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, 2004
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 (or
for such shorter period that the registrant was required to file
such reports), 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.
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes X .
No __.
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of June 30, 2004:
$2,822,813,000.
Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 17, 2005:
118,292,354 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
Portions of the Registrant's 2005 Proxy Statement 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
Independent Power Production
Item 3 -- Legal Proceedings
Item 4 -- Submission of Matters to a Vote of
Security Holders
PART II
Item 5 -- Market for the Registrant's Common Equity,
Related Stockholder Matters and Issuer
Purchase of Equity Securities
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 -- Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
Item 9A -- Controls and Procedures
Item 9B -- Other Information
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 and Financial Statement Schedules
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 (MD&A) - 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, disposal and impairments of assets or
facilities
- Changes in operation, performance and construction of plant
facilities or other assets
- Changes in present or prospective generation
- The availability of economic expansion or development
opportunities
- Population growth rates and demographic patterns
- Market demand for, and/or available supplies of, energy
products and services
- Cyclical nature of large construction projects at certain
operations
- 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
- 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 or regulatory 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 western Minnesota and southeastern North Dakota. 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, development 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, builds and operates electric
generating facilities in the United States and has
investments in domestic and international natural
resource-based projects. Electric capacity and energy
produced at its power plants are sold primarily under mid-
and long-term contracts to nonaffiliated entities.
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 the
Other category.
As of December 31, 2004, the Company had 8,058 full-time
employees with 100 employed at MDU Resources Group, Inc., 903 at
Montana-Dakota, 55 at Great Plains, 478 at WBI Holdings, 4,015 at
Knife River, 2,414 at Utility Services and 93 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, 433 and 75 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. Williston Basin is currently in
negotiations with the IBEW relative to its contract.
Knife River has 41 labor contracts that represent 662 of its
construction materials employees. Knife River is currently in
negotiations on one of its labor contracts.
Utility Services has 69 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 - MD&A and Item 8 --
Financial Statements and Supplementary Data - Note 13 and
Supplementary Financial Information.
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 -
Construction Materials and Mining - Environmental Matters and in
Item 8 -- Financial Statements and Supplementary Data - Note 18.
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 Web site as soon as reasonably
practicable after the Company has filed such reports with the
Securities and Exchange Commission (SEC). The Company's Web site
address is www.mdu.com. The information available on the
Company's Web site 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, 2004. 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 -- MD&A - Prospective Information -
Electric. As of December 31, 2004, Montana-Dakota's net electric
plant investment approximated $292.9 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 2004 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 475,000 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. 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.
On January 9, 2004, Montana-Dakota entered into a firm capacity
contract with a Midwest utility to purchase capacity during
certain months of 2004 to 2006. In addition, on January 9, 2004,
Montana-Dakota entered into a firm power contract with the
Midwest utility to purchase power during certain months of 2006
to 2010. All capacity and power purchases from these contracts
were contingent upon the parties securing transmission service
for the delivery of capacity and power to Montana-Dakota's
customer load. Transmission service was not secured and no
capacity or energy was delivered under this contract in 2004.
These agreements expired on December 31, 2004.
On July 15, 2004, Montana-Dakota entered into a firm capacity
contract to purchase 15 megawatts of capacity and associated
energy for the summer of 2005 and 25 megawatts of capacity and
associated energy for the summer of 2006 from a neighboring
utility.
On October 25, 2004, Montana-Dakota issued a request for proposal
for 70 megawatts to 100 megawatts of firm capacity and associated
energy for the period of November 1, 2006 through December 31,
2010. Montana-Dakota is currently in the process of evaluating
the responses.
The following table sets forth details applicable to the
Company's electric generating stations:
2004 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 809,267
Heskett Steam 86,000 103,780 613,145
Williston Combustion
Turbine 7,800 9,600 (75)**
South Dakota --
Big Stone* Steam 94,111 103,240 771,679
Montana --
Lewis & Clark Steam 44,000 52,300 345,857
Glendive Combustion
Turbine 75,522 75,500 9,689
Miles City Combustion
Turbine 23,150 23,830 3,311
434,230 475,000 2,552,873
- -----------------------------
* 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 were met with coal supplied by RAG Coal West, Inc.
under a contract that expired on December 31, 2004. On July 14,
2004 and July 22, 2004, Montana-Dakota entered into a three-year
coal supply agreement with Kennecott Coal Sale Company
(Kennecott) and Arch Coal Sales Company (Arch), respectively, to
meet the majority of the Big Stone Station's fuel requirements
for the years 2005 to 2007, at contracted pricing. The Kennecott
and Arch agreements provide for the purchase during 2005, 2006
and 2007 of 500,000, 1.5 million and 1.3 million tons of coal,
respectively, from Kennecott and 1.3 million, 500,000 and 500,000
tons of coal, respectively, from Arch.
The Coyote coal supply agreement provides for the purchase of
coal necessary to supply 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 of coal necessary to supply the coal requirements of the
Heskett Station at contracted pricing. The anticipated fuel
supply requirement for 2005 is 400,000 tons. The Lewis & Clark
coal supply agreement provides for the purchase of coal necessary
to supply 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, 2000, through December 31,
2004, 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, 2004 2003 2002 2001 2000
Average cost of
coal per
million Btu $ 1.08 $ 1.04 $ .98 $ .92 $ .94
Average cost of
coal per ton $15.96 $15.22 $14.39 $13.43 $13.68
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 2010 will approximate 1.2 percent annually. Montana-
Dakota's latest forecast indicates that its kilowatt-hour (kWh)
sales growth rate, on a normalized basis, through 2010 will
approximate 1.5 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 through the year
2006. 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 and/or building or
acquiring an additional 175 megawatts to 200 megawatts of
capacity. As part of the North Dakota Industrial Commission's
Lignite Vision 21 project, Montana-Dakota submitted an air
quality permit application in May 2004 to construct a 175-
megawatt coal-fired plant at Gascoyne, North Dakota. The air
permit application is under review at the North Dakota Department
of Health (North Dakota Health Department). Montana-Dakota also
is involved in the review of other potential projects to replace
capacity associated with expiring purchased power contracts and
to provide for future growth. 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
the PacifiCorp transmission system, under an agreement with Black
Hills Power and Light Company (Black Hills Power), as part of a
power supply contract through December 31, 2006, which allows for
the purchase of up to 55,000 kW of capacity annually. On
December 30, 2004, Montana-Dakota entered into a power supply
contract with Black Hills Power to purchase up to 74,000 kW of
capacity annually during the period January 1, 2007 to
December 31, 2016.
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 transmission 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 that 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 - MD&A - Prospective Information -
Electric.
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 includable 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 generating facilities have Title V
Operating Permits, under the Clean Air Act, issued by the states
in which it operates. Each of these permits has a five-year
life. Three permits have expired with a fourth expiring on April
1, 2005. Montana-Dakota has submitted applications for renewal
on all four permits within the required time frames, and as a
result, all the expired permits remain valid. 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 its 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 2004 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2007. For matters involving
Montana-Dakota and the North Dakota Health Department 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 223,000
residential, commercial and industrial customers located in 142
communities and adjacent rural areas as of December 31, 2004, 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, 2004, 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 approximately 5,200 miles.
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. For additional information regarding
Montana-Dakota's and Great Plains' franchises, see Item 7 -
MD&A - Prospective Information - Natural gas distribution. As of
December 31, 2004, Montana-Dakota's and Great Plains' net natural
gas distribution plant investment approximated $151.6 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'
2004 natural gas utility operating revenues by jurisdiction is as
follows: North Dakota -- 40 percent; Minnesota -- 10 percent;
Montana -- 25 percent; South Dakota -- 19 percent and Wyoming --
6 percent.
System Supply, System Demand and Competition --
Montana-Dakota and Great Plains serve retail natural gas markets,
consisting principally of residential and firm commercial space
and water heating users, in portions of the following states and
major communities -- North Dakota, including Bismarck, Dickinson,
Wahpeton, Williston, Minot and Jamestown; western Minnesota,
including Fergus Falls, Marshall and Crookston; eastern Montana,
including Billings, Glendive and Miles City; western and north-
central South Dakota, including Rapid City, Pierre and Mobridge;
and northern Wyoming, including Sheridan. These markets are
highly seasonal and sales volumes depend largely on the weather,
the effects of which are mitigated in certain jurisdictions by a
Distribution Delivery Stabilization Mechanism discussed in
Regulatory Matters.
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, 2004* 2003* 2002* 2001* 2000**
Mdk (thousands of decatherms)
Sales:
Residential 20,303 21,498 21,893 20,087 20,554
Commercial 14,598 15,537 16,044 14,661 14,590
Industrial 1,706 1,537 1,621 1,731 1,451
Total 36,607 38,572 39,558 36,479 36,595
Transportation:
Commercial 1,702 1,528 1,849 1,847 2,067
Industrial 12,154 12,375 11,872 12,491 12,247
Total 13,856 13,903 13,721 14,338 14,314
Total Throughput 50,463 52,475 53,279 50,817 50,909
Degree days ***
(% of normal) 90.7% 97.3% 101.1% 94.5% 100.4%
- -----------------------------
* 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 loads. 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 obtain 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 their system natural gas
requirements for the next five years.
Regulatory Matters --
On September 7, 2004, Great Plains filed an application with the
MPUC for a natural gas rate increase. Great Plains had requested
a total of $1.4 million annually or 4.0 percent above current
rates. Great Plains also requested an interim increase of $1.4
million annually. On November 23, 2004, the MPUC issued an Order
setting interim rates of $1.4 million annually effective with
service rendered on or after January 10, 2005, subject to refund.
A final order from the MPUC is expected in late 2005.
On June 7, 2004, Montana-Dakota filed an application with the
SDPUC for a natural gas rate increase for the Black Hills service
area. Montana-Dakota requested a total of $1.3 million annually
or 2.2 percent above current rates. On November 15, 2004,
Montana-Dakota and the SDPUC Staff filed a Settlement Stipulation
with the SDPUC agreeing to an increase of $670,000 annually, or
1.4 percent. On November 30, 2004, the SDPUC approved the
Settlement Stipulation effective with service rendered on or
after December 1, 2004.
On April 1, 2004, Montana-Dakota filed an application with the
MTPSC for a natural gas rate increase. Montana-Dakota requested
a total of $1.5 million annually or 1.8 percent above current
rates. On January 14, 2005, Montana-Dakota and the Montana
Consumer Counsel filed a Stipulation with the MTPSC agreeing to
an increase of $125,000 annually to be effective with service
rendered on or after February 1, 2005. On January 25, 2005, the
MTPSC passed a Motion approving the Stipulation.
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.
Montana-Dakota's North Dakota and South Dakota-Black Hills area
gas tariffs contain a Distribution Delivery Stabilization
Mechanism applicable to the firm rate schedules to correct for
the over/under collection of distribution delivery charge
revenues due to weather fluctuations during the billing period
from November 1 through May 1.
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 2004 and do not expect to incur any
material capital expenditures related to environmental compliance
with current laws and regulations through 2007.
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, 2004,
Utility Services owned or leased offices in 14 states. This
space is used for offices, equipment yards, warehousing, storage
and vehicle shops. At December 31, 2004, Utility Services' net
plant investment was approximately $43.3 million.
Utility Services' 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 December 31, 2004,
was approximately $238 million compared to $148 million at
December 31, 2003. Utility Services expects to complete a
significant amount of this backlog during the year ending
December 31, 2005. Due to the nature of its contractual
arrangements, in many instances Utility Services' customers are
not committed to the specific volumes of services to be purchased
under a contract, but rather Utility Services 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 Utility Services 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 lineworkers in
certain areas. Utility Services works with the National
Electrical Contractors Association and the IBEW on hiring and
recruiting qualified lineworkers.
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 Utility Services 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 2004 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2007.
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. 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 and from
Canada. At December 31, 2004, Williston Basin's net plant
investment was approximately $215.8 million. Under the Natural
Gas Act, as amended, Williston Basin is subject to the
jurisdiction of the FERC regarding certificate, rate, service and
accounting matters.
WBI Holdings, through its nonregulated pipeline business, owns
and operates gathering facilities in Colorado, Kansas, Montana
and Wyoming. A one-sixth interest in the assets of various
offshore gathering pipelines and associated onshore pipeline and
related processing facilities also is owned by WBI Holdings.
These facilities include over 1,600 miles of field gathering
lines and 79 owned or leased compression facilities, some of
which interconnect with Williston Basin's system. In addition,
WBI Holdings provides installation sales and/or leasing of
alternate energy delivery systems, primarily propane air
facilities, 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, producers, 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. WBI Holdings currently
estimates that it can adequately meet the requirements of these
contracts. WBI Holdings transacts a significant portion of its
business in the northern Great Plains and Rocky Mountain regions
of the United States.
Another energy services business owned by WBI Holdings is
Innovatum, Inc. (Innovatum), a cable and pipeline magnetization
and locating company. Innovatum provides products and services
that assist the natural gas and oil and telecommunication
industries with accurate location and tracking of submerged
pipelines and cables on a worldwide basis. Additionally,
Innovatum manufactures and resells a line of terrestrial, hand-
held locators that are used for locating and identifying
underground objects. Innovatum has 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.
System Demand and Competition --
Williston Basin competes with several pipelines for its
customers' transportation, storage and gathering 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, serve 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, 2004, represented 68 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 an
estimated 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 certain 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 - MD&A - 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, gathering and storage
services through system expansion and/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.
In July 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. In August 2003, Williston Basin
requested 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 May 11, 2004, the FERC issued an Order
on Rehearing and Compliance and Remanding Certain Issues for
Hearing (Order on Rehearing). The Order on Rehearing denied
rehearing on all of the issues addressed by Williston Basin in
its August 2003 request for rehearing except for the issue of the
proper rate to utilize for transmission system negative salvage
expenses. In addition, the FERC remanded the issues regarding
certain service and annual demand quantity restrictions to an ALJ
for resolution. On June 14, 2004, Williston Basin requested
clarification of a few of the issues addressed in the Order on
Rehearing including determinations associated with cost of
service and cost allocation, as discussed in the FERC's Order on
Rehearing. On June 14, 2004, Williston Basin also made its
filing to comply with the requirements of the various FERC orders
in this proceeding. Williston Basin is awaiting a decision from
the FERC on Williston Basin's compliance filing and clarification
request but is unable to predict the timing of the FERC's
decision. Williston Basin participated in a hearing before the
ALJ in early January 2005, regarding the matters remanded to the
ALJ by the FERC in its Order on Rehearing and an order on these
matters is expected in 2005.
A liability has 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 the liability is 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 FERC's
permitting processes for both the construction and abandonment of
Williston Basin's natural gas transmission pipelines and storage
facilities.
WBI Holdings' pipeline and energy services' operations did not
incur any material environmental expenditures in 2004 and does
not expect to incur any material capital expenditures related to
environmental compliance with current laws and regulations
through 2007.
NATURAL GAS AND OIL PRODUCTION
General --
Fidelity Exploration & Production Company (Fidelity), a direct
wholly owned subsidiary of WBI Holdings, is involved in the
acquisition, exploration, development and production of natural
gas and oil resources. Fidelity's activities include the
acquisition of producing properties with potential development
opportunities, exploratory drilling and the operation and
development of natural gas production properties. Fidelity
shares revenues and expenses from the development of specified
properties located primarily in the Rocky Mountain region of the
United States and in 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, 2004.
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 2004, 2003 and 2002, are as
follows:
2004 2003 2002
Natural Gas:
Production (MMcf) 59,750 54,727 48,239
Average realized price
(including hedges) $ 4.69 $ 3.90 $ 2.72
Average realized price
(excluding hedges) $ 4.90 $ 4.28 $ 2.54
Oil:
Production (000's of barrels) 1,747 1,856 1,968
Average realized price
(including hedges) $34.16 $27.25 $22.80
Average realized price
(excluding hedges) $37.75 $28.42 $23.26
Production costs, including taxes,
per net equivalent Mcf:
Lease operating costs $ .47 $ .48 $ .46
Gathering and transportation .17 .22 .20
Production and property taxes .32 .32 .21
$ .96 $ 1.02 $ .87
Well and Acreage Information --
Gross and net productive well counts and gross and net developed
and undeveloped acreage related to interests at December 31,
2004, are as follows:
Gross Net
Productive Wells:
Natural Gas 2,975 2,419
Oil 2,223 123
Total 5,198 2,542
Developed Acreage (000's) 791 350
Undeveloped Acreage (000's) 1,391 614
Exploratory and Development Wells --
The following table reflects activities relating to Fidelity's
natural gas and oil wells drilled and/or tested during 2004, 2003
and 2002:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
2004 1 4 5 230 20 250 255
2003 10 2 12 274 2 276 288
2002 4 --- 4 201 --- 201 205
At December 31, 2004, there were 147 gross wells in the process
of drilling or under evaluation, 144 of which were development
wells and three of which were exploratory wells. These wells are
not included in the previous table. Fidelity expects to complete
drilling and testing the majority of these wells within the next
12 months.
Competition --
The natural gas and oil industry is highly competitive. Fidelity
competes with a substantial number of major and independent
natural gas and oil companies in acquiring producing properties
and new leases for future exploration and development, and in
securing the equipment and expertise necessary to develop and
operate its properties. Many of Fidelity's competitors have
greater financial and operational resources than Fidelity.
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 2004, capital expenditures for water
handling in compliance with current laws and regulations were
approximately $400,000 and are estimated to be less than
$3.5 million in 2005 and less than $3.0 million per year for 2006
and 2007. For information regarding coalbed natural gas legal
proceedings, see Item 3 -- Legal Proceedings, Item 7 - MD&A -
Risk Factors and Cautionary Statements that May Affect Future
Results - Environmental and Regulatory Risks and Item 8 --
Financial Statements and Supplementary Data - Note 18.
Reserve Information --
Fidelity's recoverable proved developed and undeveloped natural
gas and oil reserves approximated 453.2 Bcf and 17.1 million
barrels, respectively, at December 31, 2004.
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
General --
Knife River operates construction materials and mining businesses
in Alaska, California, Hawaii, Idaho, 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 2004, the Company acquired several construction materials
and mining businesses with operations in Hawaii, Idaho, Iowa and
Minnesota. 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 May
31, 2005. 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 $426
million in backlog at December 31, 2004, compared to $332 million
at December 31, 2003. The Company anticipates that a significant
amount of the current backlog will be completed during the year
ending December 31, 2005.
Competition --
Knife River's construction materials products are marketed under
highly competitive conditions. Because 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 that
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 effect 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 also
are 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 1.3 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, 2004, and sales as of and for the years ended
December 31, 2004, 2003 and 2002:
Number Number
of Sites of Sites Estimated Reserve
Production (Crushed Stone) (Sand & Gravel) Tons Sold (000's) Reserves Lease Life
Area owned leased owned leased 2004 2003 2002 (000's tons) Expiration (years)
Central MN --- 1 52 60 6,429 6,265 6,236 112,668 2005-2028 18
Portland, OR 1 4 5 3 5,821 4,610 4,186 271,826 2005-2055 47
Northern CA 1 --- 7 1 3,699 3,907 3,430 58,269 2046 16
Southwest OR 3 6 11 3 3,405 3,360 2,812 103,990 2005-2031 31
Eugene, OR 3 3 4 2 2,003 1,442 2,724 185,651 2006-2046 93
Hawaii --- 6 --- --- 2,460 2,134 2,688 77,170 2011-2037 31
Central MT --- --- 5 1 2,555 2,667 2,463 37,440 2011-2023 15
Anchorage, AK --- --- 1 --- 1,473 1,610 1,719 23,280 N/A 16
Northwest MT --- --- 8 5 1,810 1,413 1,260 29,886 2005-2020 17
Southern CA --- 2 --- --- 518 1,945 1,247 95,809 2035 185
Bend, OR/
Boise, ID 1 2 4 1 1,678 857 1,030 78,454 2010-2012 47
Northern MN 2 --- 21 20 853 873 559 33,825 2005-2016 40
Northern IA/
Southern MN 18 10 8 26 1,370 --- --- 70,838 2005-2017 52
North/South
Dakota --- --- 2 59 965 704 --- 59,192 2005-2031 61
Eastern TX --- 3 --- 3 1,067 449 --- 18,215 2005-2012 17
Casper, WY --- --- --- 1 291 172 61 985 2006 3
Sales from
other sources 7,047 6,030 4,663 ---
43,444 38,438 35,078 1,257,498
The 1.3 billion tons of estimated aggregate reserves at
December 31, 2004, is comprised of 562 million tons that are
owned and 696 million tons that are leased. The leases have
various expiration dates ranging from 2005 to 2055.
