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, 2000
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________ to ____________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
Common Stock, par value $1.00 on which registered
and Preference Share Purchase Rights New York Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, par value $100
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months, and (2) has been
subject to such filing requirements for the past 90 days. Yes X . No
__.
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K.
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 23, 2001:
$1,873,169,000.
Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 23, 2001:
65,725,235 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 29 through 55 of the Registrant's Annual Report to
Stockholders for 2000 are incorporated by reference in Part II,
Items 6 and 8 of this Report.
2. Portions of the Registrant's Proxy Statement, dated March 9, 2001
are incorporated by reference in Part III, Items 10, 11 and 12 of
this Report.
CONTENTS
PART I
Items 1 and 2 -- Business and Properties
General
Electric
Natural Gas Distribution
Utility Services
Pipeline and Energy Services
Natural Gas and Oil Production
Construction Materials and Mining --
Construction Materials
Coal
Consolidated Construction Materials and Mining
Item 3 -- Legal Proceedings
Item 4 -- Submission of Matters to a Vote of
Security Holders
PART II
Item 5 -- Market for the Registrant's Common Stock and
Related Stockholder Matters
Item 6 -- Selected Financial Data
Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of
Operations
Item 7A -- Quantitative and Qualitative Disclosures About
Market Risk
Item 8 -- Financial Statements and Supplementary Data
Item 9 -- Change in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 10 -- Directors and Executive Officers of the
Registrant
Item 11 -- Executive Compensation
Item 12 -- Security Ownership of Certain Beneficial
Owners and Management
Item 13 -- Certain Relationships and Related
Transactions
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K
PART I
This Form 10-K contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements should be read with the cautionary
statements and important factors included in this Form 10-K at
Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Safe Harbor for Forward-
looking Statements. Forward-looking statements are all
statements other than statements of historical fact, including
without limitation, those statements that are identified by the
words "anticipates," "estimates," "expects," "intends," "plans,"
"predicts" and similar expressions.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
MDU Resources Group, Inc. (company) is a diversified natural
resource company which was incorporated under the laws of the
State of Delaware in 1924. Its principal executive offices are
at the Schuchart Building, 918 East Divide Avenue, P.O. Box 5650,
Bismarck, North Dakota 58506-5650, telephone (701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), a public
utility division of the company, through the electric and natural
gas distribution segments, generates, transmits and distributes
electricity, distributes natural gas and provides related value-
added products and services in North Dakota, Montana, South
Dakota and Wyoming. Great Plains Natural Gas Co. (Great Plains),
another public utility division of the company, distributes
natural gas in southeastern North Dakota and western Minnesota.
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) and Centennial Holdings Capital
Corp.
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 and provides energy-
related marketing and management services. The natural
gas and oil production segment is engaged in natural gas
and oil acquisition, exploration and production
primarily in the Rocky Mountain region of the United
States and in the Gulf of Mexico.
Knife River mines and markets aggregates and related
value-added construction materials products and services
in the western United States, including Alaska and
Hawaii, and also operates lignite coal mines in Montana
and North Dakota. On September 28, 2000, Knife River
announced an agreement to sell its coal operations
subject to various closing conditions. For more
information on the above pending sale see Prospective
Information contained in Item 7 -- Management's
Discussion and Analysis of Financial Condition and
Results of Operations.
Utility Services is a diversified infrastructure
construction company specializing in electric, natural
gas and telecommunication utility construction as well as
interior industrial electrical, exterior lighting and
traffic signalization. Utility Services has engineering,
design and build capability and provides related
specialty equipment sales and rental services throughout
most of the United States.
Centennial Holdings Capital Corp. anticipates making
investments in new growth and synergistic opportunities
which are not directly being pursued by the existing
business units but which are consistent with the
company's philosophy and growth strategy.
As of December 31, 2000, the company had 4,087 full-time
employees with 79 employed at MDU Resources Group, Inc., 888 at
Montana-Dakota, 60 at Great Plains, 384 at WBI Holdings, 1,607 at
Knife River's operations and 1,069 at Utility Services.
At Montana-Dakota and WBI Holdings, 429 and 91 employees,
respectively, are represented by the International
Brotherhood of Electrical Workers. Labor contracts with such
employees are in effect through April 30, 2003 and March 31,
2002, for Montana-Dakota and WBI Holdings, respectively. Knife
River has a labor contract through May 1, 2005, with the United
Mine Workers of America, which represents its coal operation's
hourly workforce aggregating 112 employees. In addition, Knife
River has 26 labor contracts which represent 413 of its
construction materials employees. Utility Services has 76 labor
contracts representing the majority of its employees.
The financial results and data applicable to each of the
company's business segments as well as their financing
requirements are set forth in Item 7 - - Management's Discussion
and Analysis of Financial Condition and Results of Operations and
Notes to the Consolidated Financial Statements.
Any reference to the company's Consolidated Financial
Statements and Notes thereto shall be to pages 29 through 53 in
the company's Annual Report to Stockholders for 2000 (Annual
Report), which are incorporated by reference herein.
ELECTRIC
General --
Montana-Dakota provides electric service at retail, serving
over 115,000 residential, commercial, industrial and municipal
customers located in 176 communities and adjacent rural areas as
of December 31, 2000. The principal properties owned by Montana-
Dakota for use in its electric operations include interests in
seven electric generating stations, as further described under
System Supply and System Demand, and approximately 3,100 and
4,000 miles of transmission and distribution lines, respectively.
Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required. For additional information regarding Montana-Dakota's
franchises, see Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations. As of
December 31, 2000, Montana-Dakota's net electric plant investment
approximated $274.8 million.
