,600 548,000
Future income tax expense 601,000 324,000 112,000
Future net cash flows 1,228,000 827,600 436,000
10% annual discount for estimated
timing of cash flows 491,200 321,300 174,000
Discounted future net cash flows
relating to proved natural gas
and oil reserves $ 736,800 $ 506,300 $ 262,000
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
2003 2002 2001
(In thousands)
Beginning of year $506,300 $262,000 $ 921,300
Net revenues from production (220,000) (112,900) (153,500)
Change in net realization 318,600 296,100 (1,119,700)
Extensions, discoveries and
improved recovery, net of
future production-related costs 245,800 117,000 40,200
Purchases of proved reserves 2,800 3,700 2,600
Sales of reserves in place (600) (8,900) ---
Changes in estimated future
development costs (4,000) (1,100) (6,700)
Development costs incurred
during the current year 35,300 19,400 31,600
Accretion of discount 62,400 27,300 122,700
Net change in income taxes (172,000) (124,700) 436,500
Revisions of previous
estimates (35,500) 30,000 (11,700)
Other (2,300) (1,600) (1,300)
Net change 230,500 244,300 (659,300)
End of year $736,800 $506,300 $ 262,000
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end natural gas
prices and oil prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future development costs estimated to be spent in each of
the next three years to develop proved undeveloped reserves are $37.1
million in 2004, $6.7 million in 2005 and $4.4 million in 2006. Future
income tax expenses were computed by applying statutory tax rates
(adjusted for permanent differences and tax credits) to estimated net
future pretax cash flows.
The standardized measure of discounted future net cash flows does not
purport to represent the fair market value of natural gas and oil
properties. There are significant uncertainties inherent in estimating
quantities of proved reserves and in projecting rates of production and
the timing and amount of future costs. In addition, future realization
of natural gas and oil prices over the remaining reserve lives may vary
significantly from current prices.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
The following information includes the evaluation of
disclosure controls and procedures by the Company's chief
executive officer and the chief financial officer, along with any
significant changes in internal controls of the Company.
Evaluation of disclosure controls and procedures
The term "disclosure controls and procedures" is defined in
Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of
1934 (Exchange Act). These rules refer to the controls and other
procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports
that it files under the Exchange Act is recorded, processed,
summarized and reported within required time periods. The
Company's chief executive officer and chief financial officer
have evaluated the effectiveness of the Company's disclosure
controls and procedures and they have concluded that, as of the
end of the period covered by this report, such controls and
procedures were effective to accomplish those tasks.
Changes in internal controls
The Company maintains a system of internal accounting controls
that is designed to provide reasonable assurance that the
Company's transactions are properly authorized, the Company's
assets are safeguarded against unauthorized or improper use, and
the Company's transactions are properly recorded and reported to
permit preparation of the Company's financial statements in
conformity with generally accepted accounting principles in the
United States of America. There were no changes in the Company's
internal control over financial reporting that occurred during
the period covered by this report that have materially affected,
or are reasonably likely to materially affect, the Company's
internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is included under the
captions "Election of Directors," "Continuing Incumbent
Directors," "Information Concerning Executive Officers," "Board
and Board Committees" and "Nominating and Governance Committee"
in the Company's Proxy Statement dated March 5, 2004 (Proxy
Statement), which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is included under the
captions "Directors' Compensation" and "Executive Compensation"
of the Proxy Statement, which is incorporated herein by reference
with the exception of the compensation committee report on
executive compensation and the performance graph.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is included under the
captions "Security Ownership" and "Proposal to Amend the Non-
Employee Director Stock Compensation Plan" of the Proxy
Statement, which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is included under the
caption "Accounting and Auditing Matters" of the Proxy Statement,
which is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits
Index to Financial Statements and Financial Statement
Schedules
1. Financial Statements:
The following consolidated financial statements
required under this item are included under
Item 8 -- Financial Statements and Supplementary
Data.
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 2003
Consolidated Balance Sheets at December 31,
2003 and 2002
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 2003
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 2003
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
MDU RESOURCES GROUP, INC.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
Additions
_______________________
Balance at Charged to
beginning costs and Balance at
Description of year expenses Other(a)(b) Deductions(c) end of year
(In thousands)
Allowance for
doubtful
accounts:
2003 $8,237 $3,185 $1,123 $4,399 $8,146
2002 5,773 8,192 1,164 6,892 8,237
2001 4,063 3,896 2,003 4,189 5,773
(a) Allowance for doubtful accounts for companies acquired
(b) Recoveries
(c) Uncollectible accounts written off
All other schedules are omitted
because of the absence of the conditions
under which they are required, or because
the information required is included in the
Company's Consolidated Financial Statements
and Notes thereto.