Approximately 58 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 2004 sales from
leased reserves, the average time necessary to produce remaining
aggregate reserves from such leases is approximately 46 years.
The following table summarizes Knife River's aggregate reserves
at December 31, 2004, 2003 and 2002 and reconciles the changes
between these dates:
2004 2003 2002
(000's of tons)
Aggregate Reserves:
Beginning of year 1,181,413 1,110,020 1,065,330
Acquisitions 115,965 109,362 72,808
Sales volumes* (36,397) (32,408) (30,415)
Other (3,483) (5,561) 2,297
End of year 1,257,498 1,181,413 1,110,020
- -----------------------------
* Excludes sales from other sources.
Lignite Deposits --
The Company has lignite deposits and leases at its former
Gascoyne Mine site in North Dakota. These lignite deposits are
currently not being mined and are not associated with an
operating mine. The 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, 2004, Knife River had under ownership or lease,
deposits of approximately 11.4 million tons of recoverable
lignite coal.
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 also are 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 also are subject to RCRA as it applies to
underground storage tanks and the management of petroleum
hydrocarbon products and wastes. These programs also have
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
Corps 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 also are 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 also are 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 10-year revegetation liability period
under SMCRA.
Knife River did not incur any material environmental expenditures
in 2004 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 2007.
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.
INDEPENDENT POWER PRODUCTION
General --
Centennial Resources owns, builds and operates electric
generating facilities in the United States and has investments in
domestic and international natural resource-based projects.
Electric capacity and energy produced at its power plants are
sold primarily under mid- and long-term contracts to
nonaffiliated entities.
Competition --
Centennial Resources encounters competition in the development of
new electric generating plants and the acquisition of existing
generating facilities, as well as operation and maintenance
services. Competitors include 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. Factors for competing in the
power production industry include having a balanced portfolio of
generating assets, fuel types, customers and power sales
agreements and maintaining low production costs.
Domestic:
Centennial Power, Inc. (Centennial Power), an indirect wholly
owned subsidiary of the Company, owns 213 megawatts of natural
gas-fired electric generating facilities (Brush Generating
Facility) near Brush, Colorado. These facilities were purchased
in November 2002. Ninety-five percent of the Brush Generating
Facility's output is sold to Public Service of Colorado (PSCO), a
wholly owned subsidiary of Xcel Energy, under two power purchase
contracts that expire in October 2005 and September 2012,
respectively. The Brush Generating Facility is operated by
Colorado Energy Management (CEM), an indirect wholly owned
subsidiary of the Company. PSCO is under contract to supply
natural gas to the Brush Generating Facility during the terms of
the power purchase contracts.
Centennial Power owns a 66.6-megawatt wind-powered electric
generating facility located in the San Gorgonio Pass, northwest
of Palm Springs, California. This facility was purchased in
January 2003. The facility sells all of its output under a
contract with the California Department of Water Resources, which
expires in September 2011. SeaWest Wind Power, Inc. (SeaWest) is
under a contract to operate the facility. The contract with
SeaWest expires in October 2013.
On September 28, 2004, Centennial Resources, through wholly owned
subsidiaries, acquired a 50-percent ownership in a 310-megawatt
natural gas-fired electric generating facility (Hartwell
Generating Facility). This facility is located in Hartwell,
Georgia. The Hartwell Generating Facility sells its output under
a power purchase agreement with Oglethorpe Power Corporation
(Oglethorpe) that expires in May 2019. American National Power,
a wholly owned subsidiary of International Power of the United
Kingdom, holds the remaining 50-percent ownership interest and is
the operating partner for the facility.
On April 16, 2004, Centennial Resources purchased CEM. CEM
provides analysis, design, construction, refurbishment, and
operation and maintenance services to independent power
producers. CEM is headquartered in Lafayette, Colorado. CEM
provides operations and maintenance services for third-party
customers owning approximately 510 megawatts of generating
capacity at January 1, 2005. The operation and maintenance
contracts have expirations ranging from January 2006 to June 2009.
Environmental Matters --
Centennial Power has several operations that require federal and
state environmental permits. The Brush Generating Facility and
the Hartwell Generating Facility 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. Centennial Power believes it is
in substantial compliance with these regulations.
The Brush Generating Facility has a Title V Operating Permit
issued by the state for a period of five years under a program
approved by the EPA. The facility 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
Generating Facility is operating in compliance with the
agreement.
The Hartwell Generating Facility has a Title V Operating Permit
issued by the state for a period of five years under a program
approved by the EPA. Centennial Power believes it is in
substantial compliance with these regulations.
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 2004 and does not expect to incur any material
capital expenditures related to environmental compliance with
current laws and regulations through 2007 in connection with its
existing operations.
Other --
Centennial Resources is constructing a 116-megawatt coal-fired
electric generating facility near Hardin, Montana. A power sales
agreement with Powerex Corp., a subsidiary of BC Hydro, has been
secured for the entire output of the plant for a term expiring
October 31, 2008, with the purchaser having an option for a two-
year extension. The projected on-line date for this plant is
late 2005. For additional information regarding this plant, see
Item 7 -- MD&A - Prospective Information - Independent power
production.
International:
MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned Brazilian
subsidiary of the Company, is party to 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 and coal mining projects in
Brazil. MDU Brasil has a 49-percent interest in MPX. MPX,
through a wholly owned subsidiary, owns and operates a 220-
megawatt natural gas-fired electric generating facility
(Termoceara Generating Facility) in the Brazilian state of Ceara.
The first phase of the Termoceara Generating Facility entered
commercial operations in July 2002. The second phase entered
commercial operations in January 2003. Petrobras, the Brazilian
state-controlled energy company, entered into a contract to
purchase all of the capacity and market all of the energy from
the Termoceara Generating Facility. The first phase of the
electric power sales contract with Petrobras for 110 megawatts
expires in November 2007 and the portion of the contract for the
remaining 110 megawatts expires in May 2008. Petrobras also is
under contract to supply natural gas to the Termoceara Generating
Facility during the term of the electric power sales contract.
This natural gas supply contract is renewable by a wholly owned
subsidiary of MPX for an additional 13 years. The Termoceara
Generating Facility generates electricity based upon economic
dispatch and available gas supplies. Under current conditions,
including, in particular, existing constraints in the region's
gas supply infrastructure, the Company does not expect the
facility to generate a significant amount of energy at least
through 2006. For information regarding any potential effect
from recent events related to the Brazilian electric power sales
contract, see Item 8 -- Financial Statements and Supplementary
Data - Note 2.
On February 26, 2004, Centennial Energy Resources International,
Inc. (Centennial International), an indirect wholly owned
subsidiary of the Company, acquired 49.99 percent of Carib Power
Management LLC (Carib Power). Carib Power, through a wholly
owned subsidiary, owns a 225-megawatt natural gas-fired electric
generating facility located in Trinidad and Tobago (Trinity
Generating Facility). The Trinity Generating Facility sells its
output to the Trinidad and Tobago Electric Commission (T&TEC),
the governmental entity responsible for the transmission,
distribution and administration of electrical power to the
national electrical grid of Trinidad and Tobago. The power
purchase agreement expires in September 2029. T&TEC also is
under contract to supply natural gas to the Trinity Generating
Facility during the term of the power purchase contract.
For additional information regarding international operations,
see Item 7 -- MD&A - Risk Factors and Cautionary Statements that
May Affect Future Results - Risks Relating to Foreign Operations.
Environmental Matters --
The Termoceara Generating Facility is subject to all Brazilian
federal and state 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 2004
and does not expect to incur any material capital expenditures
related to environmental compliance with current laws and
regulations through 2007.
The Trinity Generating Facility has been designed to comply with
Trinidad and Tobago environmental requirements. The facility
operates in documented conformance with these applicable
environmental regulations and permit requirements. Trinity
Generating Facility is in material compliance with all applicable
environmental regulations and permit requirements.
The Trinity Generating Facility did not incur any material
environmental expenditures in 2004 and does not expect to incur
any material capital expenditures related to environmental
compliance with current laws and regulations through 2007.
ITEM 3. LEGAL PROCEEDINGS
In June 1997, Jack J. Grynberg (Grynberg) filed suit under the
Federal False Claims Act 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.
On June 4, 2004, following preliminary discovery, Williston Basin
and Montana-Dakota joined with other defendants and filed a
Motion to Dismiss on the grounds that the information upon which
Grynberg based his complaint was publicly disclosed prior to the
filing of his complaint and further, that he is not the original
source of such information. The Motion to Dismiss is
additionally based on the grounds that Grynberg disclosed the
filing of the complaint prior to the entry of a court order
allowing such disclosure and that Grynberg failed to provide
adequate information to the government prior to filing suit.
In the event the Motion to Dismiss is not granted, it is expected
that further discovery will follow. Williston Basin and Montana-
Dakota believe Grynberg will not prevail in the suit or recover
damages from Williston Basin and/or Montana-Dakota because
insufficient facts exist to support the allegations. Williston
Basin and Montana-Dakota believe Grynberg's claims are without
merit and intend to vigorously contest this suit.
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.
Fidelity has been named as a defendant in, and/or certain of its
operations are or have been the subject of, more than a dozen
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 November 2004 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. Portions of 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, the National Environmental Policy Act, the
Federal Land Management Policy Act, the National Historic
Preservation Act and the Montana Environmental Policy Act. The
cases involving alleged violations of the Federal Clean Water Act
have been resolved without a finding that Fidelity is in
violation of the Federal Clean Water Act. There presently are no
claims pending for penalties, fines or damages under the Federal
Clean Water Act. The suits that remain extant include a variety
of claims that state and federal government agencies violated
various environmental laws that impose procedural requirements
and the lawsuits seek injunctive relief, invalidation of various
permits and unspecified damages. Fidelity is unable to quantify
the damages sought in any of these cases, and will be unable to
do so until after completion of discovery in these separate
cases. 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 Health Department in
September 2003 that the North Dakota Health 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 North
Dakota Health 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 in October
2003, in the Burleigh County District Court in Bismarck, North
Dakota. Proceedings have been stayed pending discussions with
the EPA, the North Dakota Health Department and the other
electric generators.
In a related matter, the state of North Dakota and the EPA
entered into a Memorandum of Understanding (MOU) on February 24,
2004, establishing the principles to be used by the state of
North Dakota in completing dispersion modeling of air quality in
Theodore Roosevelt National Park and other "Class I" areas in
North Dakota and Montana. In April 2004, the Dakota Resource
Council filed a petition for review of the MOU with the United
States Eighth Circuit Court of Appeals. The petition was
dismissed, without prejudice, in June 2004 upon stipulation of
the EPA, the Dakota Resource Council and the state of North
Dakota. The Company cannot predict the outcome of the North
Dakota Health Department or Dakota Resource Council matters or
their ultimate impact on its operations.
In December 2000, MBI 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 - 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 2004.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY
SECURITIES
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 2004 and 2003 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High)* (Low)* Per Share*
2004
First Quarter $ 24.35 $ 22.67 $ .17
Second Quarter 24.03 21.85 .17
Third Quarter 26.43 23.72 .18
Fourth Quarter 27.70 25.20 .18
$ .70
2003
First Quarter $ 18.87 $ 16.41 $ .16
Second Quarter 22.66 18.55 .16
Third Quarter 23.32 20.37 .17
Fourth Quarter 24.35 22.23 .17
$ .66
__________________________
* Reflects the Company's three-for-two common stock split
effected in October 2003.
As of December 31, 2004, the Company's common stock was held by
approximately 15,200 stockholders of record.
ITEM 6. SELECTED FINANCIAL DATA
MDU RESOURCES GROUP, INC.
OPERATING STATISTICS
2004 2003 2002 2001 2000 1999
Selected Financial Data
Operating revenues (000's):
Electric $ 178,803 $ 178,562 $ 162,616 $ 168,837 $ 161,621 $ 154,869
Natural gas distribution 316,120 274,608 186,569 255,389 233,051 157,692
Utility services 426,821 434,177 458,660 364,750 169,382 99,917
Pipeline and energy services 357,229 252,192 165,258 531,114 636,848 383,532
Natural gas and oil production 342,840 264,358 203,595 209,831 138,316 78,394
Construction materials and mining 1,322,161 1,104,408 962,312 806,899 631,396 469,905
Independent power production 43,059 32,261 2,998 --- --- ---
Other 4,423 2,728 3,778 --- --- ---
Intersegment eliminations (272,199) (191,105) (114,249) (113,188) (96,943) (64,500)
$2,719,257 $2,352,189 $2,031,537 $2,223,632 $1,873,671 $1,279,809
Operating income (000's):
Electric $ 26,776 $ 35,761 $ 33,915 $ 38,731 $ 38,743 $ 35,727
Natural gas distribution 1,820 6,502 2,414 3,576 9,530 6,688
Utility services (5,757) 12,885 13,980 25,199 16,606 11,518
Pipeline and energy services 24,690 35,155 39,091 30,368 28,782 40,627
Natural gas and oil production 178,897 118,347 85,555 103,943 66,510 26,845
Construction materials and mining 86,030 91,579 91,430 71,451 56,816 38,346
Independent power production 8,126 10,610 (1,176) --- --- ---
Other 136 1,233 908 --- --- ---
$ 320,718 $ 312,072 $ 266,117 $ 273,268 $ 216,987 $ 159,751
Earnings on common stock (000's):
Electric $ 12,790 $ 16,950 $ 15,780 $ 18,717 $ 17,733 $ 15,973
Natural gas distribution 2,182 3,869 3,587 677 4,741 3,192
Utility services (5,650) 6,170 6,371 12,910 8,607 6,505
Pipeline and energy services 8,944 18,158 19,097 16,406 10,494 20,972
Natural gas and oil production 110,779 70,767* 53,192 63,178 38,574 16,207
Construction materials and mining 50,707 54,261* 48,702 43,199 30,113 20,459
Independent power production 26,309 11,415 307 --- --- ---
Other 321 606 652 --- --- ---
Earnings on common stock before
cumulative effect of accounting change 206,382 182,196* 147,688 155,087 110,262 83,308
Cumulative effect of accounting change --- (7,589) --- --- --- ---
$ 206,382 $ 174,607 $ 147,688 $ 155,087 $ 110,262 $ 83,308
Earnings per common share before cumulative
effect of accounting change -- diluted $ 1.76 $ 1.62* $ 1.38 $ 1.52 $ 1.20 $ 1.01
Cumulative effect of accounting change --- (.07) --- --- --- ---
$ 1.76 $ 1.55 $ 1.38 $ 1.52 $ 1.20 $ 1.01
Pro forma amounts assuming retroactive
application of accounting change:
Net income (000's) $ 207,067 $ 182,913 $ 146,052 $ 152,933 $ 108,951 $ 82,932
Earnings per common share -- diluted $ 1.76 $ 1.62 $ 1.36 $ 1.49 $ 1.17 $ 1.00
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 117,411 112,460 106,863 101,803 92,085 82,306
Dividends per common share $ .7000 $ .6600 $ .6266 $ .6000 $ .5733 $ .5467
Book value per common share $ 14.09 $ 12.66 $ 11.56 $ 10.60 $ 9.03 $ 7.83
Market price per common share (year end) $ 26.68 $ 23.81 $ 17.21 $ 18.77 $ 21.67 $ 13.33
Market price ratios:
Dividend payout 40% 43% 45% 39% 48% 54%
Yield 2.7% 2.9% 3.7% 3.3% 2.7% 4.2%
Price/earnings ratio 15.2x 15.4x 12.5x 12.3x 18.1x 13.2x
Market value as a percent of book value 189.4% 188.1% 148.8% 177.0% 239.9% 170.4%
Profitability Indicators
Return on average common equity 13.2% 13.0% 12.5% 15.3% 14.3% 13.9%
Return on average invested capital 9.4% 8.9% 8.6% 10.1% 9.5% 9.6%
Interest coverage 7.1x 7.4x 7.7x 8.5x 8.3x 7.1x
Fixed charges coverage, including
preferred dividends 4.7x 4.7x 4.8x 5.3x 4.1x 4.3x
General
Total assets (000's) $3,733,521 $3,380,592 $2,996,921 $2,675,978 $2,358,981 $1,806,648
Long-term debt, net of current
maturities (000's) $ 873,441 $ 939,450 $ 819,558 $ 783,709 $ 728,166 $ 563,545
Redeemable preferred stock (000's) $ --- $ --- $ 1,300 $ 1,400 $ 1,500 $ 1,600
Capitalization ratios:
Common equity 65% 60% 60% 58% 54% 54%
Preferred stocks 1 1 1 1 1 1
Long-term debt, net of current maturities 34 39 39 41 45 45
100% 100% 100% 100% 100% 100%
<FN>
* Before cumulative effect of the change in accounting for asset retirement obligations required by the adoption of
SFAS No. 143, "Accounting for Asset Retirement Obligations," as discussed in Item 8 -- Financial Statements and
Supplementary Data - Notes 1 and 8.
NOTE: Common stock share amounts reflect the Company's three-for-two common stock split effected in October 2003.
</FN>
2004 2003 2002 2001 2000 1999
Electric
Retail sales (thousand kWh) 2,303,460 2,359,888 2,275,024 2,177,886 2,161,280 2,075,446
Sales for resale (thousand kWh) 821,516 841,637 784,530 898,178 930,318 943,520
Electric system summer generating and firm
purchase capability -- kW
(Interconnected system) 544,220 542,680 500,570 500,820 500,420 492,800
Demand peak -- kW
(Interconnected system) 470,470 470,470 458,800 453,000 432,300 420,550
Electricity produced (thousand kWh) 2,552,873 2,384,884 2,316,980 2,469,573 2,331,188 2,350,769
Electricity purchased (thousand kWh) 794,829 929,439 857,720 792,641 948,700 860,508
Average cost of fuel and purchased
power per kWh $.019 $.019 $.018 $.018 $.016 $.016
Natural Gas Distribution
Sales (Mdk) 36,607 38,572 39,558 36,479 36,595 30,931
Transportation (Mdk) 13,856 13,903 13,721 14,338 14,314 11,551
Weighted average degree days --
% of previous year's actual 94% 96% 109% 95% 113% 95%
Pipeline and Energy Services
Transportation (Mdk) 114,206 90,239 99,890 97,199 86,787 78,061
Gathering (Mdk) 80,527 75,861 72,692 61,136 41,717 19,799
Natural Gas and Oil Production
Production:
Natural gas (MMcf) 59,750 54,727 48,239 40,591 29,222 24,652
Oil (000's of barrels) 1,747 1,856 1,968 2,042 1,882 1,758
Average realized prices:
Natural gas (per Mcf) $ 4.69 $ 3.90 $ 2.72 $ 3.78 $ 2.90 $ 1.94
Oil (per barrel) $34.16 $27.25 $22.80 $24.59 $23.06 $15.34
Proved reserves:
Natural gas (MMcf) 453,200 411,700 372,500 324,100 309,800 268,900
Oil (000's of barrels) 17,100 18,900 17,500 17,500 15,100 14,700
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold) 43,444 38,438 35,078 27,565 18,315 13,981
Asphalt (tons sold) 8,643 7,275 7,272 6,228 3,310 2,993
Ready-mixed concrete (cubic yards sold) 4,292 3,484 2,902 2,542 1,696 1,186
Recoverable aggregate reserves (tons) 1,257,498 1,181,413 1,110,020 1,065,330 894,500 740,030
Coal (000's):
Sales (tons) ---* ---* ---* 1,171* 3,111 3,236
Lignite deposits (tons) 11,400* 26,910* 37,761* 56,012* 145,643 182,761
Independent Power Production**
Net generation capacity -- kW 279,600 279,600 213,000 --- --- ---
Electricity produced and sold (thousand kWh) 204,425 270,044 15,804 --- --- ---
<FN>
* Coal operations were sold effective April 30, 2001.