All of Montana-Dakota's electric properties, with certain
exceptions, are subject to the lien of the Indenture of Mortgage
dated May 1, 1939, as supplemented, amended and restated, from
the company to The Bank of New York and Douglas J. MacInnes,
successor trustees.
The electric operations of Montana-Dakota are subject to
regulation by the Federal Energy Regulatory Commission (FERC)
under provisions of the Federal Power Act with respect to the
transmission and sale of power at wholesale in interstate
commerce, interconnections with other utilities, the issuance of
securities, accounting and other matters. Retail rates, service,
accounting and, in certain cases, 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 2000 electric utility operating revenues by
jurisdiction is as follows: North Dakota -- 60 percent;
Montana -- 23 percent; South Dakota -- 7 percent and Wyoming --
10 percent.
System Supply and System Demand --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and major
communities -- western North Dakota, including Bismarck,
Dickinson and Williston; eastern Montana, including Glendive and
Miles City; and northern South Dakota, including Mobridge. The
interconnected system consists of seven on-line electric
generating stations which have an aggregate turbine nameplate
rating attributable to Montana-Dakota's interest of 393,488
Kilowatts (kW) and a total summer net capability of 434,020 kW.
Montana-Dakota's four principal generating stations are steam-
turbine generating units using coal for fuel. The nameplate
rating for Montana-Dakota's ownership interest in these four
stations (including interests in the Big Stone Station and the
Coyote Station aggregating 22.7 percent and 25.0 percent,
respectively) is 327,758 kW. The balance of Montana-Dakota's
interconnected system electric generating capability is supplied
by three combustion turbine peaking stations. Additionally,
Montana-Dakota has contracted to purchase through October 31,
2006, 66,400 kW of participation power annually from Basin
Electric Power Cooperative for its interconnected system.
The following table sets forth details applicable to the
company's electric generating stations:
2000 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 706,244
Heskett Steam 86,000 104,330 472,036
Williston Combustion
Turbine 7,800 9,600 (76)**
South Dakota --
Big Stone* Steam 94,111 103,640 814,556
Montana --
Lewis & Clark Steam 44,000 52,100 324,983
Glendive Combustion
Turbine 34,780 33,200 9,975
Miles City Combustion
Turbine 23,150 24,400 3,470
393,488 434,020 2,331,188
- -----------------------------
* Reflects Montana-Dakota's ownership interest.
** Station use, to meet MAPP's accreditation requirements,
exceeded generation.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. The majority of
the Big Stone Station's fuel requirements are currently being met
with coal supplied by Kennecott Energy Company under a contract
which expires on December 31, 2001.
During the years ended December 31, 1996, through
December 31, 2000, 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,
2000 1999 1998 1997 1996
Average cost of
coal per
million Btu $.94 $.90 $.93 $.95 $.93
Average cost of
coal per ton $13.68 $13.31 $13.67 $14.22 $13.64
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 432,300 kW in August 2000. 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 2006 will approximate 1.1 percent annually.
Montana-Dakota's latest forecast indicates that its kilowatt-hour
(kWh) sales growth rate, on a normalized basis, through 2006 will
approximate 0.7 percent annually. Montana-Dakota currently
estimates that, with modifications already made and those
expected to be made, it has adequate capacity available through
existing generating stations and long-term firm purchase
contracts until the year 2004. If additional capacity is needed
in 2004 or after, it is expected to be met through the addition
of combustion turbine peaking stations and purchases from the Mid-
Continent Area Power Pool (MAPP) on an intermediate-term basis.
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 46,600 kW and occurred in December 1983.
The Sheridan System is supplied through an interconnection
with Black Hills Power and Light Company under a power supply
contract through December 31, 2006 which allows for the purchase
of up to 55,000 kW of capacity annually.
Regulation and Competition --
The electric utility industry can be expected to continue to
become increasingly competitive due to a variety of regulatory,
economic and technological changes. The FERC, in its Order No.
888, has required that utilities provide open access and
comparable transmission service to third parties. In addition,
as a result of competition in electric generation, wholesale
power markets have become increasingly competitive and
evaluations are ongoing concerning retail competition.
In March 1996, the MAPP, of which Montana-Dakota is a member,
filed a restated operating agreement with the FERC. The FERC
approved MAPP's restated agreement, excluding MAPP's market-based
rate proposal, effective November 1996. In 1999, the FERC
approved MAPP's request to use each member's individual market
based tariffs which were already on file and approved by the
FERC.
In December 1999, the FERC issued its Order 2000 in which it
prescribed certain minimum characteristics of and functions to be
performed by Regional Transmission Organizations (RTOs). Montana-
Dakota has been actively pursuing its options for voluntary
participation in a FERC-approved RTO that would become
operational by December 15, 2001. As required by Order 2000,
Montana-Dakota filed a report with the FERC in October 2000 in
which it described its efforts to join an RTO and explained its
reasons for not proposing to join an RTO at that time. Montana-
Dakota is continuing to pursue its options to join a FERC-
approved RTO, but for economic and operational reasons, it has
been unable to commit to joining a specific RTO.
The Montana legislature passed an electric industry
restructuring bill, effective May 2, 1997. The bill provides for
full customer choice of electric supplier by July 1, 2002,
stranded cost recovery and other provisions. On December 19,
2000, the MTPSC extended this date to July 1, 2004, for those
customers, primarily residential and small commercial, that do
not have a choice of, or have not yet chosen, an electricity
supplier. MTPSC cited the fact that Montana customers would be
disadvantaged due to the lack of a competitive electricity supply
market. Based on the provisions of such restructuring bill,
because Montana-Dakota operates in more than one state, the
company has the option of deferring its transition to full
customer choice until 2006. Legislation has been proposed in
Montana which would delay the restructuring and transition to
full customer choice until a time that Montana-Dakota can
reasonably implement customer choice in the state of its primary
service territory.