3. Exhibits:
3(a) Restated Certificate of Incorporation of
the Company, as amended, filed as Exhibit
3(a) to Form S-3 on June 13, 2003, in
Registration No. 333-104150 *
3(b) By-laws of the Company, as amended,
filed as Exhibit 3.3 to Form 8-A/A on
March 10, 2003, in File No. 1-3480 *
3(c) Certificate of Designations of Series B
Preference Stock of the Company, as
amended, filed as Exhibit 3(a) to
Form 10-Q for the quarter ended
September 30, 2002, in File No. 1-3480 *
4(a) Indenture of Mortgage, dated as of May 1,
1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of
April 21, 1992, and the Forty-Sixth through
Forty-Ninth Supplements thereto between the
Company and the New York Trust Company (The
Bank of New York, successor Corporate
Trustee) and A. C. Downing (Douglas J.
MacInnes, successor Co-Trustee), filed as
Exhibit 4(a) in Registration No. 33-66682;
and Exhibits 4(e), 4(f) and 4(g) in
Registration No. 33-53896; and Exhibit
4(c)(i) in Registration No. 333-49472 *
4(b) Fiftieth Supplemental Indenture, dated as of
December 15, 2003, filed as Exhibit 4(e) to
Form S-8 on January 21, 2004, in Registration
No. 333-112035 *
4(c) Rights agreement, dated as of November 12,
1998, between the Company and Wells Fargo
Bank Minnesota, N.A. (formerly known as
Norwest Bank Minnesota, N.A.), Rights
Agent, filed as Exhibit 4.1 to Form 8-A on
November 12, 1998, in File No. 1-3480 *
4(d) Indenture, dated as of December 15, 2003,
between the Company and The Bank of New
York, as trustee, filed as Exhibit 4(f) to
Form S-8 on January 21, 2004, in
Registration No. 333-112035 *
4(e) Certificate of Adjustment to Purchase Price
and Redemption Price, as amended and
restated, pursuant to the Rights Agreement,
dated as of November 12, 1998 **
+ 10(a) Executive Incentive Compensation Plan,
as amended **
+ 10(b) 1992 Key Employee Stock Option Plan,
as amended, filed as Exhibit 10(b) to
Form 10-K for the year ended December 31,
2002, in File No. 1-3480 *
+ 10(c) Supplemental Income Security Plan,
as amended, filed as Exhibit 10(c) to
Form 10-K for the year ended December 31,
2002, in File No. 1-3480 *
+ 10(d) Directors' Compensation Policy, as amended,
filed as Exhibit 10(a) to Form 10-Q for the
quarter ended June 30, 2003, in File No.
1-3480 *
+ 10(e) Deferred Compensation Plan for Directors,
as amended, filed as Exhibit 10(e) to
Form 10-K for the year ended December 31,
2002, in File No. 1-3480 *
+ 10(f) Non-Employee Director Stock Compensation
Plan, as amended, filed as Exhibit 10(b)
to Form 10-Q for the quarter ended June 30,
2003, in File No. 1-3480 *
+ 10(g) 1997 Non-Employee Director Long-Term
Incentive Plan, as amended, filed as Exhibit
10(d) to Form 10-Q for the quarter ended
June 30, 2000, in File No. 1-3480 *
+ 10(h) 1997 Executive Long-Term Incentive Plan,
as amended, filed as Exhibit 10(a) to
Form 10-Q for the quarter ended
March 31, 2001, in File No. 1-3480 *
+ 10(i) Change of Control Employment Agreement
between the Company and John K. Castleberry,
filed as Exhibit 10(a) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(j) Change of Control Employment Agreement
between the Company and Cathleen M.