** Excludes equity method investments.
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview
This subsection of MD&A is an 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 MD&A
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
Prior to the fourth quarter of 2004, the Company reported 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. The independent power production and other operations did
not individually meet the criteria to be considered a reportable
segment. In the fourth quarter of 2004, the Company separated
independent power production as a reportable business segment due
to the significance of its operations. The Company's operations
are now conducted through seven reportable segments and all prior
period information has been restated to reflect this change.
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 investments in natural gas-
fired electric generating facilities in Brazil and Trinidad and
Tobago, as discussed in Item 8 -- Financial Statements and
Supplementary Data - Note 2.
The electric segment includes the electric generation,
transmission and distribution operations of Montana-Dakota. The
natural gas distribution segment includes the natural gas
distribution operations of Montana-Dakota and Great Plains Natural
Gas Co. The electric and natural gas distribution segments also
supply related value-added products and services in the northern
Great Plains. The utility services segment includes all the
operations of Utility Services, Inc., which 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 includes WBI Holdings' 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 includes WBI Holdings' natural gas and oil acquisition,
exploration, development and production operations, primarily in
the Rocky Mountain region of the United States and in and around
the Gulf of Mexico. The construction materials and mining segment
includes the results of Knife River, which 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 operations of Centennial Resources owns, builds and
operates electric generating facilities in the United States and
has investments in electric generating facilities in Brazil,
Trinidad and Tobago, and the United States. Electric capacity and
energy produced at its power plants are sold primarily under mid-
and long-term contracts to nonaffiliated entities.
Excluding the asset impairments at the pipeline and energy
services segment of $5.3 million (after tax), 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, independent power production,
and other are all from nonregulated operations.
The Company's strategy is to apply its expertise in energy and
transportation infrastructure industries to increase market share
through internal growth along with acquisition of well-managed
companies and development of projects that enhance shareholder
value and are accretive to earnings per share and returns on
invested capital.
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 2004 were $387 million and are estimated to be
approximately $445 million for 2005.
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 experiences
fluctuations in average natural gas and oil prices. 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.
- Economic volatility both domestically and in the foreign
countries where the Company does business affects the Company's
operations as well as the demand for its products and services
and, as a result, may have a negative impact on the Company's
future revenues.
- 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, more than a dozen 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 summarizes the contribution to consolidated
earnings by each of the Company's businesses.
Years ended December 31, 2004 2003 2002
(Dollars in millions, where applicable)
Electric $ 12.8 $ 16.9 $ 15.8
Natural gas distribution 2.2 3.9 3.6
Utility services (5.6) 6.2 6.4
Pipeline and energy services 8.9 18.2 19.1
Natural gas and oil production 110.8 63.0 53.2
Construction materials and mining 50.7 54.4 48.7
Independent power production 26.3 11.4 .3
Other .3 .6 .6
Earnings on common stock $ 206.4 $ 174.6 $ 147.7
Earnings per common share - basic $ 1.77 $ 1.57 $ 1.39
Earnings per common share - diluted $ 1.76 $ 1.55 $ 1.38
Return on average common equity 13.2% 13.0% 12.5%
2004 compared to 2003
Consolidated earnings for 2004 increased $31.8 million from the
comparable prior period. The earnings increase was largely the
result of:
- Higher natural gas prices of 20 percent and higher oil prices
of 25 percent at the natural gas and oil production business
- Increased natural gas production of 9 percent at the natural
gas and oil production business
- Higher net income of $14.8 million from the Company's share
of its equity method investment in Brazil
- Favorable resolution of federal and related state income tax
matters of $8.3 million, including interest
- The absence in 2004 of a noncash transition charge in 2003 of
$7.6 million (after tax), reflecting the cumulative effect of an
accounting change, as discussed in Item 8 -- Financial Statements
and Supplementary Data - Notes 1 and 8
Partially offsetting the increase were:
- Higher operation and maintenance expense including payroll,
severance-related expenses, pension costs, higher fuel costs of
which a significant portion was not recovered through higher
prices at the construction materials and mining business, as well
as costs associated with adverse weather at the Texas construction
materials and mining business
- Lower inside electrical margins at the utility services
business, including the effect of losses on a few large jobs of
$5.8 million (after tax)
- A $4.0 million (before and after tax) noncash goodwill
impairment relating to the Company's cable and pipeline
magnetization and location business, as well as a $1.3 million
(after tax) adjustment reflecting the reduction in value of
certain gathering facilities in the Gulf Coast region
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 business
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 method investment in Brazil
- Increased earnings at the natural gas and oil production
business 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, as discussed
in Item 8 -- Financial Statements and Supplementary Data - Note
18, and the $12.7 million ($7.7 million after tax) noncash
transition charge in 2003, reflecting the cumulative effect of an
accounting change, as previously discussed, and higher
depreciation, depletion and amortization expense
- Higher earnings 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
- Increased earnings at the natural gas distribution business
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
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 were a
reflection of the continuing effects of the soft economy and the
downturn in the telecommunications market.
Financial and Operating Data
The following tables are key financial and operating statistics
for each of the Company's businesses.
Electric
Years ended December 31, 2004 2003 2002
(Dollars in millions, where applicable)
Operating revenues $178.8 $178.6 $162.6
Operating expenses:
Fuel and purchased power 64.6 62.0 56.0
Operation and maintenance 59.0 52.9 46.0
Depreciation, depletion and
amortization 20.2 20.2 19.6
Taxes, other than income 8.2 7.7 7.1
152.0 142.8 128.7
Operating income $ 26.8 $ 35.8 $ 33.9
Retail sales (million kWh) 2,303.5 2,359.9 2,275.0
Sales for resale (million kWh) 821.5 841.6 784.6
Average cost of fuel and
purchased power per kWh $ .019 $ .019 $ .018
2004 compared to 2003
Electric earnings decreased $4.1 million (25 percent) compared to
the prior year, largely as a result of the following:
- An increase in operation and maintenance expense of
$3.7 million (after tax) due primarily to increased payroll,
severance-related and pension expenses
- Lower retail sales margins largely the result of decreased
retail sales volumes of 2.4 percent, primarily the result of lower
residential sales volumes due to cooler summer weather
Partially offsetting the decrease in earnings was a favorable
resolution of federal and related state income tax matters of
$1.7 million (after tax), including interest.
2003 compared to 2002
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
Partially offsetting the earnings increase were:
- 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
Natural Gas Distribution
Years ended December 31, 2004 2003 2002
(Dollars in millions, where applicable)
Operating revenues:
Sales $311.5 $270.2 $182.5
Transportation and other 4.6 4.4 4.1
316.1 274.6 186.6
Operating expenses:
Purchased natural gas sold 251.1 211.1 132.9
Operation and maintenance 48.3 41.8 36.5
Depreciation, depletion and
amortization 9.4 10.0 9.9
Taxes, other than income 5.5 5.2 4.9
314.3 268.1 184.2
Operating income $ 1.8 $ 6.5 $ 2.4
Volumes (MMdk):
Sales 36.6 38.6 39.6
Transportation 13.9 13.9 13.7
Total throughput 50.5 52.5 53.3
Degree days (% of normal)* 90.7% 97.3% 101.1%
Average cost of natural gas,
including transportation
thereon, per dk $ 6.86 $ 5.47 $ 3.22
______________________________
* Degree days are a measure of the daily temperature-related
demand for energy for heating.
2004 compared to 2003
The natural gas distribution business experienced a decrease in
earnings of $1.7 million (44 percent) compared to the prior year.
The earnings decrease largely resulted from:
- Higher payroll, severance-related expenses, pension and other
operational expenses of $5.2 million (after tax)
- Decreased retail sales volumes of 5.1 percent, primarily
lower residential and commercial sales volumes as a result of 6
percent warmer weather compared to last year
Partially offsetting the decrease in earnings were:
- A favorable resolution of federal and related state income
tax matters of $3.0 million (after tax), including interest
- Higher retail sales prices, the result of rate increases
effective in South Dakota, North Dakota and Minnesota
The pass-through of higher natural gas prices is reflected in the
increase in both sales revenues and purchased natural gas sold.
2003 compared to 2002
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
- 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
- Higher income taxes in 2003
- Decreased returns on natural gas held in storage
- Lower retail sales volumes due to weather that was 4 percent
warmer than the comparable prior period
The pass-through of higher natural gas prices is reflected in the
increase in both sales revenues and purchased natural gas sold.
Utility Services
Years ended December 31, 2004 2003 2002
(Dollars in millions)
Operating revenues $426.8 $434.2 $458.7
Operating expenses:
Operation and maintenance 405.6 395.9 419.0
Depreciation, depletion and
amortization 11.1 10.3 9.9
Taxes, other than income 15.8 15.1 15.8
432.5 421.3 444.7
Operating income (loss) $ (5.7) $ 12.9 $ 14.0
2004 compared to 2003
Utility services experienced a $5.6 million loss compared to $6.2
million in earnings for the prior year. The earnings decrease was
attributable to:
- Decreased inside electrical margins, including the effect
of losses on a few large jobs of $5.8 million (after tax)
- Increased severance and other general and administrative
expenses of $3.6 million (after tax), including higher consulting
and legal fees as well as other outside service costs
The decrease in earnings was partially offset by increased line
construction margins.
2003 compared to 2002
Utility services earnings decreased slightly as a result of:
- Lower line construction workloads and margins in the
Southwest and Central regions
- Lower workloads and margins in the telecommunications
industry in the Rocky Mountain region
- Increased selling, general and administrative expenses
- Lower inside electrical workloads and margins in the Central
region
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)
- Higher line construction margins in the Northwest and Rocky
Mountain regions
Lower margins were a reflection of the continuing effects of the
soft economy in this sector and the downturn in the
telecommunications market.
Pipeline and Energy Services
Years ended December 31, 2004 2003 2002
(Dollars in millions)
Operating revenues:
Pipeline $ 87.2 $ 97.2 $ 95.3
Energy services 270.0 155.0 69.9
357.2 252.2 165.2
Operating expenses:
Purchased natural gas sold 249.8 149.5 58.3
Operation and maintenance 51.1 46.6 47.3
Depreciation, depletion and
amortization 17.8 15.0 14.8
Taxes, other than income 7.7 5.9 5.7
Asset impairments 6.1 --- ---
332.5 217.0 126.1
Operating income $ 24.7 $ 35.2 $ 39.1
Transportation volumes (MMdk):
Montana-Dakota 32.5 34.1 33.3
Other 81.7 56.1 66.6
114.2 90.2 99.9
Gathering volumes (MMdk) 80.5 75.9 72.7
2004 compared to 2003
Earnings at the pipeline and energy services business decreased
$9.3 million (51 percent) due largely to:
- A $4.0 million (before and after tax) noncash goodwill
impairment and a $1.3 million (after tax) asset valuation
adjustment, as previously discussed
- Increased operating costs of $5.3 million (after tax)
including costs associated with last year's expansion of pipeline
and gathering operations, as well as higher payroll-related costs
- Higher financing-related costs of $2.2 million (after tax)
- Lower average rates of $1.5 million (after tax), due in part
to the estimated effects of a FERC rate order received in July
2003 and rehearing order received in May 2004 which resulted in
lower rates effective July 1, 2004
Partially offsetting the decrease in earnings were:
- Increased natural gas transportation volumes of $3.5 million
(after tax), including:
- Higher volumes transported on the Grasslands Pipeline (which
began providing natural gas transmission service late in 2003)
- Higher natural gas volumes transported into storage which
were largely commodity price related
- A favorable resolution of federal and related state income
tax matters of $1.6 million (after tax), including interest
The increase in energy services revenues and the related increase
in purchased natural gas sold includes the effect of higher
natural gas prices and volumes since the comparable prior period.
2003 compared to 2002
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
- 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
Years ended December 31, 2004 2003 2002
(Dollars in millions, where applicable)
Operating revenues:
Natural gas $280.4 $213.5 $131.0
Oil 59.7 50.6 42.1
Other 2.8 .2 30.5*
342.9 264.3 203.6
Operating expenses:
Purchased natural gas sold 2.7 .1 .1
Operation and maintenance:
Lease operating costs 33.0 31.6 27.5
Gathering and transportation 11.6 14.7 12.3
Other 23.1 17.2 15.8
Depreciation, depletion and
amortization 70.8 61.0 48.7
Taxes, other than income:
Production and property
taxes 22.6 21.0 12.7
Other .2 .4 .9
164.0 146.0 118.0
Operating income $178.9 $118.3 $ 85.6
Production:
Natural gas (MMcf) 59,750 54,727 48,239
Oil (000's of barrels) 1,747 1,856 1,968
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 4.69 $ 3.90 $ 2.72
Oil (per barrel) $34.16 $27.25 $22.80
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.90 $ 4.28 $ 2.54
Oil (per barrel) $37.75 $28.42 $23.26
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .47 $ .48 $ .46
Gathering and transportation .17 .22 .20
Production and property taxes .32 .32 .21
$ .96 $ 1.02 $ .87
______________________________
*Includes the effects of a compromise agreement gain of
$27.4 million ($16.6 million after tax).
2004 compared to 2003
Natural gas and oil production earnings increased $47.8 million
(76 percent) due to:
- Higher average realized natural gas prices of 20 percent due
in part to the Company's ability to access higher and more stable-
priced markets for much of its operated natural gas production
through the recently constructed Grasslands Pipeline
- Higher natural gas production of 9 percent, largely the
result of drilling activity
- The absence in 2004 of a $12.7 million ($7.7 million after
tax) noncash transition charge in 2003, reflecting the cumulative
effect of an accounting change, as previously discussed
- Higher average realized oil prices of 25 percent
Partially offsetting the increase in earnings were:
- Higher depreciation, depletion and amortization expense of
$6.0 million (after tax) due to higher rates and higher natural
gas production volumes
- Higher general and administrative costs of $3.5 million
(after tax) due primarily to increased payroll-related expenses
and outside services
2003 compared to 2002
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
- 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
- Increased depreciation, depletion and amortization expense
due to higher natural gas production volumes and higher rates
- Higher lease operating expenses due in part to increased
natural gas production
- Higher general and administrative costs
- Decreased oil production of 6 percent
- Higher interest expense
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."
Construction Materials and Mining
Years ended December 31, 2004 2003 2002
(Dollars in millions)
Operating revenues $1,322.2 $1,104.4 $962.3
Operating expenses:
Operation and maintenance 1,132.3 924.2 797.7
Depreciation, depletion and
amortization 69.6 63.6 54.4
Taxes, other than income 34.3 25.0 18.8
1,236.2 1,012.8 870.9
Operating income $ 86.0 $ 91.6 $ 91.4
Sales (000's):
Aggregates (tons) 43,444 38,438 35,078
Asphalt (tons) 8,643 7,275 7,272
Ready-mixed concrete
(cubic yards) 4,292 3,484 2,902
2004 compared to 2003
Construction materials and mining earnings decreased $3.7 million
(7 percent) due to:
- Lower aggregate and construction margins of $10.5 million
(after tax) from existing operations largely as a result of:
- The absence of certain large projects reflected in 2003
results
- Wet weather which severely impacted operations in Texas
- Increased fuel costs of which a significant portion was not
recovered through higher prices
- Higher general and administrative expenses of $5.3 million
(after tax), including payroll-related costs, insurance and
professional services
Partially offsetting the decrease in earnings were:
- Increased ready-mixed concrete margins of $2.7 million (after
tax), largely as a result of higher sales volumes from existing
operations
- Earnings from companies acquired since the comparable prior
period contributed approximately 5 percent of earnings
2003 compared to 2002
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 prior
period
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
Independent Power Production
Years ended December 31, 2004 2003 2002
(Dollars in millions)
Operating revenues $43.1 $32.3 $ 3.0
Operating expenses:
Operation and maintenance 23.0 13.8 3.7
Depreciation, depletion and
amortization 9.6 7.9 .4
Taxes, other than income 2.4 --- ---
35.0 21.7 4.1
Operating income (loss) $ 8.1 $10.6 $(1.1)
Net generation capacity - kW* 279,600 279,600 213,000
Electricity produced and sold
(thousand kWh)* 204,425 270,044 15,804
______________________________
* Excludes equity method investments.
NOTE: The earnings from the Company's equity method investments
are not reflected in the above table.
2004 compared to 2003
Earnings for the independent power production business were
$26.3 million compared to $11.4 million in 2003. This increase
is largely due to:
- Higher net income of $14.8 million from the Company's share
of its equity method investment in Brazil due primarily to:
- Changes in value of the embedded derivative in the Brazilian
electric power sales contract, net of lower operating margins
resulting from the contract annual revenue reset provision, as
well as other foreign currency changes, totaling $8.5 million
(after tax)
- Lower financing costs of $4.8 million (after tax), largely
the result of obtaining low-cost, long-term financing for the
operation in mid-2003
- Earnings from acquisitions and equity method investments
acquired since the comparable prior period contributed
approximately 7 percent of earnings
For additional information regarding equity method investments,
see Item 8 -- Financial Statements and Supplementary Data -
Note 2.
2003 compared to 2002
Earnings for the independent power production business 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
- Higher net income of $3.7 million from the Company's share of
its equity method 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)
- Foreign currency gains from an increase in value of the
Brazilian Real
Partially offset by:
- The mark-to-market loss on an embedded derivative in the
electric power sales contract
- Higher interest expense due to a full year of debt in 2003
Other and Intersegment Transactions
Amounts presented in the preceding tables will not agree with the
Consolidated Statements of Income due to the Company's other
operations and the elimination of intersegment transactions. The
amounts relating to these items are as follows:
Years ended December 31, 2004 2003 2002
(In millions)
Other:
Operating revenues $ 4.4 $ 2.7 $ 3.8
Operation and maintenance 4.0 1.2 2.7
Depreciation, depletion and
amortization .3 .3 .3
Intersegment transactions:
Operating revenues $272.2 $191.1 $114.3
Purchased natural gas sold 253.7 176.5 98.8
Operation and maintenance 18.5 14.6 15.5
For further information on intersegment eliminations, see
Item 8 -- Financial Statements and Supplementary Data -
Note 13.
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 and pipeline and
energy services businesses are dependent on factors, including
commodity prices and commodity price basis differentials, which
cannot be predicted or controlled.
These factors include: price fluctuations in natural gas and
crude oil prices; fluctuations in commodity price basis
differentials; availability of economic supplies of natural gas;
drilling successes in natural gas and oil operations; the timely
receipt of necessary permits and approvals; 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. Significant
changes in these factors could negatively affect the results of
operations and financial condition of the Company's natural gas
and oil production and pipeline and energy services businesses.
The construction and operation of power generation facilities may
involve unanticipated changes or delays that could negatively
impact the Company's business and its results of operations.
The construction and 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. Such
unanticipated events could negatively impact the Company's
business and its results of operations.
The Company's utility services business operates in highly
competitive markets characterized by low margins in a number of
service lines and geographic areas.
This business' ability to return to profitability on a sustained
basis will depend upon improved capital spending for electric
construction services and management's ability to successfully
refocus the business on more profitable markets, reduce operating
costs and implement process improvements in project management.
Economic volatility affects the Company's operations as well as
the demand for its products and services and, as a result, may
have a negative impact on the Company's future revenues.
The global demand for natural resources, interest rates,
governmental budget constraints, and the ongoing threat of
terrorism can create volatility in the financial markets. 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.
The Company relies on financing sources and capital markets. If
the Company is unable to obtain 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 its 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 costs of
operations, impact or limit 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, and delays 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, a number of 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 delay and/or 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 Foreign Operations
The value of the Company's investments 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 an electric power sales contract 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.
Negotiations with Petrobras may impact the Company's future
earnings.