In its 1997 legislative session, the North Dakota
legislature established an Electric Industry Competition
Committee to study over a six-year period the impact of
competition on the generation, transmission and distribution of
electric energy in North Dakota. 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.
Fuel adjustment clauses contained in North Dakota and South
Dakota jurisdictional electric rate schedules allow
Montana-Dakota to reflect increases or decreases in fuel and
purchased power costs (excluding demand charges) on a timely
basis. Expedited rate filing procedures in Wyoming allow Montana-
Dakota to timely reflect increases or decreases in fuel and
purchased power costs. In Montana (23 percent of electric
revenues), such cost changes are includible in general rate
filings.
Environmental Matters --
Montana-Dakota's electric operations are subject to federal,
state and local laws and regulations providing for air, water and
solid waste pollution control; state facility-siting regulations;
zoning and planning regulations of certain state and local
authorities; federal health and safety regulations and state hazard
communication standards. Montana-Dakota believes it is in
substantial compliance with those regulations.
Governmental regulations establishing environmental
protection standards are continuously evolving and, therefore,
the character, scope, cost and availability of the measures which
will permit compliance with these laws or regulations, cannot be
accurately predicted. Montana-Dakota did not incur any
significant environmental expenditures in 2000 and does not
expect to incur any significant capital expenditures related to
environmental compliance through 2003.
NATURAL GAS DISTRIBUTION
General --
Montana-Dakota sells natural gas at retail, serving over 211,000
residential, commercial and industrial customers located in 141
communities and adjacent rural areas as of December 31, 2000, and
provides natural gas transportation services to certain customers
on its system. Great Plains, acquired July 2000, 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, 2000, and provides natural gas
transportation services to certain customers on its system.
These services for the two public utility divisions are provided
through distribution systems aggregating over 5,200 miles.
Montana-Dakota and Great Plains have obtained and hold valid and
existing franchises authorizing them to conduct natural gas
distribution operations in all of the municipalities they serve
where such franchises are required. For additional information
regarding Montana-Dakota's franchises, see Item 7 -- Management's
Discussion and Analysis of Financial Condition and Results of
Operations. As of December 31, 2000, Montana-Dakota's and Great
Plains' net natural gas distribution plant investment
approximated $102.2 million.
All of Montana-Dakota's natural gas distribution properties,
with certain exceptions, are subject to the lien of the Indenture
of Mortgage dated May 1, 1939, as supplemented, amended and
restated, from the company to The Bank of New York and Douglas J.
MacInnes, successor trustees.
The natural gas distribution operations of Montana-Dakota are
subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC
regarding retail rates, service, accounting and, in certain
instances, security issuances. The natural gas distribution
operations of Great Plains are subject to regulation by the NDPSC
and Minnesota Public Utilities Commission regarding retail rates,
service, accounting and, in certain instances, security
issuances. The percentage of Montana-Dakota's and Great Plains'
2000 natural gas utility operating revenues by jurisdiction is as
follows: North Dakota -- 39 percent; Minnesota -- 8 percent;
Montana -- 28 percent; South Dakota -- 19 percent and Wyoming --
6 percent (Operating revenues for Great Plains are for the period
July through December 2000).
System Supply, System Demand and Competition --
Montana-Dakota and Great Plains serve retail natural gas
markets, consisting principally of residential and firm
commercial space and water heating users, in portions of the
following states and major communities -- North Dakota, including
Bismarck, Dickinson, Wahpeton, Williston, Minot and Jamestown;
western Minnesota, including Fergus Falls, Marshall and
Crookston; eastern Montana, including Billings, Glendive and
Miles City; western and north-central South Dakota, including
Rapid City, Pierre and Mobridge; and northern Wyoming, including
Sheridan. These markets are highly seasonal and sales volumes
depend on the weather.
The following table reflects this segment's natural gas sales,
natural gas transportation volumes and degree days as a percentage
of normal during the last five years:
Years Ended December 31,
2000 1999 1998 1997 1996
Mdk (thousands of decatherms)
Sales:
Residential 20,554 18,059 18,614 20,126 22,682
Commercial 14,590 12,030 12,458 13,799 15,325
Industrial 1,451 842 952 395 276
Total 36,595 30,931 32,024 34,320 38,283
Transportation:
Commercial 2,067 1,975 1,995 1,612 1,677
Industrial 12,247 9,576 8,329 8,455 7,746
Total 14,314 11,551 10,324 10,067 9,423
Total Throughput 50,909 42,482 42,348 44,387 47,706
Degree days
(% of normal) 100.4% 88.8% 93.7% 99.3% 116.2%
- -----------------------------
Note: Sales and transportation volumes for Great Plains are for the
period July through December 2000. Degree days exclude Great Plains.
The restructuring of the natural gas industry, as described
under Pipeline and Energy Services, has resulted in additional
competition in retail natural gas markets. In response to
these changed market conditions, Montana-Dakota and Great Plains
have established various natural gas transportation service rates
for their distribution businesses to retain interruptible commercial
and industrial load. Certain of these services include
transportation under flexible rate schedules whereby Montana-Dakota's
and Great Plains' interruptible customers can avail themselves of the
advantages of open access transportation on regional transmission
pipelines, including the system of Williston Basin Interstate Pipeline
Company (Williston Basin), an indirect wholly owned subsidiary of
WBI Holdings. These services have enhanced Montana-Dakota's and
Great Plains' competitive posture with alternate fuels, although
certain of Montana-Dakota's and Great Plains' customers have the
potential of bypassing the respective distribution systems by
directly accessing transmission pipelines located within close
proximity.