Christopherson, filed as Exhibit 10(b) to
Form 10-Q for the quarter ended
September 30, 2002, in File No. 1-3480 *
+ 10(k) Change of Control Employment Agreement
between the Company and Richard A. Espeland,
filed as Exhibit 10(c) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(l) Change of Control Employment Agreement
between the Company and Terry D. Hildestad,
filed as Exhibit 10(d) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(m) Change of Control Employment Agreement
between the Company and Vernon A. Raile,
filed as Exhibit 10(f) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(n) Change of Control Employment Agreement
between the Company and Warren L. Robinson,
filed as Exhibit 10(g) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(o) Change of Control Employment Agreement
between the Company and William E. Schneider,
filed as Exhibit 10(h) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(p) Change of Control Employment Agreement
between the Company and Ronald D. Tipton,
filed as Exhibit 10(i) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(q) Change of Control Employment Agreement
between the Company and Martin A. White,
filed as Exhibit 10(j) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(r) Change of Control Employment Agreement
between the Company and Robert E. Wood,
filed as Exhibit 10(k) to Form 10-Q for the
quarter ended September 30, 2002, in File
No. 1-3480 *
+ 10(s) Separation Agreement and Release between
the Company and Douglas C. Kane, filed as
Exhibit 10(t) to Form 10-K for the year
ended December 31, 2002, in File No. 1-3480 *
+ 10(t) 1998 Option Award Program, filed as Exhibit
10(u) to Form 10-K for the year ended
December 31, 2002, in File No. 1-3480 *
+ 10(u) Group Genius Innovation Plan, filed as
Exhibit 10(v) to Form 10-K for the year
ended December 31, 2002, in File No. 1-3480 *
+ 10(v) Agreement on Retirement between the Company
and Lester H. Loble, II **
+ 10(w) The Wagner-Smith Company Deferred
Compensation Plan **
+ 10(x) Wagner-Smith Equipment Co. Deferred
Compensation Plan **
+ 10(y) The Capital Electric Construction Company,
Inc. Deferred Compensation Plan **
+ 10(z) The Capital Electric Line Builders, Inc.
Deferred Compensation Plan **
+ 10(aa) The Bauerly Brothers, Inc. Deferred
Compensation Plan **
+ 10(ab) The Oregon Electric Construction, Inc.
Deferred Compensation Plan **
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Independent Auditors' Consent **
23(b) Notice regarding consent of Arthur
Andersen LLP **
31(a) Certification of Chief Executive Officer
filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 **
31(b) Certification of Chief Financial Officer
filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 **
32 Certification of Chief Executive Officer
and Chief Financial Officer furnished
pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 **
* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to Item
15(c) of this report.
(b) Reports on Form 8-K
Form 8-K was filed on October 24, 2003. Under Item 12 --
Results of Operations and Financial Condition, the Company
reported the press release issued October 24, 2003, regarding
earnings for the quarter ended September 30, 2003.
Form 8-K was filed on November 18, 2003. Under Item 5 --
Other Events, the Company reported an alliance formed with Basin
Electric Power Cooperative to evaluate potential utility
opportunities presented by NorthWestern Corporation's bankruptcy
filing.
Form 8-K was filed on December 17, 2003. Under Item 5 --
Other Events and Required FD Disclosure, the Company filed an
Underwriting Agreement relating to a public offering of Senior
Notes.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
MDU RESOURCES GROUP, INC.
Date: February 27, 2004 By: /s/ Martin A. White
Martin A. White (Chairman of
the Board, President and Chief
Executive Officer)
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following persons
on behalf of the registrant in the capacities and on the date indicated.
Signature Title Date
/s/ Martin A. White Chief Executive February 27, 2004
Martin A. White (Chairman of the Board, Officer
President and Chief Executive Officer) and Director
/s/ Warren L. Robinson Chief Financial February 27, 2004
Warren L. Robinson (Executive Vice Officer
President and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 27, 2004
Vernon A. Raile (Senior Vice President Officer
and Chief Accounting Officer)
/s/ Harry J. Pearce Lead Director February 27, 2004
Harry J. Pearce
Director
Bruce R. Albertson
/s/ Thomas Everist Director February 27, 2004
Thomas Everist
/s/ Dennis W. Johnson Director February 27, 2004
Dennis W. Johnson
/s/ Patricia L. Moss Director February 27, 2004
Patricia L. Moss
/s/ Robert L. Nance Director February 27, 2004
Robert L. Nance
/s/ John L. Olson Director February 27, 2004
John L. Olson
/s/ Homer A. Scott, Jr. Director February 27, 2004
Homer A. Scott, Jr.
/s/ Sister Thomas Welder Director February 27, 2004
Sister Thomas Welder
/s/ John K. Wilson Director February 27, 2004
John K. Wilson