The Company's future earnings from its investment in Brazilian
power operations may be affected by the outcome of negotiations
between its 49 percent-owned investee, MPX, and Petrobras over
continuing payments by Petrobras under an electric power sales
contract covering capacity and energy associated with the
Termoceara Generating Facility.
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 production 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. The increase in competition could negatively affect the
Company's results of operations and financial condition.
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 and construction and
drilling activities for the pipeline and energy services and
natural gas and oil production businesses. In addition, severe
weather can be destructive, causing outages, reduced natural gas
and oil production, 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 2005, diluted, are projected in
the range of $1.70 to $1.90.
- - The Company expects the percentage of 2005 earnings per
common share, diluted, by quarter to be in the following
approximate ranges:
- First quarter - 10 percent to 15 percent
- Second quarter - 20 percent to 25 percent
- Third quarter - 37 percent to 42 percent
- Fourth quarter - 23 percent to 28 percent
- - These projections do not take into consideration any
potential effect from recent events related to the Brazilian
electric power sales contract. Excluding any such effects,
earnings estimated for 2005 from existing Brazilian operations are
in the range of 4 percent to 6 percent of consolidated earnings
for the Company. For further information regarding this matter,
see Item 8 -- Financial Statements and Supplementary Data - Note
2.
- - 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 anticipates investing approximately $445 million
in capital expenditures during 2005.
- - 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.
Electric
- - The expected earnings in 2005 are anticipated to be slightly
lower than 2004 earnings because of anticipated higher operation
and maintenance expenses primarily related to higher benefit
costs, and the absence of the favorable resolution of income tax
matters.
- - As part of the North Dakota Industrial Commission's Lignite
Vision 21 project, the Company submitted an air quality permit
application in May 2004 to construct a 175-megawatt coal-fired
plant at Gascoyne, N.D. The air permit application is now under
review at the North Dakota Health Department. This segment also
is involved in the review of other potential projects to replace
capacity associated with expiring purchased power contracts and to
provide for future growth. The costs of building and/or acquiring
the additional generating capacity needed by the utility are
expected to be recovered in rates.
- - 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.
Natural gas distribution
- - The expected earnings for this segment for 2005 are projected
to be somewhat higher than the earnings for 2004 primarily the
result of rate relief and the assumed return to normal weather,
which for 2004 was 9 percent warmer than normal.
- - In September 2004, a natural gas rate case was filed with the
MPUC requesting an increase of $1.4 million annually, or
4.0 percent. The Company requested an interim increase of
$1.4 million annually and in November 2004, the MPUC issued an
Order approving the requested interim increase effective January
10, 2005, subject to refund. A final order is expected in late
2005.
- - 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.
Utility services
- - Revenues are expected to be in the range of $440 million to
$490 million in 2005.
- - The Company anticipates margins to increase substantially in
2005 as compared to 2004 levels.
- - Work backlog as of December 31, 2004, was approximately
$238 million, compared to $148 million at December 31, 2003.
Pipeline and energy services
- - In 2005, total natural gas gathering and transportation
throughput is expected to increase approximately 5 percent to 10
percent over 2004 levels.
- - 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 and storage rate reductions due to the
estimated effects of a FERC rate order received in July 2003 and
rehearing order received in May 2004 have been reflected in the
Company's 2005 earnings projections.
Natural gas and oil production
- - The Company is expecting to drill up to 500 wells in 2005,
dependent on the timely receipt of regulatory approvals. Delays
in receipt of drilling permits are affecting producers throughout
the Rocky Mountain region.
- - In 2005, the Company expects a combined natural gas and oil
production increase of approximately 6 percent to 8 percent over
2004 levels. A portion of this increase is predicated on the
timely receipt of various regulatory approvals. Currently, this
segment's net combined natural gas and oil production is
approximately 185,000 Mcf equivalent to 195,000 Mcf equivalent per
day.
- - Estimates of natural gas prices in the Rocky Mountain region
for February through December 2005 reflected in the Company's 2005
earnings guidance are in the range of $4.25 to $4.75 per Mcf. The
Company's estimates for natural gas prices on the NYMEX for
February through December 2005, reflected in the Company's 2005
earnings guidance, are in the range of $5.00 to $5.50 per Mcf.
During 2004, more than three-fourths of this segment's natural gas
production was priced using Rocky Mountain or other non-NYMEX
prices.
- - Estimates of NYMEX crude oil prices for February through
December 2005, reflected in the Company's 2005 earnings guidance,
are projected in the range of $35 to $40 per barrel.
- - The Company has hedged a portion of its 2005 estimated
natural gas production. The Company has entered into agreements
representing approximately 35 percent to 40 percent of its 2005
estimated annual natural gas production. The agreements are at
various indices/prices and range from a low Ventura index of $4.75
to a high NYMEX price of $10.18 per Mcf. Ventura is an index
pricing point related to Northern Natural Gas Co.'s system.
- - This segment has hedged a portion of its 2005 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $30.70 and a high of $52.05 representing approximately 45
percent to 50 percent of its 2005 estimated annual oil production.
- - For 2005, the Company may hedge up to 70 percent of its
existing natural gas and oil production that qualifies for hedge
accounting, based on established pricing criteria.
Construction materials and mining
- - The Company anticipates improved earnings in 2005 with an
expected return to more normal weather conditions in Texas.
- - Aggregate, ready-mixed concrete and asphalt volumes in 2005
are expected to be comparable to 2004 levels.
- - Revenues in 2005 are expected to be comparable to 2004
levels.
- - The Company expects that the replacement funding legislation
for the TEA-21 will be equal to or higher than previous funding
levels.
- - Work backlog as of December 31, 2004, was approximately $426
million, compared to $332 million at December 31, 2003.
Independent power production
- - Earnings projections for 2005 are expected to be slightly
lower than 2004 earnings primarily due to benefits realized in
2004 from foreign currency gains and the effects of the embedded
derivative in the Brazilian electric power sales contract.
- - Earnings projections do not take into consideration any
potential effect from recent events related to the Brazilian
electric power sales contract.
- - The Company anticipates making an additional investment in an
international project in 2005 which is reflected in earnings
projections.
- - The Company is constructing a 116-megawatt coal-fired
electric generating facility near Hardin, Montana. A power sales
agreement with Powerex Corp., a subsidiary of BC Hydro, has been
secured for the entire output of the plant for a term expiring
October 31, 2008, with the purchaser having an option for a two-
year extension. The projected on-line date for this plant is late
2005.
New Accounting Standards
FIN 46 (revised) --
In December 2003, the Financial Accounting Standards Board (FASB)
issued FASB Interpretation No. 46 (revised December 2003),
"Consolidation of Variable Interest Entities" (FIN 46 (revised)),
which replaced 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. The adoption of FIN 46 (revised) did not have an effect on
the Company's financial position or results of operations.
FSP Nos. FAS 106-1 and FAS 106-2 --
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" (FSP No. FAS 106-1). FSP 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).
In May 2004, the FASB issued FASB Staff Position No. FAS 106-2,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003" (FSP
No. FAS 106-2).
The Company elected the one-time deferral of accounting for the
effects of the 2003 Medicare Act in the quarter ended March 31,
2004, the first period in which the plan's accounting for the
effects of the 2003 Medicare Act normally would have been
reflected in the Company's financial statements.
During the second quarter of 2004, the Company adopted FSP No.
FAS 106-2 retroactive to the beginning of the year. The Company
expects to be entitled to a federal subsidy. The expected federal
subsidy reduced the accumulated postretirement benefit obligation
(APBO) at January 1, 2004, by approximately $3.2 million, and net
periodic benefit cost for 2004 by approximately $285,000 (as
compared with the amount calculated without considering the
effects of the subsidy). In addition, the Company expects a
reduction in future participation in the postretirement plans,
which further reduced the APBO at January 1, 2004, by
approximately $12.7 million and net periodic benefit cost for 2004
by approximately $1.3 million.
FSP Nos. FAS 141-1 and FAS 142-1 --
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1
and FAS 142-1, "Interaction of FASB Statements No. 141, 'Business
Combinations,' and No. 142, 'Goodwill and Other Intangible
Assets,' and EITF Issue No. 04-2, 'Whether Mineral Rights are
Tangible or Intangible Assets,'" (FSP Nos. FAS 141-1 and FAS
142-1). The Company adopted FSP Nos. FAS 141-1 and FAS 142-1 in
the second quarter of 2004. FSP Nos. FAS 141-1 and FAS 142-1
required reclassification of the Company's leasehold rights at its
construction materials and mining operations from other intangible
assets, net, to property, plant and equipment, as well as changes
to Notes to Consolidated Financial Statements. FSP Nos. FAS 141-1
and FAS 142-1 affected the asset classification in the
consolidated balance sheet and associated footnote disclosure
only, so the reclassifications did not affect the Company's
stockholders' equity, cash flows or results of operations.
FSP No. FAS 142-2 --
In September 2004, the FASB Staff issued FASB Staff Position No.
FAS 142-2, "Application of FASB Statement No. 142, Goodwill and
Other Intangible Assets, to Oil- and Gas-Producing Entities," (FSP
No. FAS 142-2). FSP No. FAS 142-2 indicates that the exception in
SFAS No. 142, "Goodwill and Other Intangible Assets," does not
change the accounting prescribed in SFAS No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies,"
including the balance sheet classification of drilling and mineral
rights of oil and gas producing entities and, as a result, the
contractual mineral rights should continue to be classified as
part of property, plant and equipment. FSP No. FAS 142-2 did not
have an effect on the Company's financial position, results of
operations or cash flows.
SAB No. 106 --
In September 2004, the SEC issued Staff Accounting Bulletin No.
106 (SAB No. 106) which is an interpretation regarding the
application of SFAS No. 143 by oil and gas producing companies
following the full-cost accounting method. SAB No. 106 shall be
applied to all entities subject to SAB No. 106 as of the beginning
of the first quarter after October 4, 2004. The adoption of SAB
No. 106 is not expected to have a material effect on the Company's
financial position or results of operations.
SFAS No. 123 (revised)--
In December 2004, the FASB issued SFAS No. 123 (revised 2004),
"Share-Based Payment" (SFAS No. 123 (revised)). SFAS No. 123
(revised) revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the fair value of share-
based payments granted to employees. SFAS No. 123 (revised)
requires a company to record compensation expense for all awards
granted after the date of adoption of SFAS No. 123 (revised) and
for the unvested portion of previously granted awards that remain
outstanding at the date of adoption. SFAS No. 123 (revised) is
effective as of the beginning of the first interim or annual
reporting period that begins after June 15, 2005. The Company is
evaluating the effects of the adoption of SFAS No. 123 (revised).
For further information on FIN 46 (revised), FSP Nos. FAS 106-1
and FAS 106-2, FSP Nos. FAS 141-1 and FAS 142-1, FSP No. FAS
142-2, SAB No. 106, and SFAS No. 123 (revised), 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 an electric power sales
contract 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. 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
when the estimates are made.
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 SEC, and the cost 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 liability assumptions and
may from time to time change its liability 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. In as much as contract prices are
generally set before the work is performed, the estimates
pertaining to 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 when 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
leasehold rights).
The fair value of owned recoverable aggregate reserve deposits is
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.
The fair value of leasehold rights 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 considerable degree 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.
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 when 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 2004 increased
$14.7 million from the comparable 2003 period, the result of an
increase in net income of $31.7 million and higher depreciation,
depletion and amortization expense of $20.4 million largely due to
higher rates and higher natural gas production volumes at the
natural gas and oil production business and higher property, plant
and equipment due to acquisitions at the construction materials
and mining business. Also contributing to the increase were
changes in working capital of $19.1 million and asset impairments
of $6.1 million. Partially offsetting the increase in cash flows
from operating activities were decreased deferred income taxes of
$31.4 million, which reflects the effects of higher depreciation,
depletion and amortization expense, as previously discussed, as
well as lower tax depreciation in 2004 on the Grasslands Pipeline.
Also offsetting the increase were increased earnings, net of
distributions, from equity method investments of $18.2 million and
the absence in 2004 of the 2003 cumulative effect of an accounting
change of $7.6 million.
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.
Investing activities --
Cash flows used in investing activities in 2004 decreased
$34.4 million compared to the comparable 2003 period, the result
of a decrease in net capital expenditures (capital expenditures;
acquisitions, net of cash acquired; and net proceeds from the sale
or disposition of property) of $77.0 million and an increase in
proceeds from notes receivable of $14.2 million, offset in part by
an increase in investments of $56.8 million, including equity
method investments. Net capital expenditures exclude the noncash
transactions related to acquisitions, including the issuance of
the Company's equity securities. The noncash transactions were
$33.1 million and $42.4 million for 2004 and 2003, respectively.
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.
Financing activities --
Cash flows provided by financing activities in 2004 decreased
$54.8 million compared to the comparable 2003 period, primarily
the result of a decrease in proceeds from the issuance of long-
term debt of $204.4 million. A decrease in repayment of long-term
debt of $67.7 million and an increase in proceeds from the
issuance of common stock of $69.6 million, primarily due to net
proceeds received from an underwritten public offering, partially
offset the decrease in cash provided by 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.
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, 2004, certain Pension Plans' accumulated benefit
obligations exceeded these plans' assets by approximately
$3.7 million. Pretax pension expense (income) reflected in the
years ended December 31, 2004, 2003 and 2002, was $4.1 million,
$153,000, and ($2.4) million, respectively. The Company's pension
expense is currently projected to be approximately $7.0 million to
$8.0 million in 2005. 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 2004, 2003 and 2002 were approximately
$1.2 million, $1.6 million, and $1.2 million, respectively. For
further information on the Company's Pension Plans, see Item 8 --
Financial Statements and Supplementary Data - Note 15.
Capital expenditures
The Company's capital expenditures for 2002 through 2004 and as
anticipated for 2005 through 2007 are summarized in the following
table, which also includes the Company's capital needs for the
retirement of maturing long-term debt.
Actual Estimated*
2002 2003 2004 2005 2006 2007
(In millions)
Capital expenditures:
Electric $ 27.8 $ 28.5 $ 18.8 $ 24.8 $ 63.5 $167.2
Natural gas
distribution 11.0 15.7 17.4 15.2 15.8 13.4
Utility services 17.3 7.8 8.5 12.8 11.8 12.4
Pipeline and energy
services 21.5 93.0 38.3 35.4 29.9 34.6
Natural gas and oil
production 136.4 101.7 111.5 157.2 146.7 149.2
Construction
materials
and mining 106.9 128.5 133.0 101.3 93.2 73.4
Independent power
production 89.6 110.9 76.2 86.5 38.3 20.7
Other 6.1 1.9 4.2 13.0 .3 .2
416.6 488.0 407.9 446.2 399.5 471.1
Net proceeds from sale or
disposition of property (16.2) (14.4) (20.5) (1.8) (2.8) (1.7)
Net capital expenditures 400.4 473.6 387.4 444.4 396.7 469.4
Retirement of
long-term debt 82.6 105.7 38.0 72.0 138.8 132.9
$483.0 $579.3 $425.4 $516.4 $535.5 $602.3
*The estimated 2005 through 2007 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 2004, 2003 and 2002, related to
acquisitions, in the preceding table include the following noncash
transactions: issuance of the Company's equity securities of
$33.1 million in 2004, $42.4 million in 2003 and $47.2 million in
2002.
In 2004, the Company acquired a number of businesses, none of
which was individually material, including construction materials
and mining businesses in Hawaii, Idaho, Iowa and Minnesota and an
independent power production operating and development company in
Colorado. The total purchase consideration for these businesses
and adjustments with respect to certain other acquisitions
acquired prior to 2004, consisting of the Company's common stock
and cash, was $70.3 million.
The 2004 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 2005 through 2007 include those for:
- Potential future acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Buildings, land and building improvements
- Pipeline and gathering expansion projects
- Further enhancement of natural gas and oil production and
reserve growth
- Power generation opportunities, including certain
construction costs for an additional 175 megawatts of capacity and
for a 116-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 2005 through 2007 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, 2004.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at December 31, 2004. There were no amounts
outstanding under the credit agreement at December 31, 2004. The
credit agreement supports the Company's $75 million commercial
paper program. Under the Company's commercial paper program,
$37.0 million was outstanding at December 31, 2004. 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.
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
$56,000 (after tax) based on December 31, 2004, variable rate
borrowings.
Prior to the maturity of the credit agreement, the Company plans
to negotiate the extension or replacement of this agreement, which
provides credit support to access the capital markets. In the
event the Company is 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, 2004. 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 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 have been 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 fund $1.43 of unfunded property or use $1.00 of
refunded bonds for each dollar of indebtedness incurred under the
Indenture and, in some cases, to certify to the trustee 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
tests, as of December 31, 2004, the Company could have issued
approximately $343 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.7 times for the twelve months ended December 31,
2004 and 2003. Additionally, the Company's first mortgage bond
interest coverage was 7.1 times and 7.4 times for the twelve
months ended December 31, 2004 and 2003, respectively. Common
stockholders' equity as a percent of total capitalization (net of
long-term debt due within one year) was 65 percent and 60 percent
at December 31, 2004 and 2003, respectively.
Centennial Energy Holdings, Inc.
Centennial has three revolving credit agreements with various
banks and institutions that support $335 million of Centennial's
$350 million commercial paper program. There were no outstanding
borrowings under the Centennial credit agreements at December 31,
2004. Under the Centennial commercial paper program, $26.0
million was outstanding at December 31, 2004. 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. One of
these credit agreements is for $300 million and expires on
August 17, 2007, and another agreement is for $25 million and
expires on April 30, 2007. Centennial intends to negotiate the
extension or replacement of these agreements prior to their
maturities. The third agreement is an uncommitted line for $10
million, which was effective on January 25, 2005, and may be
terminated by the bank at any time.
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, 2004. The ability to request
additional borrowings under this master shelf agreement expires
on February 28, 2005. The Company is in discussion regarding
potential renewal of this facility. 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 $39,000 (after
tax) based on December 31, 2004, variable rate borrowings. Based
on Centennial's overall interest rate exposure at December 31,
2004, 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, which 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, 2004. 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, 2004. The ability to request
additional borrowings under this master shelf agreement expires on
December 20, 2005.
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, 2004. 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 Termoceara Generating Facility, 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, 2004, the aggregate amount of
borrowings outstanding subject to these guarantees was $34.9
million and the scheduled repayment of these borrowings is $11.0
million in 2005, $10.7 million in 2006 and 2007 and $2.5 million
in 2008. The individual investor (who through EBX Empreendimentos
Ltda. (EBX), a Brazilian company, owns 51 percent of MPX) has also
guaranteed these loans. In the event MPX defaults under its
obligation, Centennial and the individual investor would be
required to make payments under their guarantees, which are joint
and several obligations. 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, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$375 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
is 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 7
and 18. At December 31, 2004, the Company's commitments under
these obligations were as follows:
2005 2006 2007 2008 2009 Thereafter Total
(In millions)
Long-term debt $ 72.0 $138.8 $132.9 $161.3 $ 86.9 $353.6 $ 945.5
Estimated interest
payments* 53.7 49.5 38.7 32.5 25.3 126.2 325.9
Operating leases 14.7 10.5 6.6 5.1 3.5 25.2 65.6
Purchase
commitments 223.6 105.7 65.4 50.5 46.9 236.4 728.5
$364.0 $304.5 $243.6 $249.4 $162.6 $741.4 $2,065.5
* Estimated interest payments are calculated based on the
applicable rates and payment dates.
In addition to the above obligations, the Company has certain
purchase obligations for natural gas connected to its gathering
system. These purchases and the resale of the natural gas are at
market-based prices. These obligations continue as long as
natural gas is produced. However, if the purchase and resale of
natural gas becomes uneconomical, the purchase commitments can be
canceled by the Company with 60 days notice. These purchase
obligations are currently estimated at approximately $10 million
annually.
Effects of Inflation
Inflation did not have a significant effect on the Company's
operations in 2004, 2003 or 2002.
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 that natural gas
and oil price derivative instruments and interest rate derivative
instruments not exceed a period of 24 months and foreign currency
derivative instruments not exceed a 12-month period. 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; if the derivative instrument expires or is sold,
terminated or exercised; 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 --
Fidelity 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 its 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.