Montana-Dakota and Great Plains acquire their system
requirements directly from producers, processors and marketers.
Such natural gas is supplied by a portfolio of contracts
specifying market-based pricing, and is transported under
transportation agreements by Williston Basin, Northern Gas
Company, South Dakota Intrastate Pipeline Company, Northern
Border Pipeline Company, Viking Gas Transmission Company and
Northern Natural Gas Company to provide firm service to their
customers. Montana-Dakota has also contracted with Williston
Basin to provide firm storage services which enable Montana-
Dakota to meet winter peak requirements as well as allow it to
better manage its natural gas costs by purchasing natural gas at
more uniform daily volumes throughout the year. Demand for
natural gas, which is a widely traded commodity, is sensitive to
changes in market price. Montana-Dakota and Great Plains believe
that, based on regional supplies of natural gas and the pipeline
transmission network currently available through its suppliers
and pipeline service providers, supplies are adequate to meet its
system natural gas requirements for the next five years.
Regulatory Matters --
Montana-Dakota's and Great Plains' retail natural gas rate
schedules contain clauses permitting monthly adjustments in rates
based upon changes in natural gas commodity, transportation and
storage costs. Current regulatory practices allow Montana-Dakota
and Great Plains to recover increases or refund decreases in such
costs within a period ranging from 24 months to 28 months from
the time such changes occur.
Environmental Matters --
Montana-Dakota's and Great Plains' natural gas distribution
operations are subject to federal, state and local
environmental, facility siting, zoning and planning laws and
regulations. Montana-Dakota and Great Plains believe they are
in substantial compliance with those regulations.
UTILITY SERVICES
Utility Services is a diversified infrastructure
construction company specializing in electric, natural gas and
telecommunication utility construction as well as interior
industrial electrical, exterior lighting and traffic
signalization. Utility Services has engineering, design and build
capability and provides related specialty equipment sales and
rental services. These services are provided to electric,
natural gas, and telecommunication companies along with
municipal, commercial and industrial entities throughout most
of the United States.
During 2000, the company acquired utility services companies
based in California, Colorado, Montana and Ohio. None of these
acquisitions was individually material to the company.
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 primarily based on
price and reputation for quality, safety and reliability. The
size and area location of the services provided will be a factor
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 will enable it to
effectively operate in this competitive environment.
In the aggregate, electric utilities represent the largest
customer base. Accordingly, electric utilities account for a
significant portion of the work performed by the utility services
segment and the amount of construction contracts from utilities
is dependent to a certain extent on the level and timing of
maintenance programs undertaken by such utilities. Utility
Services relies on repeat customers and strives to maintain
successful long-term relationships with these 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.
PIPELINE AND ENERGY SERVICES
General --
Williston Basin, the principal regulated business of
WBI Holdings, owns and operates over 3,800 miles of
transmission, gathering and storage lines and 24 compressor
stations located in the states of Montana, North Dakota,
South Dakota and Wyoming. Through three underground
storage fields located in Montana and Wyoming, storage services
are provided to local distribution companies, producers,
natural gas marketers and others, and serve to enhance system
deliverability. Williston Basin's system is strategically
located near five natural gas producing basins making natural
gas supplies available to Williston Basin's transportation and
storage customers.
At December 31, 2000, Williston Basin's net plant
investment was approximately $164.7 million.
WBI Holdings owns and operates gathering facilities in
Colorado, Kansas, Montana, Nebraska and Wyoming. These
facilities include various field gathering lines and owned and
leased compression facilities some of which interconnect with
Williston Basin's system. An underground natural gas storage
facility in Kentucky and a one-sixth interest in the assets of
various offshore gathering pipelines and associated onshore
pipeline and related processing facilities are also owned by WBI
Holdings.
WBI Holdings, through its energy services businesses, seeks
new energy markets while continuing to expand present markets for
natural gas. Its activities include buying and selling natural
gas and arranging transportation services to end users,
pipelines, municipals and local distribution companies. The
energy services segment transacts a significant portion of its
business on the Williston Basin and Texas Gas Transmission Corp.
pipeline systems, serving customers in the Rocky Mountain, Upper
Midwest, Southern and Central regions of the United States. In
2000, a pipeline and cable tracking and locating technology
company was acquired. This company provides products and
services which are an integral part of the ongoing reliability of
the submerged pipeline and cable infrastructure.
Under the Natural Gas Act, as amended, Williston Basin and
certain other operations of WBI Holdings are subject to the
jurisdiction of the FERC regarding certificate, rate and
accounting matters.
System Demand and Competition --
The natural gas pipeline industry, although regulated, is
very competitive. In the mid-1980s, customers began switching
their natural gas service from a bundled merchant service to
transportation. This switching was accelerated with the
implementation of Order 636 which unbundled pipelines' services.
This change reflects most customers' willingness to purchase
their natural gas supply from producers, processors or marketers
rather than pipelines. Williston Basin competes with several
pipelines for its customers' transportation business and at times
will have to discount rates in an effort to retain market share.
However, the strategic location of Williston Basin's system near
five natural gas producing basins and the availability of
underground storage and gathering services provided by Williston
Basin and affiliates along with interconnections with other
pipelines serve to enhance Williston Basin's competitive
position.
Although a significant portion of Williston Basin's firm
customers, which include Montana-Dakota, have relatively secure
residential and commercial end-users, virtually all have some
price-sensitive end-users that could switch to alternate fuels.
Williston Basin transports substantially all of Montana-
Dakota's natural gas utilizing firm transportation agreements,
which at December 31, 2000, represented 87 percent of Williston
Basin's currently subscribed firm transportation capacity. In
November 1996, Montana-Dakota executed a new firm transportation
agreement with Williston Basin for a term of five years which
began in July 1997. In addition, in July 1995, Montana-Dakota
entered into a twenty-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 353,300 million
cubic feet (MMcf), including 28,900 MMcf and 46,300 MMcf of
recoverable and nonrecoverable native gas, respectively.
Williston Basin's storage facilities enable its customers to
purchase natural gas at more uniform daily volumes throughout the
year and, thus, facilitate meeting winter peak requirements.
Natural gas supplies from traditional regional sources have
declined during the past several years and such declines are
anticipated to continue. As a result, Williston Basin
anticipates that a potentially significant amount of the future
supply needed to meet its customers' demands will come from non-
traditional, off-system sources. The acquisition of the coal bed
natural gas assets in the Powder River Basin is expected to meet
some of these supply needs. Williston Basin expects to
facilitate the movement of these supplies by making available its
transportation and storage services. Williston Basin will
continue to look for opportunities to increase transportation and
storage services through system expansion or other pipeline
interconnections or enhancements which could provide substantial
future benefits.
Regulatory Matters and Revenues Subject to Refund --
In June 1995, Williston Basin filed a general rate increase
application with the Federal Energy Regulatory Commission (FERC).
As a result of FERC orders issued after Williston Basin's
application was filed, Williston Basin filed revised base rates
in December 1995 with the FERC. Williston Basin began collecting
such increase effective January 1, 1996, subject to refund. In
July 1998, the FERC issued an order which addressed various
issues including storage cost allocations, return on equity and
throughput. In August 1998, Williston Basin requested rehearing
of such order. In June 1999, the FERC issued an order approving
and denying various issues addressed in Williston Basin's
rehearing request, and also remanding the return on equity issue
to an Administrative Law Judge for further proceedings. In July
1999, Williston Basin requested rehearing of certain issues which
were contained in the June 1999 FERC order. In September 1999,
the FERC granted Williston Basin's request for rehearing with
respect to the return on equity issue but also ordered Williston
Basin to issue interim refunds prior to the final determination
in this proceeding. As a result, in October 1999, Williston
Basin issued refunds to its customers totaling $11.3 million, all
from amounts which had previously been reserved. In December
1999, a hearing was held before the FERC regarding the return on
equity issue. On April 27, 2000, the Administrative Law Judge
issued an Initial Decision regarding the remanded return on
equity issue. On August 15, 2000, Williston Basin filed a
stipulation and agreement for the purpose of resolving the rate
and refund matters at issue with the FERC. On November 21, 2000,
the FERC issued its order accepting the August 15, 2000
stipulation and agreement. As a result, on December 28, 2000,
Williston Basin issued refunds to its customers totaling $13.0
million, all from amounts which had previously been reserved.
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.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to
pending regulatory proceedings and to reflect future resolution
of certain issues with the FERC. Based on the November 21, 2000
FERC order referenced above, Williston Basin, in the fourth
quarter of 2000, determined that reserves it had previously
established exceeded its expected refund obligation and,
accordingly, reversed reserves and recognized in income $6.7
million after tax. Williston Basin, in the second quarter of
1999, determined that reserves it had previously established in
relation to a 1992 general natural gas rate change application
and the 1995 general rate increase application exceeded its
expected refund obligation and, accordingly, reversed reserves
and recognized in income $4.4 million after tax. Williston Basin
believes that its remaining reserves are adequate based on its
assessment of the ultimate outcome of the application filed in
December 1999.
Environmental Matters --
WBI Holdings' pipeline and energy services' operations are
generally subject to federal, state and local environmental,
facility-siting, zoning and planning laws and regulations. WBI
Holdings believes it is in substantial compliance with those
regulations.
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 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 the Gulf of
Mexico in proportion to its interests.
Fidelity owns in fee or holds natural gas leases for the
properties it operates in Colorado, Montana and North Dakota.
These rights are in the Bonny Field located in eastern Colorado,
the Cedar Creek Anticline in southeastern Montana and
southwestern North Dakota, and in the Bowdoin area located in
north-central Montana. In 2000, coal bed natural gas reserves in
the Powder River Basin of Wyoming and Montana were acquired.
These acquisitions include over 210,000 net acres under lease.
The natural gas and oil activities have continued to expand
since the mid-1980s. Fidelity continues to seek additional
reserve and production opportunities through the direct
acquisition of producing properties and through exploratory
drilling opportunities, as well as routine development of its
existing properties. Future growth is dependent upon its
continuing 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 2000, 1999 and 1998,
are as follows:
2000 1999 1998
Natural Gas:
Production (MMcf) 29,222 24,652 20,699
Average realized price $2.90 $1.94 $1.81
Oil:
Production (000's of barrels) 1,882 1,758 1,912
Average realized price $23.06 $15.34 $12.71
Production costs, including taxes,
per net equivalent Mcf $0.77 $0.62 $0.52
Well and Acreage Information --
Gross and net productive well counts and gross and net
developed and undeveloped acreage related to interests at
December 31, 2000, are as follows:
Gross Net
Productive Wells:
Natural Gas 1,931 1,343
Oil 1,559 199
Total 3,490 1,542
Developed Acreage (000's) 949 363
Undeveloped Acreage (000's) 843 286
Exploratory and Development Wells --
The following table shows the results of natural gas and oil
wells drilled and tested during 2000, 1999 and 1998:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
2000 9 3 12 362 3 365 377
1999 1 2 3 70 2 72 75
1998 2 2 4 54 --- 54 58
At December 31, 2000, there were four gross wells in the
process of drilling, one of which was an exploratory well and
three of which were development wells.