The following table summarizes hedge agreements entered into by
Fidelity as of December 31, 2004. These agreements call for
Fidelity 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 2005 $ 5.39 8,020 $ (4,187)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2005 $5.42/$6.64 15,050 $ (168)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreement
maturing in 2005 $ 30.70 183 $ (2,138)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2005 $37.79/$44.68 347 $ (608)
The following table summarizes hedge agreements entered into by
Fidelity as of December 31, 2003. These agreements call for
Fidelity 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)
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, 2004.
Fair
2005 2006 2007 2008 2009 Thereafter Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $72.0 $101.8 $106.9 $161.3 $86.9 $353.6 $882.5 $930.0
Weighted average
interest rate 7.9% 6.5% 8.2% 4.5% 6.2% 6.5% 6.4% -
Variable rate - $37.0 $26.0 - - - $63.0 $62.2
Weighted average
interest rate - 2.3% 2.3% - - - 2.3% -
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 method investment in an
electric 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 Termoceara
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 Termoceara Generating Facility's U.S. dollar
denominated obligations. At December 31, 2004, these U.S. dollar
denominated obligations approximated $61.4 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 Termoceara Generating Facility, would record a
foreign currency loss in net income of approximately $2.3 million
(after tax) based on the above U.S. dollar denominated obligations
at December 31, 2004.
The investment of Centennial International in the Termoceara
Generating Facility at December 31, 2004, was approximately $25.2
million.
A portion of the Termoceara 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
Termoceara Generating Facility's electric power sales contract.
The Termoceara 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
Management's Report on Internal Control over Financial Reporting
The management of MDU Resources Group, Inc. is responsible for
establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) under the
Securities Exchange Act of 1934. The Company's internal control
system was designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles.
All internal control systems, no matter how well designed, have
inherent limitations. Therefore, even those systems determined to
be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Because of its
inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
Management assessed the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004. In
making this assessment, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control-Integrated Framework.
Based on our evaluation under the framework in Internal
Control-Integrated Framework, management concluded that the
Company's internal control over financial reporting was effective
as of December 31, 2004.
Management's assessment of the Company's internal control over
financial reporting as of December 31, 2004, has been audited by
Deloitte & Touche LLP, an independent registered public accounting
firm, as stated in their report.
/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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004
and 2003, 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, 2004. Our audits also
included the financial statement schedules for each of the three
years in the period ended December 31, 2004, 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.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). 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 consolidated financial statement presentation. We
believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company as of December 31, 2004 and 2003, and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 2004, in conformity with accounting
principles generally accepted in the United States of America.
Also, in our opinion, the financial statement schedules for each
of the three years in the period ended December 31, 2004, when
considered in relation to the consolidated financial statements
taken as a whole, present fairly, in all material respects, the
information set forth therein.
As discussed in Notes 1 and 8 to the consolidated financial
statements, effective January 1, 2003, the Company changed its
method of accounting for asset retirement obligations.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of the Company's internal control over financial
reporting as of December 31, 2004, based on the criteria
established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
and our report dated February 22, 2005, expressed an unqualified
opinion on management's assessment of the effectiveness of the
Company's internal control over financial reporting and an
unqualified opinion on the effectiveness of the Company's internal
control over financial reporting.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of MDU Resources Group,
Inc.:
We have audited management's assessment, included in the
accompanying Management's Report on Internal Control over
Financial Reporting, that MDU Resources Group, Inc. (the
"Company") maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established
in Internal Control-Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for maintaining effective
internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the
Company's internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. Our
audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process
designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of
directors, management, and other personnel to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A
company's internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company;
(2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material
effect on the financial statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely
basis. Also, projections of any evaluation of the effectiveness
of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate
because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company
maintained effective internal control over financial reporting as
of December 31, 2004, is fairly stated, in all material respects,
based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated financial statements and financial statement schedule
of the Company as of and for the year ended December 31, 2004, and
our report dated February 22, 2005, expressed an unqualified
opinion on those financial statements and financial statement
schedule.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2005
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2004 2003 2002
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas
distribution and
pipeline and energy
services $ 776,836 $ 641,062 $ 459,409
Utility services, natural
gas and oil production,
construction materials
and mining, independent
power production and other 1,942,421 1,711,127 1,572,128
2,719,257 2,352,189 2,031,537
Operating expenses:
Fuel and purchased power 64,618 62,037 56,010
Purchased natural gas sold 249,924 184,171 92,528
Operation and maintenance:
Electric, natural gas
distribution and
pipeline and energy
services 158,387 141,307 129,845
Utility services, natural
gas and oil production,
construction materials
and mining, independent
power production and
other 1,614,053 1,384,015 1,263,183
Depreciation, depletion and
amortization 208,770 188,337 157,961
Taxes, other than income 96,681 80,250 65,893
Asset impairments (Notes 1 and 3) 6,106 --- ---
2,398,539 2,040,117 1,765,420
Operating income 320,718 312,072 266,117
Earnings from equity method
investments 25,053 5,968 1,341
Other income 12,707 16,239 12,231
Interest expense 57,437 52,794 45,015
Income before income taxes 301,041 281,485 234,674
Income taxes 93,974 98,572 86,230
Income before cumulative effect
of accounting change 207,067 182,913 148,444
Cumulative effect of accounting
change (Note 8) --- (7,589) ---
Net income 207,067 175,324 148,444
Dividends on preferred stocks 685 717 756
Earnings on common stock $ 206,382 $ 174,607 $ 147,688
Earnings per common share --
basic:
Earnings before cumulative
effect of accounting change $ 1.77 $ 1.64 $ 1.39
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share --
basic $ 1.77 $ 1.57 $ 1.39
Earnings per common share --
diluted:
Earnings before cumulative
effect of accounting change $ 1.76 $ 1.62 $ 1.38
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share --
diluted $ 1.76 $ 1.55 $ 1.38
Dividends per common share $ .7000 $ .6600 $ .6266
Weighted average common shares
outstanding -- basic 116,482 111,483 106,115
Weighted average common shares
outstanding -- diluted 117,411 112,460 106,863
Pro forma amounts assuming
retroactive application of
accounting change:
Net income $ 207,067 $ 182,913 $ 146,052
Earnings per common share --
basic $ 1.77 $ 1.64 $ 1.37
Earnings per common share --
diluted $ 1.76 $ 1.62 $ 1.36
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
December 31, 2004 2003
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 99,377 $ 86,341
Receivables, net 440,903 357,677
Inventories 143,880 114,051
Deferred income taxes 2,874 3,104
Prepayments and other current assets 41,144 52,367
728,178 613,540
Investments 120,555 44,975
Property, plant and equipment (Note 1) 3,931,428 3,584,038
Less accumulated depreciation,
depletion and amortization 1,358,723 1,187,105
2,572,705 2,396,933
Deferred charges and other assets:
Goodwill (Note 3) 199,743 199,427
Other intangible assets, net (Note 3) 22,269 18,814
Other 90,071 106,903
312,083 325,144
$3,733,521 $3,380,592
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Long-term debt due within one year $ 72,046 $ 27,646
Accounts payable 184,993 150,316
Taxes payable 28,372 15,358
Dividends payable 21,449 19,442
Other accrued liabilities 142,233 101,299
449,093 314,061
Long-term debt (Note 7) 873,441 939,450
Deferred credits and other liabilities:
Deferred income taxes 494,589 444,779
Other liabilities 235,385 231,666
729,974 676,445
Commitments and contingencies (Notes 15, 17 and 18)
Stockholders' equity:
Preferred stocks (Note 9) 15,000 15,000
Common stockholders' equity:
Common stock (Note 10)
Authorized - 250,000,000 shares, $1.00 par value
Issued - 118,586,065 shares in 2004 and
113,716,632 shares in 2003 118,586 113,717
Other paid-in capital 863,449 757,787
Retained earnings 699,095 575,287
Accumulated other comprehensive loss (11,491) (7,529)
Treasury stock at cost - 359,281 shares (3,626) (3,626)
Total common stockholders' equity 1,666,013 1,435,636
Total stockholders' equity 1,681,013 1,450,636
$3,733,521 $3,380,592
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, 2004, 2003 and 2002
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, 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 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
(pre-split) 1,442,220 1,442 45,260 --- --- --- --- 46,702
Three-for-two common
stock split (Note 10) 37,862,129 37,862 (37,862) --- --- (119,760) --- ---
Issuance of common stock
(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
Comprehensive income:
Net income --- --- --- 207,067 --- --- --- 207,067
Other comprehensive
income (loss), net of tax -
Net unrealized loss on
derivative instruments
qualifying as hedges --- --- --- --- (1,032) --- --- (1,032)
Minimum pension liability
adjustment --- --- --- --- (3,782) --- --- (3,782)
Foreign currency
translation adjustment --- --- --- --- 852 --- --- 852
Total comprehensive
income --- --- --- --- --- --- --- 203,105
Dividends on
preferred stocks --- --- --- (685) --- --- --- (685)
Dividends on
common stock --- --- --- (82,574) --- --- --- (82,574)
Issuance of common stock 4,869,433 4,869 105,662 --- --- --- --- 110,531
Balance at
December 31, 2004 118,586,065 $118,586 $863,449 $699,095 $(11,491) (359,281) $(3,626) $1,666,013
<FN>
The accompanying notes are an integral part of these consolidated financial statements.
</FN>
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2004 2003 2002
(In thousands)
Operating activities:
Net income $207,067 $175,324 $148,444
Cumulative effect of accounting
change --- 7,589 ---
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 208,770 188,337 157,961
Earnings, net of distributions,
from equity method investments (22,261) (4,020) (1,341)
Deferred income taxes 33,163 64,587 30,759
Asset impairments 6,106 --- ---
Changes in current assets and
liabilities, net of
acquisitions:
Receivables (64,168) (9,698) (18,296)
Inventories (23,799) (13,023) 6,537
Other current assets 9,659 (13,383) (5,562)
Accounts payable 30,319 2,748 11,600
Other current liabilities 44,172 10,486 (9,499)
Other noncurrent changes 4,043 9,450 5,728
Net cash provided by operating
activities 433,071 418,397 326,331
Investing activities:
Capital expenditures (337,688) (313,053) (276,776)
Acquisitions, net of cash acquired (37,138) (132,653) (92,657)
Net proceeds from sale or
disposition of property 20,518 14,439 16,217
Investments (54,265) 2,491 (4,666)
Proceeds from notes receivable 22,000 7,812 4,000
Net cash used in investing
activities (386,573) (420,964) (353,882)
Financing activities:
Net change in short-term borrowings --- (20,000) 20,000
Issuance of long-term debt 15,449 219,895 129,072
Repayment of long-term debt (38,021) (105,740) (82,523)
Retirement of preferred stock --- --- (100)
Proceeds from issuance of
common stock 70,129 568 55,134
Dividends paid (81,019) (73,371) (68,287)
Net cash provided by (used in)
financing activities (33,462) 21,352 53,296
Increase in cash and cash equivalents 13,036 18,785 25,745
Cash and cash equivalents --
beginning of year 86,341 67,556 41,811
Cash and cash equivalents --
end of year $ 99,377 $ 86,341 $ 67,556
The accompanying notes are an integral part of these consolidated financial
statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Summary of Significant Accounting Policies
Basis of presentation
The consolidated financial statements of the 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,
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, independent
power production, and other are nonregulated. For further
descriptions of the Company's businesses, see Note 13. The
statements also include the ownership interests in the assets,
liabilities and expenses of two jointly owned electric generating
facilities.
The Company uses the equity method of accounting for certain
investments. For more information on the Company's equity method
investments, see Note 2.
The Company's regulated businesses are subject to various state
and federal agency regulations. The accounting policies followed
by these businesses are generally subject to the Uniform System of
Accounts of the 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 SFAS No. 71, "Accounting for
the Effects of Certain Types 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.
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,
2004 and 2003, was $6.8 million and $8.1 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 was $24.9 million and $19.6 million at December 31, 2004 and
2003, respectively. The remainder of natural gas in underground
storage was included in other assets and was $43.3 million and
$42.6 million at December 31, 2004 and 2003, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
Company's regulated operations, consisted primarily of aggregates
held for resale of $71.0 million and $54.7 million, materials and
supplies of $31.0 million and $27.2 million, and other inventories
of $17.0 million and $12.6 million, as of December 31, 2004 and
2003, 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. Leased mineral rights at the
Company's construction materials and mining business were
reclassified from other intangible assets, net, to property, plant
and equipment, as discussed in new accounting standards in this
note. 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 this note, 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 $6.2
million, $7.4 million and $7.6 million in 2004, 2003 and 2002,
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, 2004 and 2003, was
as follows:
Estimated
Depreciable
Life
2004 2003 in Years
(Dollars in thousands, as applicable)
Regulated:
Electric:
Electric generation,
distribution and
transmission plant $ 650,902 $ 639,893 4-50
Natural gas distribution:
Natural gas distribution plant 264,496 252,591 4-40
Pipeline and energy services:
Natural gas transmission,
gathering and storage
facilities 358,853 340,841 8-104
Nonregulated:
Utility services:
Land 2,533 2,505 ---
Buildings and improvements 10,257 10,123 3-40
Machinery, vehicles and equipment 63,586 58,843 2-10
Other 6,224 5,400 3-10
Pipeline and energy services:
Natural gas gathering
and other facilities 132,067 119,613 3-20
Energy services 1,480 1,339 3-15
Natural gas and oil production:
Natural gas and oil properties 973,604 862,839 *
Other 9,021 8,518 3-7
Construction materials and mining:
Land 91,610 89,545 ---
Buildings and improvements 51,309 48,907 3-40
Machinery, vehicles and equipment 658,355 569,295 1-23
Construction in progress 16,545 14,392 ---
Aggregate reserves 372,649 358,260 **
Independent power production:
Electric generation 154,631 153,944 10-30
Construction in progress 93,953 29,805 ---
Land 375 375 ---
Other 1,643 3 3-7
Other:
Land 3,044 1,626 ---
Other 14,291 15,381 3-20
Less accumulated depreciation,
depletion and amortization 1,358,723 1,187,105
Net property, plant and equipment $2,572,705 $2,396,933
* Amortized on the units-of-production method based on total
proved reserves at an Mcf equivalent average rate of $.98,
$.89, and $.80 for the years ended December 31, 2004, 2003 and
2002, respectively. Includes natural gas and oil production
properties accounted for under the full-cost method, of which
$69.0 million and $104.3 million were excluded from
amortization at December 31, 2004 and 2003, respectively.
** Depleted 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
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. In the third quarter of 2004, the Company recognized a
$2.1 million ($1.3 million after tax) adjustment reflecting the
reduction in value of certain gathering facilities in the Gulf
Coast region at the pipeline and energy services segment. No
impairment losses were recorded in 2003 and 2002. 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. 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 the
third quarter of 2004, the Company recognized a goodwill
impairment at the pipeline and energy services segment. For more
information on the goodwill impairment and 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 SEC, and the cost 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, 2004 and 2003, 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, 2004, 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, 2004, in
total and by year in which such costs were incurred:
Year Costs Incurred
2001
and
Total 2004 2003 2002 prior
(In thousands)
Acquisition $34,169 $ 6,708 $ 481 $15,493 $11,487
Development 22,582 16,259 4,559 1,764 ---
Exploration 5,228 4,681 547 --- ---
Capitalized interest 7,005 2,252 1,839 2,914 ---
Total costs not subject
to amortization $68,984 $29,900 $7,426 $20,171 $11,487
Costs not subject to amortization as of December 31, 2004,
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 and
an enhanced recovery development project in the Cedar Creek
Anticline in southeastern Montana. The Company expects that the
majority of these costs will be evaluated within the next 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 and, where
applicable, revenues are recognized under Emerging Issues Task
Force Issue No. 91-6, "Revenue Recognition of Long-Term Power
Sales Contracts," ratably over the terms of the related contract.
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. If a loss is anticipated on a
contract, the loss is immediately recognized. Costs in excess of
billings on uncompleted contracts of $31.9 million and $31.8
million at December 31, 2004 and 2003, respectively, represent
revenues recognized in excess of amounts billed and were included
in receivables, net. Billings in excess of costs on uncompleted
contracts of $32.2 million and $20.4 million at December 31, 2004
and 2003, respectively, represent billings in excess of revenues
recognized and were 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 $40.9 million and $34.3 million at December 31, 2004
and 2003, 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 that natural gas
and oil price derivative instruments and interest rate derivative
instruments not exceed a period of 24 months and foreign currency
derivative instruments not exceed a 12-month period. 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.
Asset retirement obligations
In 2003, the Company adopted SFAS No. 143, which requires the
Company 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 Company 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, the Company either settles the obligation for the
recorded amount or incurs a gain or loss. For more information on
asset retirement obligations, see Note 8.
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 $15.5 million and $10.5 million at
December 31, 2004 and 2003, respectively, which is included in
prepayments and other current assets.
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
above the primary automobile and general liability policies 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 for claims incurred but not reported.
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 10.
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, 2004, 2003 and 2002, 36,000
shares, 209,805 shares and 3,674,925 shares, respectively, with an
average exercise price of $25.70, $24.56 and $20.08, 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, 2004,
2003 and 2002, 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 years ended December 31, 2004 and 2003,
was $18,000 and $41,000, respectively (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 Accounting Principles Board (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.
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, 2004, 2003 and 2002, 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:
2004 2003 2002
(In thousands, except per share amounts)
Earnings on common stock, as
reported $206,382 $174,607 $147,688
Stock-based compensation expense
included in reported earnings,
net of related tax effects 18 41 ---
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (62) (2,139) (2,862)
Pro forma earnings on common stock $206,338 $172,509 $144,826
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect
of accounting change $ 1.77 $ 1.64 $ 1.39
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share -- basic $ 1.77 $ 1.57 $ 1.39
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect
of accounting change $ 1.77 $ 1.62 $ 1.36
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share -- basic $ 1.77 $ 1.55 $ 1.36
Earnings per common share -- diluted
-- as reported:
Earnings before cumulative effect
of accounting change $ 1.76 $ 1.62 $ 1.38
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share --
diluted $ 1.76 $ 1.55 $ 1.38
Earnings per common share -- diluted
-- pro forma:
Earnings before cumulative effect
of accounting change $ 1.76 $ 1.60 $ 1.36
Cumulative effect of accounting
change --- (.07) ---
Earnings per common share --
diluted $ 1.76 $ 1.53 $ 1.36
For more information on the Company's stock-based compensation,
see Note 11.
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 the electric power sales contract
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, 2004 2003 2002
(In thousands)
Interest, net of amount
capitalized $50,236 $47,474 $37,788
Income taxes $50,487 $31,737 $60,988
Reclassifications
Certain 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
FIN 46 (revised) --
In December 2003, the FASB issued FIN 46 (revised), which replaced
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.
The Company evaluated the provisions of FIN 46 (revised) and
determined that the Company does not have any controlling
financial interests in any variable interest entities and,
therefore, is not required to consolidate any variable interest
entities in its financial statements. The adoption of FIN 46
(revised) did not have an effect on the Company's financial
position or results of operations.
FSP Nos. FAS 106-1 and FAS 106-2 --
In January 2004, the FASB issued FSP No. FAS 106-1. FSP 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 2003 Medicare Act.
In May 2004, the FASB issued FSP No. FAS 106-2. FSP No. FAS 106-2
requires (a) that the effects of the federal subsidy be considered
an actuarial gain and recognized in the same manner as other
actuarial gains and losses and (b) certain disclosures for
employers that sponsor postretirement health care plans that
provide prescription drug benefits.
The Company provides prescription drug benefits to certain
eligible employees. The Company elected the one-time deferral of
accounting for the effects of the 2003 Medicare Act in the quarter
ended March 31, 2004, the first period in which the plan's
accounting for the effects of the 2003 Medicare Act normally would
have been reflected in the Company's financial statements.
During the second quarter of 2004, the Company adopted FSP No.