Environmental Matters --
WBI Holdings' natural gas and oil production operations are
generally subject to federal, state and local environmental,
facility-siting, zoning and planning laws and regulations. WBI
Holdings believes it is in substantial compliance with those
regulations.
Reserve Information --
Fidelity's recoverable proved developed and undeveloped
natural gas and oil reserves approximated 309.8 Bcf and 15.1
million barrels, respectively, at December 31, 2000.
For additional information related to natural gas and oil
interests, see Notes 1 and 16 of Notes to Consolidated Financial
Statements.
CONSTRUCTION MATERIALS AND MINING
Construction Materials:
General --
Knife River operates construction materials and mining
businesses in Alaska, California, Hawaii, Montana, Oregon and
Wyoming. These operations mine, process and sell construction
aggregates (crushed rock, 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 2000, the company acquired several construction
materials and mining companies with operations in Alaska,
California, Montana and Oregon. None of these acquisitions was
individually material to the company.
Knife River's construction materials business has continued
to grow since its first acquisition in 1992 and now comprises the
substantial majority of Knife River's business. Knife River
continues to investigate the acquisition of other construction
materials properties, particularly those relating to sand and
gravel aggregates and related products such as ready-mixed
concrete, asphalt and various finished aggregate products.
Knife River's construction materials business is expected to
continue to benefit from the Transportation Equity Act for the
21st Century (TEA-21), which was signed into law in June 1998.
TEA-21 represents an average increase in federal highway
construction funding of approximately 48 percent for the six
fiscal years 1998 to 2003.
The construction materials business had approximately $126
million in backlog in mid-February 2001, compared to
approximately $107 million in mid-February 2000. The company
anticipates that a significant amount of the current backlog will
be completed during the year ending December 31, 2001.
Competition --
Knife River's construction materials products are marketed
under highly competitive conditions. Since there are generally
no measurable product differences in the market areas in which
Knife River conducts its construction materials businesses, price
is the principal competitive force to which these products are
subject, with service, delivery time and proximity to the
customer also being significant factors. The number and size of
competitors varies in each of Knife River's principal market
areas and product lines.
The demand for construction materials products is
significantly influenced by the cyclical nature of the
construction industry in general. In addition, construction
materials activity in certain locations may be seasonal in nature
due to the effects of weather. The key economic factors
affecting product demand are changes in the level of local, state
and federal governmental spending, general economic conditions
within the market area which influence both the commercial and
private sectors, and prevailing interest rates.
Knife River is not dependent on any single customer or group
of customers for sales of its construction materials products,
the loss of which would have a materially adverse affect on its
construction materials businesses. During 2000, 1999 and 1998,
no single customer accounted for more than 10 percent of annual
construction materials revenues.
Coal:
General --
Knife River is engaged in lignite coal mining operations.
Knife River's surface mining operations are located at
Beulah, North Dakota and Savage, Montana. On September 28,
2000, Knife River announced an agreement to sell its coal
operations subject to various closing conditions. For more
information on the above pending sale see Prospective
Information contained in Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of
Operations.
The average annual production from the Beulah and Savage
mines approximates 2.8 million and 325,000 tons,
respectively. Reserve estimates related to these mine
locations are discussed herein. During the last five years,
Knife River mined and sold the following amounts of lignite
coal:
Years Ended December 31,
2000 1999 1998 1997 1996
(In thousands)
Tons sold:
Montana-Dakota generating stations 765 717 702 530 528
Jointly-owned generating stations --
Montana-Dakota's share 568 611 583 434 565
Others 1,703 1,831 1,749 1,303 1,695
Industrial and other sales 75 77 79 108 111
Total 3,111 3,236 3,113 2,375 2,899
Revenues $33,721 $34,841 $35,949 $27,906 $32,696
Knife River's lignite coal operations are subjected to
competition from other coal and alternate fuel sources.
Currently, virtually all of the coal requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. These contracts
with the Coyote, Heskett and Lewis & Clark stations expire in
May 2016, December 2005, and December 2002, respectively. In
2000, Knife River supplied approximately 3.0 million tons of coal
to these three stations.
Consolidated Construction Materials and Mining:
Environmental Matters --
Knife River's construction materials and mining operations
are subject to regulation customary for surface mining
operations, including federal, state and local environmental and
reclamation regulations. Except as what may be ultimately
determined with regard to the issue decribed below, Knife River
believes it is in substantial compliance with those regulations.
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the company, was named by the United States
Environmental Protection Agency (EPA) as a Potentially
Responsible Party in connection with the cleanup of a commercial
property site, now owned by MBI, and part of the Portland,
Oregon, Harbor Superfund Site. Sixty-eight other parties were
also named in this administrative action. The EPA wants
responsible parties to share in the cleanup of sediment
contamination in the Williamette River. Based upon a review of
the Portland Harbor sediment contamination evaluation by the
Oregon State Department of Environmental Quality and other
information available, MBI does not believe it is a Responsible
Party. In addition, MBI intends to seek indemnity for any and
all liabilities incurred in relation to the above matters from
Georgia-Pacific West, Inc., the seller of the commercial property
site to MBI, pursuant to the terms of their sale agreement.
Reserve Information --
As of December 31, 2000, the combined construction materials
operations had under ownership or lease approximately 895 million
tons of recoverable aggregate reserves.
As of December 31, 2000, Knife River had under ownership or
lease, reserves of approximately 146 million tons of recoverable
lignite coal, 88 million tons of which are at present mining
locations. Knife River estimates that approximately 39 million
tons of its reserves will be needed to supply Montana-Dakota's
Coyote, Heskett and Lewis & Clark stations for the expected lives
of those stations and to fulfill the existing commitments of
Knife River for sales to third parties.
ITEM 3. LEGAL PROCEEDINGS
In March 1997, 11 natural gas producers filed suit in North
Dakota Northwest Judicial District Court (North Dakota District
Court) against Williston Basin and the company. The natural gas
producers had processing agreements with Koch Hydrocarbon Company
(Koch). Williston Basin and the company had natural gas purchase
contracts with Koch. The natural gas producers alleged they were
entitled to damages for the breach of Williston Basin's and the
company's contracts with Koch although no specific damages were
stated. A similar suit was filed by Apache Corporation (Apache)
and Snyder Oil Corporation (Snyder) in North Dakota District
Court in December 1993. The North Dakota Supreme Court in
December 1999 affirmed the North Dakota District Court decision
dismissing Apache's and Snyder's claims against Williston Basin
and the company. Based in part upon the decision of the North
Dakota Supreme Court affirming the dismissal of the claims
brought by Apache and Snyder, Williston Basin and the company
filed motions for summary judgment to dismiss the claims of the
11 natural gas producers. The motions for summary judgment were
granted by the North Dakota District Court on July 3, 2000. The
company is awaiting entry of a final judgment on the July 3, 2000
order granting the motions for summary judgment.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other natural
gas pipeline companies. Grynberg, acting on behalf of the United
States under the Federal False Claims Act, alleged improper
measurement of the heating content or volume of natural gas
purchased by the defendants resulting in the underpayment of
royalties to the United States. In March 1997, the U.S. District
Court dismissed the suit without prejudice and the dismissal was
affirmed by the D.C. Circuit Court in October 1998. In June
1997, Grynberg filed a similar Federal False Claims Act suit
against Williston Basin and Montana-Dakota and filed over 70
other separate similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. In April 1999, the United States Department of Justice
decided not to intervene in these cases. In response to a motion
filed by Grynberg, the Judicial Panel on Multidistrict Litigation
consolidated all of these cases in the Federal District Court of
Wyoming (Federal District Court). Oral argument on motions to
dismiss was held before the Federal District Court on March 17,
2000. Williston Basin and Montana-Dakota are awaiting a decision
from the Federal District Court.
The Quinque Operating Company (Quinque), on behalf of itself
and subclasses of gas producers, royalty owners and state taxing
authorities, instituted a legal proceeding in State District
Court for Stevens County, Kansas, against over 200 natural gas
transmission companies and producers, gatherers, and processors
of natural gas, including Williston Basin and Montana-Dakota.
The complaint, which was served on Williston Basin and Montana-
Dakota in September 1999, contains allegations of improper
measurement of the heating content and volume of all natural gas
measured by the defendants other than natural gas produced from
federal lands. In response to a motion filed by the defendants
in this suit, the Judicial Panel on Multidistrict Litigation
transferred the suit to the Federal District Court for inclusion
in the pretrial proceedings of the Grynberg suit.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits.
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the company, was named by the United States
Environmental Protection Agency (EPA) as a Potentially
Responsible Party in connection with the cleanup of a commercial
property site, now owned by MBI, and part of the Portland,
Oregon, Harbor Superfund Site. For additional information
regarding this issue, see Items 1 and 2 -- Business and
Properties -- Construction Materials and Mining.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders
during the fourth quarter of 2000.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The company's common stock is listed on the New York Stock
Exchange and the Pacific Stock Exchange under the symbol "MDU".
The price range of the company's common stock as reported by The
Wall Street Journal composite tape during 2000 and 1999 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
2000
First Quarter $ 21.44 $ 17.63 $ .21
Second Quarter 23.25 20.38 .21
Third Quarter 30.06 21.56 .22
Fourth Quarter 33.00 27.44 .22
$ .86
1999
First Quarter $ 27.19 $ 21.25 $ .20
Second Quarter 24.38 20.31 .20
Third Quarter 24.75 22.38 .21
Fourth Quarter 24.38 18.81 .21
$ .82
As of December 31, 2000, the company's common stock was held
by approximately 13,600 stockholders of record.
Between October 1, 2000 and December 31, 2000, the company
issued 93,595 shares of Common Stock, $1.00 par value, as final
adjustments with respect to acquisitions in prior periods. The
Common Stock issued by the company in these transactions was
issued in private sales exempt from registration pursuant to
Section 4(2) of the Securities Act of 1933. The former owners of
the businesses acquired, now shareholders of the company, are
accredited investors and have acknowledged that they would hold
the company's Common Stock as an investment and not with a view
to distribution.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 54 and
55 of the company's Annual Report which is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
For purposes of segment financial reporting and discussion
of results of operations, electric and natural gas distribution
include the electric and natural gas distribution operations of
Montana-Dakota and the natural gas distribution operations of
Great Plains Natural Gas Co. Utility services includes all the
operations of Utility Services, Inc. Pipeline and energy
services includes WBI Holdings' natural gas transportation,
underground storage, gathering services and energy marketing and
management services. Natural gas and oil production includes the
natural gas and oil acquisition, exploration and production
operations of WBI Holdings, while construction materials and
mining includes the results of Knife River's operations.
Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the company's business segments.
Years ended December 31,
2000 1999 1998
Electric $ 17.7 $ 16.0 $ 13.9
Natural gas distribution 4.8 3.2 3.5
Utility services 8.6 6.5 3.3
Pipeline and energy services 10.5 21.0 18.6
Natural gas and oil production 38.6 16.2 (30.5)
Construction materials and mining 30.1 20.4 24.5
Earnings on common stock $ 110.3 $ 83.3 $ 33.3
Earnings per common share - basic $ 1.80 $ 1.53 $ .66
Earnings per common share - diluted $ 1.80 $ 1.52 $ .66
Return on average common equity 14.3% 13.9% 6.5%
2000 compared to 1999
Consolidated earnings for 2000 increased $27.0 million from
the comparable period a year ago due to higher earnings from the
natural gas and oil production, construction materials and
mining, utility services, electric and natural gas distribution
businesses. Lower earnings at the pipeline and energy services
business partially offset the earnings increase.