FAS 106-2 retroactive to the beginning of the year. The Company
and its actuarial advisors determined that benefits provided to
certain participants are expected to be at least actuarially
equivalent to Medicare Part D (the federal prescription drug
benefit), and, accordingly, the Company expects to be entitled to
a federal subsidy. The expected federal subsidy reduced the APBO
at January 1, 2004, by approximately $3.2 million, and net
periodic benefit cost for 2004 by approximately $285,000 (as
compared with the amount calculated without considering the
effects of the subsidy). In addition, the Company expects a
reduction in future participation in the postretirement plans,
which further reduced the APBO at January 1, 2004, by
approximately $12.7 million and net periodic benefit cost for 2004
by approximately $1.3 million.
FSP Nos. FAS 141-1 and FAS 142-1 --
In April 2004, the FASB issued FSP Nos. FAS 141-1 and FAS 142-1.
FSP Nos. FAS 141-1 and FAS 142-1 amend SFAS No. 141, "Business
Combinations," and SFAS No. 142 to clarify that certain mineral
rights held by mining entities that are not within the scope of
SFAS No. 19 be classified as tangible assets rather than
intangible assets. The Company adopted FSP Nos. FAS 141-1 and FAS
142-1 in the second quarter of 2004. FSP Nos. FAS 141-1 and FAS
142-1 required reclassification of the Company's leasehold rights
at its construction materials and mining operations from other
intangible assets, net, to property, plant and equipment, as well
as changes to Notes to Consolidated Financial Statements. FSP
Nos. FAS 141-1 and FAS 142-1 affected the asset classification in
the consolidated balance sheet and associated footnote disclosure
only, so the reclassifications did not affect the Company's
stockholders' equity, cash flows or results of operations.
FSP No. FAS 142-2 --
In September 2004, the FASB Staff issued FSP No. FAS 142-2. FSP
No. FAS 142-2 indicates that the exception in SFAS No. 142 does
not change the accounting prescribed in SFAS No. 19 including the
balance sheet classification of drilling and mineral rights of oil
and gas producing entities and, as a result, the contractual
mineral rights should continue to be classified as part of
property, plant and equipment. FSP No. FAS 142-2 did not have an
effect on the Company's financial position, results of operations
or cash flows.
SAB No. 106 --
In September 2004, the SEC issued SAB No. 106 which is an
interpretation regarding the application of SFAS No. 143 by oil
and gas producing companies following the full-cost accounting
method. SAB No. 106 clarifies that the future cash outflows
associated with settling asset retirement obligations that have
been accrued on the balance sheet should be excluded from the
computation of the present value of estimated future net revenues
for purposes of the full-cost ceiling calculation. SAB No. 106
also states that a company is expected to disclose in the
financial statement footnotes and MD&A how the company's
calculation of the ceiling test and depreciation, depletion and
amortization are affected by the adoption of SFAS No. 143. SAB
No. 106 shall be applied to all entities subject to SAB No. 106 as
of the beginning of the first quarter after October 4, 2004. The
adoption of SAB No. 106 is not expected to have a material effect
on the Company's financial position or results of operations.
SFAS No. 123 (revised) --
In December 2004, the FASB issued SFAS No. 123 (revised). SFAS
No. 123 (revised) revises SFAS No. 123 and requires entities to
recognize compensation expense in an amount equal to the fair
value of share-based payments granted to employees. SFAS No. 123
(revised) requires a company to record compensation expense for
all awards granted after the date of adoption of SFAS No. 123
(revised) and for the unvested portion of previously granted
awards that remain outstanding at the date of adoption. SFAS No.
123 (revised) is effective as of the beginning of the first
interim or annual reporting period that begins after June 15,
2005. The Company is evaluating the effects of the adoption of
SFAS No. 123 (revised).
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 (losses) on
derivative instruments qualifying as hedges, minimum pension
liability adjustments and foreign currency translation
adjustments. For more information on derivative instruments, see
Note 5.
The components of other comprehensive income (loss), and their
related tax effects for the years ended December 31, 2004, 2003
and 2002, were as follows:
2004 2003 2002
(In thousands)
Other comprehensive income (loss):
Net unrealized gain (loss) on
derivative instruments
qualifying as hedges:
Net unrealized loss
on derivative instruments
arising during the period,
net of tax of $2,734,
$2,132 and $2,903 in 2004,
2003 and 2002, respectively $(4,367) $(3,335) $ (4,541)
Less: Reclassification adjustment
for gain (loss) on derivative
instruments included in
net income, net of tax of $2,132,
$2,903 and $1,448 in 2004, 2003
and 2002, respectively (3,335) (4,541) 2,218
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges (1,032) 1,206 (6,759)
Minimum pension liability
adjustment, net of tax of $2,406,
$38 and $2,876 in 2004, 2003
and 2002, respectively (3,782) 21 (4,464)
Foreign currency translation
adjustment 852 1,048 (799)
Total other comprehensive income
(loss) $(3,962) $ 2,275 $(12,022)
The after-tax components of accumulated other comprehensive loss
as of December 31, 2004, 2003 and 2002, were as follows:
Net
Unrealized
Loss on Total
Derivative Minimum Foreign Accumulated
Instruments Pension Currency Other
Qualifying Liability Translation Comprehensive
as Hedges Adjustment Adjustment Loss
(In thousands)
Balance at December 31, 2002 $(4,541) $(4,464) $ (799) $ (9,804)
Balance at December 31, 2003 $(3,335) $(4,443) $ 249 $ (7,529)
Balance at December 31, 2004 $(4,367) $(8,225) $1,101 $(11,491)
Note 2
Equity Method Investments
The Company has a number of equity method investments including
MPX, Carib Power and Hartwell. The Company assesses its equity
method investments for impairment whenever events or changes in
circumstances indicate that such carrying values may not be
recoverable. None of the Company's equity method investments have
been impaired and, accordingly, no impairment losses have been
recorded in the accompanying consolidated financial statements or
related equity method investment balances.
MDU Brasil has a 49 percent interest in MPX, which was formed in
August 2001 when MDU Brasil entered into a joint venture agreement
with a Brazilian firm. MPX, through a wholly owned subsidiary,
owns and operates the Termoceara Generating Facility in the
Brazilian state of Ceara. Petrobras, the Brazilian state-
controlled energy company, entered into a contract to purchase all
of the capacity and market all of energy from the Termoceara
Generating Facility. The first phase of the electric power sales
contract with Petrobras for 110 megawatts expires in November 2007
and the portion of the contract for the remaining 110 megawatts
expires in May 2008. Petrobras also is under contract to supply
natural gas to the Termoceara Generating Facility during the term
of the electric power sales contract. This natural gas supply
contract is renewable by a wholly owned subsidiary of MPX for an
additional 13 years.
During 2004, Petrobras initiated discussions with a number of
owners of thermoelectric plants, including MPX, regarding a
possible renegotiation of their related power purchase agreements
or buyout of the generating plants. On January 13, 2005,
Petrobras obtained a Brazilian court order permitting it to cease
making monthly capacity payments to MPX and to instead deposit the
payments into a court account until the matter is resolved. On
February 2, 2005, the court revoked its January 13, 2005, order
and stated that MPX could withdraw the amounts deposited by
Petrobras. This decision was upheld on appeal on February 17,
2005. Under the existing contract, Petrobras agreed to jointly
market all of the facility's energy, and in the event that the
facility's revenues are insufficient to cover its costs during
certain periods, to make certain monthly contingency payments.
Petrobras has stated that, because of structural changes in the
Brazilian electric power markets since the contract was signed in
2001, the contingency payments had become permanent payment
obligations entitling Petrobras to renegotiate the contract. The
contract contains a dispute resolution provision which creates a
30-day period for accelerated negotiations. In the event that the
parties do not reach agreement during the 30-day period, the
dispute would be resolved in arbitration.
The Termoceara Generating Facility generates electricity based
upon economic dispatch and available gas supplies. Under current
conditions, including, in particular, existing constraints in the
region's gas supply infrastructure, the Company does not expect
the facility to generate a significant amount of energy at least
through 2006.
The functional currency for the Termoceara Generating Facility is
the Brazilian Real. The electric power sales contract 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. The Company's 49
percent share of the gain (loss) from the change in fair value of
the embedded derivative in the electric power sales contract and
the Company's 49 percent share of the foreign currency gain (loss)
resulting from an increase (decrease) in value of the Brazilian
Real versus the U.S. dollar for the years ended December 31, were
as follows:
2004 2003 2002
(In thousands)
Company's 49 percent share of
the gain (loss) from the
change in fair value of the
embedded derivative in the
electric power sales
contract (after tax) $2,451 $(11,282) $13,592
Company's 49 percent share of
the foreign currency gain
(loss) resulting from the
change in value of the
Brazilian Real versus
the U.S. dollar (after tax) $1,871 $ 2,757 $ (9,392)
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX. For more information on this guarantee,
see Note 18.
On February 26, 2004, Centennial International acquired 49.99
percent of Carib Power. Carib Power, through a wholly owned
subsidiary, owns a 225-megawatt natural gas-fired electric
generating facility located in Trinidad and Tobago. The Trinity
Generating Facility sells its output to the T&TEC, the governmental
entity responsible for the transmission, distribution and
administration of electrical power to the national electrical grid
of Trinidad and Tobago. The power purchase agreement expires in
September 2029. T&TEC also is under contract to supply natural
gas to the Trinity Generating Facility during the term of the
power purchase contract. The functional currency for the Trinity
Generating Facility is the U.S. dollar.
On September 28, 2004, Centennial Resources, through wholly owned
subsidiaries, acquired a 50-percent ownership interest in a 310-
megawatt natural gas-fired electric generating facility. This
facility is located in Hartwell, Georgia. The Hartwell Generating
Facility sells its output under a power purchase agreement with
Oglethorpe that expires in May 2019. American National Power, a
wholly owned subsidiary of International Power of the United
Kingdom, holds the remaining 50-percent ownership interest and is
the operating partner for the facility.
At December 31, 2004, MPX, Carib Power and Hartwell had total
assets of $334.2 million and long-term debt of $224.9 million.
The Company's investment in the Termoceara, Trinity and Hartwell
Generating Facilities was approximately $65.7 million, including
undistributed earnings of $26.6 million at December 31, 2004. The
Company's investment in the Termoceara Generating Facility was
approximately $25.2 million, including undistributed earnings of
$4.6 million at December 31, 2003.
Note 3
Goodwill and Other Intangible Assets
The changes in the carrying amount of goodwill for the year ended
December 31, 2004, were as follows:
Balance Goodwill Goodwill Balance
as of Acquired Impaired as of
January 1, During During December 31,
2004 the Year* the Year 2004
(In thousands)
Electric $ --- $ --- $ --- $ ---
Natural gas
distribution --- --- --- ---
Utility services 62,604 28 --- 62,632
Pipeline and energy
services 9,494 --- (4,030) 5,464
Natural gas and oil
production --- --- --- ---
Construction materials
and mining 120,198 254 --- 120,452
Independent power production 7,131 4,064 --- 11,195
Other --- --- --- ---
Total $199,427 $4,346 $(4,030) $199,743
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
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 7,131 --- 7,131
Other --- --- ---
Total $190,999 $8,428 $199,427
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Innovatum, which specializes in cable and pipeline magnetization
and location, developed a hand-held locating device that can
detect both magnetic and plastic materials, including unexploded
ordnance. Innovatum was working with, and had demonstrated the
device to, a Department of Defense contractor and had also met
with individuals from the Department of Defense, to discuss the
possibility of using the hand-held locating device in their
operations. In the third quarter of 2004, after communications
with the Department of Defense, and delays in further testing
resulting from a Department of Defense request to enhance the hand-
held locating device, Innovatum decreased its expected future cash
flows from the hand-held locating device. This decrease, coupled
with the continued downturn in the telecommunications and energy
industries, resulted in a revised earnings forecast for Innovatum,
and as a result, a goodwill impairment loss of $4.0 million
(before and after tax), which was included in asset impairments,
was recognized in the third quarter of 2004. Innovatum, a
reporting unit for goodwill impairment testing, is part of the
pipeline and energy services segment. The fair value of Innovatum
was estimated using the expected present value of future cash
flows.
As discussed in Note 1, the Company reclassified its leasehold
rights at its construction materials and mining operations from
other intangible assets, net, to property, plant and equipment.
Other intangible assets at December 31, 2004 and 2003 were as
follows:
2004 2003
(In thousands)
Amortizable intangible assets:
Acquired contracts $15,041 $12,656
Accumulated amortization (5,013) (1,944)
10,028 10,712
Noncompete agreements 10,575 12,075
Accumulated amortization (8,186) (9,690)
2,389 2,385
Other 9,535 5,078
Accumulated amortization (534) (321)
9,001 4,757
Unamortizable intangible assets 851 960
Total $22,269 $18,814
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, 2004, 2003 and 2002, was $3.8 million,
$2.2 million and $757,000, respectively. Estimated amortization
expense for amortizable intangible assets is $2.8 million in 2005,
$2.0 million in 2006, 2007 and 2008, $1.9 million in 2009 and
$10.7 million thereafter.
Note 4
Regulatory Assets and Liabilities
The following table summarizes the individual components of
unamortized regulatory assets and liabilities as of December 31:
2004 2003
(In thousands)
Regulatory assets:
Deferred income taxes $ 39,212 $ 37,072
Natural gas costs recoverable
through rate adjustments 15,534 10,519
Plant costs 12,838 2,697
Long-term debt refinancing costs 3,531 4,519
Postretirement benefit costs 507 562
Other 7,225 7,159
Total regulatory assets 78,847 62,528
Regulatory liabilities:
Plant removal and decommissioning costs 78,525 76,176
Liabilities for regulatory matters 18,853 11,970
Taxes refundable to customers 15,660 18,973
Deferred income taxes 15,192 10,663
Other 3,676 658
Total regulatory liabilities 131,906 118,440
Net regulatory position $(53,059) $(55,912)
As of December 31, 2004, a large portion of the Company's
regulatory assets, other than certain deferred income taxes, was
being reflected in rates charged to customers and is being
recovered over the next one to 18 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
Derivative instruments (including certain derivative instruments
embedded in other contracts) are required to be recorded on the
balance sheet as either an asset or liability measured at its fair
value. Changes in the derivative instrument's fair value are
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.
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; if the derivative instrument expires or is sold,
terminated or exercised; 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, 2004, Fidelity held derivative instruments
designated as cash flow hedging instruments.
Hedging activities
Fidelity 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 its 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, 2004, 2003 and 2002, the amount
of hedge ineffectiveness, which was included in operating
revenues, was immaterial. For the years ended December 31, 2004,
2003 and 2002, Fidelity 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, 2004, the maximum term of
Fidelity's swap and collar agreements, in which Fidelity is
hedging its exposure to the variability in future cash flows for
forecasted transactions, is 12 months. Fidelity estimates that
over the next 12 months, net losses of approximately $4.4 million
will be reclassified from accumulated other comprehensive loss
into earnings, subject to changes in natural gas and oil market
prices, as the hedged transactions affect earnings.
Note 6
Fair Value of Other Financial Instruments
The estimated fair value of the Company's long-term debt is based
on quoted market prices of the same or similar issues. The
estimated fair values of the Company's natural gas and oil price
swap and collar agreements were included in current liabilites at
December 31, 2004 and 2003. The estimated fair values of the
Company's natural gas and oil price swap and collar agreements
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 and
natural gas and oil price swap and collar agreements at
December 31 was as follows:
2004 2003
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $945,487 $992,172 $967,096 $1,012,547
Natural gas and oil
price swap and
collar agreements $ (7,101) $ (7,101) $ (5,467) $ (5,467)
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
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 was as follows:
2004 2003
(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 7.75%, due on
dates ranging from April 1, 2007
to April 1, 2012 95,000 110,000
Senior Note, 5.98%, due December 15, 2033 30,000 30,000
Total first mortgage bonds and notes 145,850 160,850
Senior notes at a weighted
average rate of 6.23%, due on
dates ranging from January 18, 2005
to July 1, 2019 728,500 718,000
Commercial paper at a weighted average
rate of 2.28%, supported by revolving
credit agreements 63,000 72,500
Term credit agreements at a weighted
average rate of 6.68%, due on dates
ranging from January 25, 2005
to December 1, 2013 8,172 14,286
Pollution control note obligation,
6.20%, paid in 2004 --- 1,500
Discount (35) (40)
Total long-term debt 945,487 967,096
Less current maturities 72,046 27,646
Net long-term debt $873,441 $939,450
The amounts of scheduled long-term debt maturities for the five
years and thereafter following December 31, 2004, aggregate $72.0
million in 2005; $138.8 million in 2006; $132.9 million in 2007;
$161.3 million in 2008; $86.9 million in 2009 and $353.6 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, 2004.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at December 31, 2004. There were no amounts
outstanding under the credit agreement at December 31, 2004 and
2003. The credit agreement supports the Company's $75 million
commercial paper program. Under the Company's commercial paper
program, $37.0 million and $40.0 million were outstanding at
December 31, 2004 and 2003, respectively, which was classified as
long-term debt. The commercial paper borrowings classified as
long-term debt are intended to be refinanced on a long-term basis
through continued commercial paper borrowings and as further
supported by the credit agreement, which expires on July 18, 2006.
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. MDU
Resources was in compliance with these covenants and met the
required conditions at December 31, 2004.
There are no credit facilities that contain cross-default
provisions between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require MDU
Resources to fund $1.43 of unfunded property or use $1.00 of
refunded bonds for each dollar of indebtedness incurred under the
Indenture and, in some cases, to certify to the trustee 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
tests, as of December 31, 2004, the Company could have issued
approximately $343 million of additional first mortgage bonds.
Approximately $419.7 million of the Company's net electric and
natural gas distribution properties at December 31, 2004, 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 has three revolving credit agreements with various
banks and institutions that support $335 million of Centennial's
$350 million commercial paper program. There were no outstanding
borrowings under the Centennial credit agreements at December 31,
2004 or 2003. Under the Centennial commercial paper program,
$26.0 million and $32.5 million were outstanding at December 31,
2004 and 2003, 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. One of these
credit agreements is for $300 million and expires on August 17,
2007, and another agreement is for $25 million and expires on
April 30, 2007. Centennial intends to negotiate the extension or
replacement of these agreements prior to their maturities. The
third agreement is an uncommitted line for $10 million, which was
effective on January 25, 2005, and may be terminated by the bank
at any time.
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, 2004 and 2003. The ability to request additional
borrowings under this master shelf agreement expires on February
28, 2005. The Company is in discussion regarding potential
renewal of this facility. 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, 2004.
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, 2004 and 2003. The ability to request
additional borrowings under this master shelf agreement expires on
December 20, 2005.
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, 2004.
Note 8
Asset Retirement Obligations
The Company adopted SFAS No. 143 on January 1, 2003. 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, which is included in
other liabilities, for the years ended December 31 was as follows:
2004 2003
(In thousands)
Balance at beginning of year $34,633 $29,997
Liabilities incurred 3,718 2,405
Liabilities acquired 178 1,803
Liabilities settled (2,286) (1,555)
Accretion expense 1,931 1,906
Revisions in estimates (824) 77
Balance at end of year $37,350 $34,633
The fair value of assets that are legally restricted for purposes
of settling asset retirement obligations at December 31, 2004 and
2003, was $5.2 million and $5.1 million, respectively.
Note 9
Preferred Stocks
Preferred stocks at December 31 were as follows:
2004 2003
(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:
4.50% Series -- 100,000 shares $10,000 $10,000
4.70% Series -- 50,000 shares 5,000 5,000
Total preferred stocks $15,000 $15,000
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 10
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.
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, 2002, 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, 2004, there were
12.1 million shares of common stock reserved for original issuance
under the Stock Purchase Plan and K-Plan.
In 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 11
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, 2004, 2003 and 2002, 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,
2004, 2003 and 2002, and changes during the years then ended were
as follows:
2004 2003 2002
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 4,182,456 $19.09 4,861,268 $18.58 5,208,311 $18.60
Granted --- --- 27,015 17.29 160,605 19.15
Forfeited (382,942) 19.64 (188,486) 20.05 (453,840) 19.77
Exercised (1,237,830) 18.49 (517,341) 13.88 (53,808) 12.20
Balance at end
of year 2,561,684 19.29 4,182,456 19.09 4,861,268 18.58
Exercisable at
end of year 1,700,223 $18.73 611,404 $15.06 1,135,050 $14.56
Summarized information about stock options outstanding and exercisable as
of December 31, 2004, 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 11,076 2.3 $10.69 11,076 $10.69
13.01 - 17.00 374,050 3.4 14.20 371,404 14.19
17.01 - 21.00 1,977,433 6.2 19.77 1,243,108 19.78
21.01 - 25.70 199,125 6.2 24.55 74,635 24.97
Balance at end of year 2,561,684 5.8 19.29 1,700,223 18.73
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:
2004 2003 2002
Weighted average fair value of options
at grant date --- $4.67 $5.38
Weighted average risk-free interest rate --- 3.91% 5.14%
Weighted average expected price volatility --- 32.28% 30.80%
Weighted average expected dividend yield --- 3.43% 3.43%
Expected life in years --- 7 7
In addition, prior to 2002 the Company granted restricted stock
awards under a long-term incentive plan and deferred compensation
agreements. The restricted stock awards granted vest to the
participants at various times ranging from one year 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 Company also has granted stock
awards totaling 35,205 shares, 31,855 shares and 21,390 shares in
2004, 2003 and 2002, respectively, under a nonemployee director
stock compensation plan. The weighted average grant date fair
value of the stock grants was $23.61, $21.40 and $19.20, in 2004,
2003 and 2002, 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 $3.4 million, $4.8 million and $5.2 million in
2004, 2003 and 2002, respectively.
In 2004 and 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 59,224
February 2003 2003-2005 54,180
February 2004 2004-2006 189,337
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 years ended December 31, 2004 and 2003, was $2.5 million
and $879,000, respectively.
The Company is authorized to grant options, restricted stock and
stock for up to 14.7 million shares of common stock and has
granted options, restricted stock and stock on 5.8 million shares
through December 31, 2004.
Note 12
Income Taxes
The components of income before income taxes for each of the years
ended December 31 were as follows:
2004 2003 2002
(In thousands)
United States $280,764 $278,143 $233,536
Foreign 20,277 3,342 1,138
Income before income taxes $301,041 $281,485 $234,674
Income tax expense for the years ended December 31 was as follows:
2004 2003 2002
(In thousands)
Current:
Federal $47,625 $26,313 $46,389
State 12,231 7,408 9,082
Foreign 955 264 ---
60,811 33,985 55,471
Deferred:
Income taxes --
Federal 28,556 55,660 26,373
State 5,422 9,861 4,632
Foreign (223) (338) 338
Investment tax credit (592) (596) (584)
33,163 64,587 30,759
Total income tax expense $93,974 $98,572 $86,230
Components of deferred tax assets and deferred tax liabilities
recognized at December 31 were as follows:
2004 2003
(In thousands)
Deferred tax assets:
Regulatory matters $ 39,212 $ 37,072
Accrued pension costs 18,754 12,122
Asset retirement obligations 12,197 7,017
Deferred compensation 9,938 9,090
Bad debts 2,266 3,188
Deferred investment tax credit 724 954
Other 29,237 21,269
Total deferred tax assets 112,328 90,712
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 450,237 406,589
Basis differences on natural gas
and oil producing properties 124,788 105,826
Regulatory matters 15,192 10,663
Other 13,826 9,309
Total deferred tax liabilities 604,043 532,387
Net deferred income tax liability $(491,715) $(441,675)
As of December 31, 2004 and 2003, 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, 2003, to December 31, 2004,
to deferred income tax expense:
2004
(In thousands)
Change in net deferred income tax
liability from the preceding table $ 50,040
Deferred taxes associated with acquisitions (16,189)
Other (688)
Deferred income tax expense for the period $ 33,163
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, 2004 2003 2002
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $105,364 35.0 $98,520 35.0 $82,136 35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit 11,468 3.8 11,857 4.2 10,279 4.4
Audit resolution (8,818) (2.9) --- --- --- ---
Foreign operations (5,648) (1.9) (832) (.3) 177 ---
Depletion allowance (3,418) (1.2) (3,117) (1.1) (2,200) (.9)
Renewable electricity
production credit (3,404) (1.1) (3,395) (1.2) --- ---
Other items (1,570) (.5) (4,461) (1.6) (4,162) (1.8)
Total income tax expense $ 93,974 31.2 $98,572 35.0 $86,230 36.7
In 2004, the Company resolved federal and related state income tax
matters for the 1998 through 2000 tax years. The Company
reflected the effects of this tax resolution and, in addition,
reversed liabilities that had previously been provided and were
deemed to be no longer required, which resulted in a benefit of
$8.3 million (after tax), including interest.
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. The cumulative
undistributed earnings at December 31, 2004, were approximately
$22 million. The amount of unrecognized deferred tax liability
associated with the undistributed earnings was approximately $5
million.
The Company has evaluated the repatriation provisions of the
American Jobs Creation Act of 2004 (Act), which was enacted on
October 22, 2004. The provisions of the Act permit corporations
to elect an 85-percent deduction for certain qualifying dividends
received during 2005 from controlled foreign corporations. The
deduction is only available to the extent that the dividend is in
excess of an historical base-period average and if the dividend is
invested in the United States pursuant to a qualifying domestic
investment plan. At this time, the Company does not anticipate
that it will be receiving dividends qualifying for this election
during 2005.
Note 13
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. Prior to the fourth quarter of 2004, the
Company reported 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. The independent power production and other
operations did not individually meet the criteria to be considered
a reportable segment. In the fourth quarter of 2004, the Company
separated independent power production as a reportable business
segment due to the significance of its operations. The Company's
operations are now conducted through seven reportable segments and
all prior period information has been restated to reflect this
change.
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 investments in natural gas-
fired electric generating facilities in Brazil and Trinidad and
Tobago, 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, development 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 segment owns, builds and operates
electric generating facilities in the United States and has
investments in domestic and international natural resource-based
projects. Electric capacity and energy produced at its power
plants are sold primarily under mid- and long-term contracts to
nonaffiliated entities.
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:
2004 2003 2002
(In thousands)
External operating revenues:
Electric $ 178,803 $ 178,562 $ 162,616
Natural gas distribution 316,120 274,608 186,569
Pipeline and energy services 281,913 187,892 110,224
776,836 641,062 459,409
Utility services 425,250 434,177 458,660
Natural gas and oil production 152,486 140,281 148,158
Construction materials and mining 1,321,626 1,104,408 962,312
Independent power production 43,059 32,261 2,998
Other --- --- ---
1,942,421 1,711,127 1,572,128
Total external operating revenues $2,719,257 $2,352,189 $2,031,537
Intersegment operating revenues:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services 1,571 --- ---
Pipeline and energy services 75,316 64,300 55,034
Natural gas and oil production 190,354 124,077 55,437
Construction materials and mining 535 --- ---
Independent power production --- --- ---
Other 4,423 2,728 3,778
Intersegment eliminations (272,199) (191,105) (114,249)
Total intersegment
operating revenues $ --- $ --- $ ---
Depreciation, depletion and
amortization:
Electric $ 20,199 $ 20,150 $ 19,537
Natural gas distribution 9,329 10,044 9,940
Utility services 11,113 10,353 9,871
Pipeline and energy services 17,804 15,016 14,846
Natural gas and oil production 70,823 61,019 48,714
Construction materials and mining 69,644 63,601 54,334
Independent power production 9,587 7,860 444
Other 271 294 275
Total depreciation, depletion
and amortization $ 208,770 $ 188,337 $ 157,961
Interest expense:
Electric $ 9,116 $ 8,013 $ 7,621
Natural gas distribution 4,292 3,936 4,364
Utility services 3,442 3,668 3,568
Pipeline and energy services 9,262 7,952 7,670
Natural gas and oil production 7,552 4,767 2,464
Construction materials and mining 20,646 18,747 18,422
Independent power production 4,354 5,850 1,100
Other (70) 15 22
Intersegment eliminations (1,157) (154) (216)
Total interest expense $ 57,437 $ 52,794 $ 45,015
Income taxes:
Electric $ 4,303 $ 9,862 $ 9,501
Natural gas distribution (3,883) 1,823 (1,325)
Utility services (3,345) 3,905 4,781
Pipeline and energy services 7,445 11,188 12,462
Natural gas and oil production 61,261 42,993 30,604
Construction materials and mining 26,674 28,168 29,415
Independent power production 1,249 257 406
Other 270 376 386
Total income taxes $ 93,974 $ 98,572 $ 86,230
Cumulative effect of accounting
change (Note 8):
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 --- --- ---
Other --- --- ---
Total cumulative effect of
accounting change $ --- $ (7,589) $ ---
Earnings on common stock:
Electric $ 12,790 $ 16,950 $ 15,780
Natural gas distribution 2,182 3,869 3,587
Utility services (5,650) 6,170 6,371
Pipeline and energy services 8,944 18,158 19,097
Natural gas and oil production 110,779 63,027 53,192
Construction materials and mining 50,707 54,412 48,702
Independent power production 26,309 11,415 307
Other 321 606 652
Total earnings on common stock $ 206,382 $ 174,607 $ 147,688
Capital expenditures:
Electric $ 18,767 $ 28,537 $ 27,795
Natural gas distribution 17,384 15,672 11,044
Utility services 8,470 7,820 17,242
Pipeline and energy services 38,282 93,004 21,449
Natural gas and oil production 111,506 101,698 136,424
Construction materials and mining 133,080 128,487 106,893
Independent power production 76,246 110,963 89,621
Other 4,215 1,895 6,127
Net proceeds from sale or
disposition of property (20,518) (14,439) (16,217)
Total net capital expenditures $ 387,432 $ 473,637 $ 400,378
Identifiable assets:
Electric* $ 323,819 $ 327,899 $ 322,475
Natural gas distribution* 252,582 234,948 208,502
Utility services 230,955 221,824 230,888
Pipeline and energy services 447,302 405,904 312,858
Natural gas and oil production 685,610 602,389 554,420
Construction materials and mining 1,345,547 1,248,607 1,137,697
Independent power production 349,752 241,918 130,867
Other** 97,954 97,103 99,214
Total identifiable assets $3,733,521 $3,380,592 $2,996,921
Property, plant and equipment:
Electric* $ 650,902 $ 639,893 $ 619,230
Natural gas distribution* 264,496 252,591 244,930
Utility services 82,600 76,871 70,660
Pipeline and energy services 492,400 461,793 372,420
Natural gas and oil production 982,625 871,357 755,788
Construction materials and mining 1,190,468 1,080,399 976,751
Independent power production 250,602 184,127 79,373
Other 17,335 17,007 15,152
Less accumulated depreciation,
depletion and amortization 1,358,723 1,187,105 1,026,932
Net property, plant and equipment $2,572,705 $2,396,933 $2,107,372
* Includes allocations of common utility property.
** Includes assets not directly assignable to a business
(i.e., cash and cash equivalents, certain accounts receivable and
other miscellaneous current and deferred assets).
Excluding the asset impairments at the pipeline and energy
services segment of $5.3 million (after tax), 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, independent power production,
and other are all from nonregulated operations. Capital
expenditures for 2004, 2003 and 2002, related to acquisitions, in
the preceding table included the following noncash transactions:
issuance of the Company's equity securities of $33.1 million,
$42.4 million and $47.2 million in 2004, 2003 and 2002,
respectively.
Note 14
Acquisitions
In 2004, the Company acquired a number of businesses, none of
which was individually material, including construction materials
and mining businesses in Hawaii, Idaho, Iowa and Minnesota and an
independent power production operating and development company in
Colorado. The total purchase consideration for these businesses
and adjustments with respect to certain other acquisitions
acquired prior to 2004, consisting of the Company's common stock
and cash, was $70.3 million.
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,
consisting of 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 April 2000, Fidelity 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 the
Seller's Option Interest from Preston for an amount as specified
in the agreement. In July 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
2004. 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 15
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. As discussed in Note 1,
the Company recognized the effects of the 2003 Medicare Act during
the second quarter of 2004. The net periodic benefit cost for
2004 reflects the effects of the 2003 Medicare Act. 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
2004 2003 2004 2003
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $261,335 $224,766 $88,381 $74,917
Service cost 7,667 5,897 1,826 1,857
Interest cost 15,903 15,211 4,312 5,281
Plan participants' contributions --- --- 1,133 977
Amendments --- 210 (773) 754
Actuarial (gain) loss 12,240 27,701 (14,951) 10,338
Benefits paid (12,389) (12,450) (4,437) (5,743)
Benefit obligation at
end of year 284,756 261,335 75,491 88,381
Change in plan assets:
Fair value of plan assets at
beginning of year 223,043 189,143 47,234 40,889
Actual gain on plan assets 27,264 43,087 2,920 6,148
Employer contribution 1,604 3,263 4,127 4,963
Plan participants' contributions --- --- 1,134 977
Benefits paid (12,389) (12,450) (4,437) (5,743)
Fair value of plan assets at end
of year 239,522 223,043 50,978 47,234
Funded status - under (45,234) (38,292) (24,513) (41,147)
Unrecognized actuarial (gain) loss 46,293 41,422 (1,832) 11,862
Unrecognized prior service cost 7,435 8,556 --- 706
Unrecognized net transition
obligation (asset) (47) (297) 16,999 19,362
Prepaid (accrued) benefit cost $ 8,447 $ 11,389 $(9,346) $(9,217)
Amounts recognized in the
Consolidated Balance Sheets
at December 31:
Prepaid benefit cost $19,020 $ 19,671 $ 572 $ 614
Accrued benefit liability (10,573) (8,282) (9,918) (9,831)
Net amount recognized $ 8,447 $ 11,389 $(9,346) $(9,217)
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 $227.3 million and $212.0 million at
December 31, 2004 and 2003, 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, 2004 and 2003, were as follows:
2004 2003
(In thousands)
Projected benefit obligation $174,983 $38,845
Accumulated benefit obligation $136,012 $28,840
Fair value of plan assets $132,280 $24,508
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, 2004 2003 2002 2004 2003 2002
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 7,667 $ 5,897 $ 5,135 $1,826 $1,857 $1,460
Interest cost 15,903 15,211 14,877 4,312 5,281 4,915
Expected return on assets (20,375) (20,730) (21,110) (3,943) (3,933) (3,843)
Amortization of prior
service cost 1,121 1,156 1,148 144 48 ---
Recognized net actuarial
(gain) loss 480 (417) (1,855) (233) (255) (566)
Amortization of net
transition obligation
(asset) (250) (950) (947) 2,151 2,151 2,151
Net periodic benefit cost
(income) 4,546 167 (2,752) 4,257 5,149 4,117
Less amount capitalized 409 14 (352) 440 601 404
Net periodic benefit cost
(income) $ 4,137 $ 153 $(2,400) $3,817 $4,548 $3,713
Weighted average assumptions used to determine benefit obligations
at December 31 were as follows:
Other
Pension Postretirement
Benefits Benefits
2004 2003 2004 2003
Discount rate 5.75% 6.00% 5.75% 6.00%
Rate of compensation increase 4.70% 4.70% 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
2004 2003 2004 2003
Discount rate 6.00% 6.75% 6.00% 6.75%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 4.70% 4.50% 4.50% 4.50%
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:
2004 2003
Health care trend rate assumed for next year 6.0%-9.5% 6.0%-9.5%
Health care cost trend rate - ultimate 5.0%-6.0% 5.0%-6.0%
Year in which ultimate trend rate achieved 1999-2013 1999-2012
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, 2004:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 218 $ (872)
Effect on postretirement
benefit obligation $ 3,176 $(8,489)
The Company's defined benefit pension plans' asset allocation at
December 31, 2004 and 2003, and weighted average targeted asset
allocations at December 31, 2004, were as follows:
Weighted Average
Percentage Targeted Asset
of Plan Allocation
Assets Percentage
Asset Category 2004 2003 2004
Equity securities 74% 72% 70%
Fixed income securities 24 25 30*
Other 2 3 ---
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, 2004 and 2003, and weighted average targeted asset
allocation at December 31, 2004, were as follows:
Weighted Average
Percentage Targeted Asset
of Plan Allocation
Assets Percentage
Asset Category 2004 2003 2004
Equity securities 70% 66% 70%
Fixed income securities 28 30 30*
Other 2 4 ---
Total 100% 100% 100%
*Includes target for both fixed income securities and other.
The Company expects to contribute approximately $900,000 to its
defined benefit pension plans and approximately $3.8 million to
its postretirement benefit plans in 2005.
The following benefit payments, which reflect future service, as
appropriate, are expected to be paid:
Other
Pension Postretirement
Years Benefits Benefits
(In thousands)
2005 $12,403 $ 5,908
2006 12,726 5,666
2007 13,248 5,941
2008 13,830 6,204
2009 14,720 6,493
2010-2014 89,922 38,302
The following Medicare Part D subsidies are expected: none in
2005; $436,000 in 2006; $439,000 in 2007; $440,000 in 2008;
$438,000 in 2009 and $2.2 million during the years 2010 through
2014.
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
$28.2 million, $27.2 million and $27.8 million in 2004, 2003 and
2002, respectively.
In addition to the qualified plan defined pension benefits
reflected in the table at the beginning of this note, the Company
also has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that generally
provides for defined benefit payments at age 65 following the
employee's retirement or to their beneficiaries upon death for a
15-year period. Investments, at December 31, 2004, consisted of
cash equivalents and life insurance carried on plan participants,
which is payable to the Company upon the employee's death. The
Company's net periodic benefit cost for this plan was
$7.5 million, $5.3 million and $5.1 million in 2004, 2003 and
2002, respectively. The total projected obligation for this plan
was $65.3 million and $51.1 million at December 31, 2004 and 2003,
respectively. The accumulated benefit obligation for this plan
was $52.3 million and $40.7 million at December 31, 2004 and 2003,
respectively. The additional minimum liability relating to this
plan was $14.3 million and $8.2 million at December 31, 2004 and
2003, respectively. The Company has a related intangible asset
recognized as of December 31, 2004 and 2003, of $851,000 and
$1.0 million, respectively. A discount rate of 5.75 percent and
6.0 percent at December 31, 2004 and 2003, respectively, and a
rate of compensation increase of 4.75 percent at both December 31,
2004 and 2003, were used to determine benefit obligations.
A discount rate of 6.00 percent and 6.75 percent at December 31,
2004 and 2003, respectively, and a rate of compensation increase
of 4.75 percent and 4.50 percent at December 31, 2004 and 2003,
respectively, were used to determine net periodic benefit cost.
The increase in minimum liability included in other comprehensive
income was $3.8 million in 2004 and $2.6 million in 2003.
The amount of benefit payments for the unfunded, nonqualified
benefit plan, as appropriate, are expected to aggregate $2.5
million in 2005; $2.6 million in 2006; $3.1 million in 2007;
$3.2 million in 2008; $3.3 million in 2009 and $20.0 million for
the years 2010 through 2014.
The Company sponsors various defined contribution plans for
eligible employees. Costs incurred by the Company under these
plans were $13.8 million in 2004, $9.8 million in 2003 and
$9.6 million in 2002. The costs incurred in each year reflect
additional participants as a result of business acquisitions.
Note 16
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:
2004 2003
(In thousands)
Big Stone Station:
Utility plant in service $ 52,157 $ 52,154
Less accumulated depreciation 36,488 34,993
$ 15,669 $ 17,161
Coyote Station:
Utility plant in service $124,388 $124,086
Less accumulated depreciation 74,671 72,850
$ 49,717 $ 51,236
Note 17
Regulatory Matters and Revenues Subject To Refund
On September 7, 2004, Great Plains filed an application with the
MPUC for a natural gas rate increase. Great Plains had requested
a total of $1.4 million annually or 4.0 percent above current
rates. Great Plains also requested an interim increase of $1.4
million annually. On November 23, 2004, the MPUC issued an Order
setting interim rates of $1.4 million annually effective with
service rendered on or after January 10, 2005, subject to refund.
A final order from the MPUC is expected in late 2005.
On June 7, 2004, Montana-Dakota filed an application with the
SDPUC for a natural gas rate increase for the Black Hills service
area. Montana-Dakota requested a total of $1.3 million annually
or 2.2 percent above current rates. On November 15, 2004, Montana-
Dakota and the SDPUC Staff filed a Settlement Stipulation with the
SDPUC agreeing to an increase of $670,000 annually, or 1.4
percent. On November 30, 2004, the SDPUC approved the Settlement
Stipulation effective with service rendered on or after December
1, 2004.
On April 1, 2004, Montana-Dakota filed an application with the
MTPSC for a natural gas rate increase. Montana-Dakota requested a
total of $1.5 million annually or 1.8 percent above current
rates. On January 14, 2005, Montana-Dakota and the Montana
Consumer Counsel filed a Stipulation with the MTPSC agreeing to an
increase of $125,000 annually to be effective with service
rendered on or after February 1, 2005. On January 25, 2005, the
MTPSC passed a Motion approving the Stipulation.
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 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. In July 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. In August 2003, Williston Basin
requested 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 May 11, 2004, the FERC issued an Order on Rehearing.
The Order on Rehearing denied rehearing on all of the issues
addressed by Williston Basin in its August 2003 request for
rehearing except for the issue of the proper rate to utilize for
transmission system negative salvage expenses. In addition, the
FERC remanded the issues regarding certain service and annual
demand quantity restrictions to an ALJ for resolution. On June
14, 2004, Williston Basin requested clarification of a few of the
issues addressed in the Order on Rehearing including
determinations associated with cost of service and cost
allocation, as discussed in the FERC's Order on Rehearing. On
June 14, 2004, Williston Basin also made its filing to comply with
the requirements of the various FERC orders in this proceeding.
Williston Basin is awaiting a decision from the FERC on Williston
Basin's compliance filing and clarification request but is unable
to predict the timing of the FERC's decision. Williston Basin
participated in a hearing before the ALJ in early January 2005,
regarding the matters remanded to the ALJ by the FERC in its Order
on Rehearing and an order on these matters is expected in 2005.
A liability has 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 the liability is adequate based on its assessment of the
ultimate outcome of the proceeding.
Note 18
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, Grynberg filed suit under the Federal False Claims
Act 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.
On June 4, 2004, following preliminary discovery, Williston Basin
and Montana-Dakota joined with other defendants and filed a Motion
to Dismiss on the grounds that the information upon which Grynberg
based his complaint was publicly disclosed prior to the filing of
his complaint and further, that he is not the original source of
such information. The Motion to Dismiss is additionally based on
the grounds that Grynberg disclosed the filing of the complaint
prior to the entry of a court order allowing such disclosure and
that Grynberg failed to provide adequate information to the
government prior to filing suit.
In the event the Motion to Dismiss is not granted, it is expected
that further discovery will follow. Williston Basin and Montana-
Dakota believe Grynberg will not prevail in the suit or recover
damages from Williston Basin and/or Montana-Dakota because
insufficient facts exist to support the allegations. Williston
Basin and Montana-Dakota believe Grynberg's claims are without
merit and intend to vigorously contest this suit.
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.
Fidelity has been named as a defendant in, and/or certain of its
operations are or have been the subject of, more than a dozen
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 November 2004 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. Portions of 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, the National Environmental Policy Act, the
Federal Land Management Policy Act, the National Historic
Preservation Act and the Montana Environmental Policy Act. The
cases involving alleged violations of the Federal Clean Water Act
have been resolved without a finding that Fidelity is in violation
of the Federal Clean Water Act. There presently are no claims
pending for penalties, fines or damages under the Federal Clean
Water Act. The suits that remain extant include a variety of
claims that state and federal government agencies violated various
environmental laws that impose procedural requirements and the
lawsuits seek injunctive relief, invalidation of various permits
and unspecified damages. Fidelity is unable to quantify the
damages sought in any of these cases, and will be unable to do so
until after completion of discovery in these separate cases.
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 Health Department in
September 2003 that the North Dakota Health 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 North Dakota
Health 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 in October 2003, in the
Burleigh County District Court in Bismarck, North Dakota.
Proceedings have been stayed pending discussions with the EPA, the
North Dakota Health Department and the other electric generators.
In a related matter, the state of North Dakota and the EPA entered
into a MOU on February 24, 2004, establishing the principles to be
used by the state of North Dakota in completing dispersion
modeling of air quality in Theodore Roosevelt National Park and
other "Class I" areas in North Dakota and Montana. In April 2004,
the Dakota Resource Council filed a petition for review of the MOU
with the United States Eighth Circuit Court of Appeals. The
petition was dismissed, without prejudice, in June 2004 upon
stipulation of the EPA, the Dakota Resource Council and the state
of North Dakota. The Company cannot predict the outcome of the
North Dakota Health 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, MBI 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 DEQ are being recorded, and initially paid, through an
administrative consent order by the 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.
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, 2004, were
$14.7 million in 2005, $10.5 million in 2006, $6.6 million in
2007, $5.1 million in 2008, $3.5 million in 2009 and $25.2 million
thereafter. Rent expense was $30.6 million, $27.2 million and
$26.9 million for the years ended December 31, 2004, 2003 and
2002, 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 20 years. The
commitments under these contracts as of December 31, 2004, were
$223.6 million in 2005, $105.7 million in 2006, $65.4 million in
2007, $50.5 million in 2008, $46.9 million in 2009 and $236.4
million thereafter. Amounts purchased under various commitments
for the years ended December 31, 2004, 2003 and 2002, were
approximately $318.3 million, $204.6 million and $152.1 million,
respectively. These commitments are not reflected in the
Company's consolidated financial statements.
In addition to the above obligations, the Company has certain
purchase obligations for natural gas connected to its gathering
system. These purchases and the resale of the natural gas are at
market-based prices. These obligations continue as long as
natural gas is produced. However, if the purchase and resale of
natural gas become uneconomical, the purchase commitments can be
canceled by the Company with 60 days notice. These purchase
obligations are currently estimated at approximately $10 million
annually.
Guarantees
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the Termoceara Generating Facility, 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, 2004, the aggregate amount of
borrowings outstanding subject to these guarantees was $34.9
million and the scheduled repayment of these borrowings is $11.0
million in 2005, $10.7 million in 2006 and 2007 and $2.5 million
in 2008. The individual investor (who through EBX owns 51 percent
of MPX) has also guaranteed these loans. In the event MPX
defaults under its obligation, Centennial and the individual
investor would be required to make payments under their
guarantees, which are joint and several obligations. 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 has guaranteed certain of Fidelity's
natural gas and oil price swap and collar agreement obligations.
Fidelity's obligations at December 31, 2004, were $4.9 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, 2004, expire in 2005; however, Fidelity 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, 2004, the amount
outstanding was reflected on the Consolidated Balance Sheets. In
the event Fidelity 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. These guarantees are related to natural gas
transportation and sales agreements, electric power supply
agreements, insurance policies and certain other guarantees. At
December 31, 2004, the fixed maximum amounts guaranteed under
these agreements aggregated $88.8 million. The amounts of
scheduled expiration of the maximum amounts guaranteed under these
agreements aggregate $40.1 million in 2005; $4.7 million in 2006;
$2.1 million in 2007; $300,000 in 2008; $900,000 in 2009; $22.0
million in 2010; $12.0 million in 2012; $2.2 million in 2028;
$500,000, which is subject to expiration 30 days after the receipt
of written notice and $4.0 million, which has no scheduled
maturity date. The amount outstanding by subsidiaries of the
Company under the above guarantees was $561,000 and was reflected
on the Consolidated Balance Sheets at December 31, 2004. 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, 2004, 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 $1.7 million, which was not reflected on
the Consolidated Balance Sheet at December 31, 2004, because these
intercompany transactions are eliminated in consolidation.
In addition, Centennial has issued guarantees to third parties
related to the Company's routine purchase of maintenance items 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, 2004.
As of December 31, 2004, Centennial was contingently liable for
the performance of certain of its subsidiaries under approximately
$375 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
is 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.
Note 19
Related Party Transactions
In 2004, Bitter Creek entered into two natural gas gathering
agreements with Nance Petroleum Corporation (Nance Petroleum), a
wholly owned subsidiary of St. Mary Land & Exploration Company
(St. Mary). Robert L. Nance, an executive officer and shareholder
of St. Mary, is also a member of the Board of Directors of the
Company. The natural gas gathering agreements with Nance
Petroleum were effective upon completion of certain high and low
pressure gathering facilities, which occurred in mid-December
2004. Bitter Creek's capital expenditures related to the
completion of the gathering lines and the expansion of its
gathering facilities to accommodate the natural gas gathering
agreements were $7.6 million in 2004 and are estimated for the
next three years to be $2.5 million in 2005, $2.2 million in 2006
and $3.3 million in 2007. The natural gas gathering agreements
are each for a term of 15 years and month-to-month thereafter.
Bitter Creek's revenues from these contracts were $37,000 in 2004
and estimated revenues from these contracts for the next three
years are $1.9 million in 2005, $3.8 million in 2006 and $5.8
million in 2007. The amount due from Nance Petroleum at December
31, 2004, was $37,000.
MDU RESOURCES GROUP, INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Quarterly Data (Unaudited)
The following unaudited information shows selected items by
quarter for the years 2004 and 2003:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2004
Operating revenues $515,459 $653,301 $804,598 $745,899
Operating expenses 471,436 568,570 690,022 668,511
Operating income 44,023 84,731 114,576 77,388
Net income 23,580 58,630 71,719 53,138
Earnings per common share:
Basic .20 .50 .61 .45
Diluted .20 .50 .60 .45
Weighted average common shares
outstanding:
Basic 114,658 116,559 117,109 117,582
Diluted 115,709 117,567 118,278 118,596
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
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:
2004 2003 2002
(In thousands)
Subject to amortization $904,620 $758,500 $603,151
Not subject to amortization 68,984 104,339 145,692
Total capitalized costs 973,604 862,839 748,843
Less accumulated depreciation,
depletion and amortization 373,932 305,349 239,964
Net capitalized costs $599,672 $557,490 $508,879
Capital expenditures, including those not subject to amortization,
related to natural gas and oil producing activities were as
follows:
Years ended December 31, 2004* 2003* 2002
(In thousands)
Acquisitions $ 11,219 $ 3,027 $ 31,439
Exploration 21,781 19,193 5,325
Development** 77,940 77,583 94,943
Total capital expenditures $110,940 $99,803 $131,707
* Excludes net 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 8, of $100,000
and $14.7 million for the years ended December 31, 2004 and 2003,
respectively.
**Includes expenditures for proved undeveloped reserves of $30.3
million, $23.3 million and $10.1 million for the years ended
December 31, 2004, 2003 and 2002, 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, 2004 2003 2002*
(In thousands)
Revenues:
Sales to affiliates $190,354 $ 124,077 $ 55,437
Sales to external customers 149,660 140,034 145,170
Production costs 67,125 67,292 52,520
Depreciation, depletion and
amortization** 69,946 60,072 48,064
Pretax income 202,943 136,747 100,023
Income tax expense 73,137 51,925 36,886
Results of operations for
producing activities before
cumulative effect of accounting
change 129,806 84,822 63,137
Cumulative effect of accounting
change --- (7,740) ---
Results of operations for
producing activities $129,806 $ 77,082 $ 63,137
* Includes the compromise agreement as discussed in Note 18.
**Includes $1.4 million of accretion of discount for asset
retirement obligations for each of the years ended December 31,
2004 and 2003, in accordance with SFAS No. 143, as discussed in
Note 8.
The following table summarizes the Company's estimated quantities
of proved natural gas and oil reserves at December 31, 2004, 2003
and 2002, 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.
2004 2003 2002
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(In thousands of Mcf/barrels)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 411,700 18,900 372,500 17,500 324,100 17,500
Production (59,700) (1,800) (54,700) (1,900) (48,200) (2,000)
Extensions and
discoveries 100,700 500 113,300 3,300 80,100 2,200
Purchases of proved
reserves 100 --- 900 --- 1,200 100
Sales of reserves
in place --- --- --- (100) (4,400) (300)
Revisions of previous
estimates 400 (500) (20,300) 100 19,700 ---
Balance at end
of year 453,200 17,100 411,700 18,900 372,500 17,500
Proved developed reserves:
January 1, 2002 291,300 17,100
December 31, 2002 331,300 14,800
December 31, 2003 342,800 15,000
December 31, 2004 376,400 16,400
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:
2004 2003 2002
(In thousands)
Future cash inflows $2,848,800 $2,547,400 $1,726,000
Future production costs 803,600 651,300 513,200
Future development costs 62,800 67,100 61,200
Future net cash flows before
income taxes 1,982,400 1,829,000 1,151,600
Future income tax expense 645,300 601,000 324,000
Future net cash flows 1,337,100 1,228,000 827,600
10% annual discount for estimated
timing of cash flows 515,600 491,200 321,300
Discounted future net cash flows
relating to proved natural gas
and oil reserves $ 821,500 $ 736,800 $ 506,300
The following are the sources of change in the standardized
measure of discounted future net cash flows by year:
2004 2003 2002
(In thousands)
Beginning of year $ 736,800 $506,300 $ 262,000
Net revenues from production (291,600) (220,000) (112,900)
Change in net realization 32,800 318,600 296,100
Extensions, discoveries and
improved recovery, net of
future production-related costs 240,200 245,800 117,000
Purchases of proved reserves 300 2,800 3,700
Sales of reserves in place --- (600) (8,900)
Changes in estimated future
development costs (5,300) (4,000) (1,100)
Development costs incurred
during the current year 39,800 35,300 19,400
Accretion of discount 97,100 62,400 27,300
Net change in income taxes (36,400) (172,000) (124,700)
Revisions of previous
estimates 9,600 (35,500) 30,000
Other (1,800) (2,300) (1,600)
Net change 84,700 230,500 244,300
End of year $ 821,500 $736,800 $ 506,300
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end natural
gas 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 as of December 31, 2004, are $37.9 million in 2005, $7.6
million in 2006 and none in 2007. 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.
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.
Management's Annual Report on Internal Control Over Financial
Reporting
The information required by this item is included in this Form 10-
K at Item 8 -- Financial Statements and Supplementary Data -
Management's Report on Internal Control over Financial Reporting.
Attestation Report of the Registered Public Accounting Firm
The information required by this item is included in this Form 10-
K at Item 8 -- Financial Statements and Supplementary Data -
Report of Independent Registered Public Accounting Firm.
ITEM 9B. OTHER INFORMATION
None.
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,"
"Section 16(a) Beneficial Ownership Reporting Compliance,"
"Board and Board Committees" and "Nominating and Governance
Committee" in the Company's 2005 Proxy Statement (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 "Re-approval of 1997 Executive
LTIP Performance Goals" 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 AND FINANCIAL STATEMENT SCHEDULES
(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, 2004
Consolidated Balance Sheets at December 31, 2004
and 2003
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 2004
Consolidated Statements of Cash Flows for each
of the three years in the period ended
December 31, 2004
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
MDU Resources Group, Inc.
Schedule II - Consolidated Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
Additions
_______________________
Balance at Charged to
Beginning Costs and Balance at
Description of Year Expenses Other* Deductions** End of Year
(In thousands)
Allowance for
doubtful
accounts:
2004 $8,146 $2,663 $ 703 $4,711 $6,801
2003 8,237 3,185 1,123 4,399 8,146
2002 5,773 8,192 1,164 6,892 8,237
* Allowance for doubtful accounts for companies acquired and recoveries.
** 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, filed as
Exhibit 4(e) to Form 10-K for the year
ended December 31, 2003, in File No. 1-3480 *
+ 10(a) MDU Resources Group, Inc. Executive
Incentive Compensation Plan, as amended,
filed as Exhibit 10(a) to Form 10-Q for the
quarter ended September 30, 2004, in File
No. 1-3480 *
+ 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) Montana-Dakota Executive Incentive
Compensation Plan, filed as Exhibit 10(b)
to Form 10-Q for the quarter ended
September 30, 2004, in File No. 1-3480 *
+ 10(j) Performance Share Award Agreement,
filed as Exhibit 10(c) to Form 10-Q for
the quarter ended September 30, 2004, in
File No. 1-3480 *
+ 10(k) 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(l) 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(m) Change of Control Employment Agreement
between the Company and Paul Gatzemeier,
filed as Exhibit 10(a) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(n) Change of Control Employment Agreement
between the Company and Mary B. Hager,
filed as Exhibit 10(b) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(o) 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(p) Change of Control Employment Agreement
between the Company and Bruce T. Imsdahl,
filed as Exhibit 10(c) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(q) 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(r) Change of Control Employment Agreement
between the Company and Cindy C. Redding,
filed as Exhibit 10(d) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(s) 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(t) Change of Control Employment Agreement
between the Company and Paul K. Sandness,
filed as Exhibit 10(e) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(u) 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(v) Change of Control Employment Agreement
between the Company and Daryl A. Splichal,
filed as Exhibit 10(f) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(w) 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(x) Change of Control Employment Agreement
between the Company and Floyd E. Wilson,
filed as Exhibit 10(g) to Form 10-Q for the
quarter ended June 30, 2004, in File
No. 1-3480 *
+ 10(y) 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(z) Agreement on Retirement between the Company
and Lester H. Loble, II, filed as Exhibit 10(v)
to Form 10-K for the year ended December
31, 2003, in File No. 1-3480 *
+ 10(aa) Agreement on Retirement between the Company
and Ronald D. Tipton, filed as Exhibit 10(d)
to Form 10-Q for the quarter ended September
30, 2004, in File No. 1-3480 *
+ 10(ab) 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(ac) 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(ad) 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(ae) The Wagner-Smith Company Deferred
Compensation Plan, filed as Exhibit 10(w)
to Form 10-K for the year ended December 31,
2003, in File No. 1-3480 *
+ 10(af) Wagner-Smith Equipment Co. Deferred
Compensation Plan, filed as Exhibit 10(x)
to Form 10-K for the year ended December 31,
2003, in File No. 1-3480 *
+ 10(ag) The Capital Electric Construction Company,
Inc. Deferred Compensation Plan, filed as
Exhibit 10(y) to Form 10-K for the year
ended December 31, 2003, in File No. 1-3480 *
+ 10(ah) The Capital Electric Line Builders, Inc.
Deferred Compensation Plan, filed as
Exhibit 10(z) to Form 10-K for the year
ended December 31, 2003, in File No. 1-3480 *
+ 10(ai) The Bauerly Brothers, Inc. Deferred
Compensation Plan, filed as Exhibit 10(aa)
to Form 10-K for the year ended December
31, 2003, in File No. 1-3480 *
+ 10(aj) The Oregon Electric Construction, Inc.
Deferred Compensation Plan, filed as
Exhibit 10(ab) to Form 10-K for the year
ended December 31, 2003, in File No. 1-3480 *
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 Consent of Independent Registered Public
Accounting Firm **
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.
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 23, 2005 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 23, 2005
Martin A. White (Chairman of the Board, Officer
President and Chief Executive Officer) and Director
/s/ Warren L. Robinson Chief Financial February 23, 2005
Warren L. Robinson (Executive Vice Officer
President and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 23, 2005
Vernon A. Raile (Senior Vice President Officer
and Chief Accounting Officer)
/s/ Harry J. Pearce Lead Director February 23, 2005
Harry J. Pearce
/s/ Bruce R. Albertson Director February 23, 2005
Bruce R. Albertson
/s/ Thomas Everist Director February 23, 2005
Thomas Everist
/s/ Dennis W. Johnson Director February 23, 2005
Dennis W. Johnson
/s/ Patricia L. Moss Director February 23, 2005
Patricia L. Moss
/s/ Robert L. Nance Director February 23, 2005
Robert L. Nance
/s/ John L. Olson Director February 23, 2005
John L. Olson
/s/ Sister Thomas Welder Director February 23, 2005
Sister Thomas Welder
/s/ John K. Wilson Director February 23, 2005
John K. Wilson