1999 compared to 1998
Consolidated earnings for 1999 increased $50.0 million from
the comparable period a year ago due to higher earnings from the
natural gas and oil production business, largely resulting from
the 1998 $39.9 million in noncash after-tax write-downs of
natural gas and oil properties. Increased earnings at the
utility services, pipeline and energy services and electric
businesses also added to the improvement in earnings. Lower
earnings at the construction materials and mining and natural gas
distribution businesses somewhat offset the earnings increase.
________________________________
Reference should be made to Items 1 and 2 -- Business and
Properties, Item 3 -- Legal Proceedings and Notes to Consolidated
Financial Statements for information pertinent to various
commitments and contingencies.
Financial and operating data
The following tables (dollars in millions, where applicable)
are key financial and operating statistics for each of the
company's business segments.
Electric
Years ended December 31,
2000 1999 1998
Operating revenues:
Retail sales $ 134.5 $ 130.9 $ 130.9
Sales for resale and other 27.1 24.0 16.4
161.6 154.9 147.3
Operating expenses:
Fuel and purchased power 54.1 51.8 49.8
Operation and maintenance 42.5 41.6 40.1
Depreciation, depletion and
amortization 19.1 18.4 18.1
Taxes, other than income 7.1 7.4 7.1
122.8 119.2 115.1
Operating income $ 38.8 $ 35.7 $ 32.2
Retail sales (million kWh) 2,161.3 2,075.5 2,053.9
Sales for resale (million kWh) 930.3 943.5 586.5
Average cost of fuel and
purchased power per kWh $ .016 $ .016 $ .017
Natural Gas Distribution
Years ended December 31,
2000 1999 1998
Operating revenues:
Sales $ 229.2 $ 154.1 $ 150.6
Transportation and other 3.9 3.6 3.5
233.1 157.7 154.1
Operating expenses:
Purchased natural gas sold 178.6 110.2 106.5
Operation and maintenance 32.0 29.2 28.5
Depreciation, depletion and
amortization 8.4 7.4 7.1
Taxes, other than income 4.6 4.2 4.0
223.6 151.0 146.1
Operating income $ 9.5 $ 6.7 $ 8.0
Volumes (MMdk):
Sales 36.6 30.9 32.0
Transportation 14.3 11.6 10.3
Total throughput 50.9 42.5 42.3
Degree days (% of normal) 100.4% 88.8% 93.7%
Average cost of natural gas,
including transportation
thereon, per dk $ 4.88 $ 3.56 $ 3.33
Utility Services
Years ended December 31,
2000 1999 1998
Operating revenues $ 169.4 $ 99.9 $ 64.2
Operating expenses:
Operation and maintenance 142.6 82.8 54.4
Depreciation, depletion and
amortization 4.9 2.6 1.7
Taxes, other than income 5.3 3.0 2.2
152.8 88.4 58.3
Operating income $ 16.6 $ 11.5 $ 5.9
Pipeline and Energy Services
Years ended December 31,
2000 1999 1998
Operating revenues:
Pipeline $ 77.4 $ 69.6 $ 60.8
Energy services 559.4 313.9 119.9
636.8 383.5 180.7
Operating expenses:
Purchased natural gas sold 548.3 301.5 109.9
Operation and maintenance 39.1 28.2 26.3
Depreciation, depletion and
amortization 15.3 8.2 7.0
Taxes, other than income 5.3 5.0 3.9
608.0 342.9 147.1
Operating income $ 28.8 $ 40.6 $ 33.6
Transportation volumes (MMdk):
Montana-Dakota 30.6 31.5 32.2
Other 56.2 46.6 56.8
86.8 78.1 89.0
Gathering volumes (MMdk) 41.7 19.8 9.1
Natural Gas and Oil Production
Years ended December 31,
2000 1999 1998
Operating revenues:
Natural gas $ 84.7 $ 47.9 $ 37.6
Oil 43.4 26.9 24.3
Other 10.2 3.6 ---
138.3 78.4 61.9
Operating expenses:
Purchased natural gas sold 3.4 1.5 ---
Operation and maintenance 31.3 24.8 18.8
Depreciation, depletion and
amortization 27.0 19.2 23.3
Taxes, other than income 10.1 6.0 4.2
Write-downs of natural gas
and oil properties --- --- 66.0
71.8 51.5 112.3
Operating income (loss) $ 66.5 $ 26.9 $ (50.4)
Production:
Natural gas (MMcf) 29,222 24,652 20,699
Oil (000's of barrels) 1,882 1,758 1,912
Average realized prices:
Natural gas (per Mcf) $ 2.90 $ 1.94 $ 1.81
Oil (per barrel) $ 23.06 $ 15.34 $ 12.71
Construction Materials and Mining
Years ended December 31,
2000 1999 1998
Operating revenues:
Construction materials $ 597.7 $ 435.1 $ 310.5
Coal 33.7 34.8 35.9
631.4 469.9 346.4
Operating expenses:
Operation and maintenance 534.9 402.0 280.7
Depreciation, depletion and
amortization 36.2 26.0 20.6
Taxes, other than income 3.5 3.5 3.5
574.6 431.5 304.8
Operating income $ 56.8 $ 38.4 $ 41.6
Sales (000's):
Aggregates (tons) 18,315 13,981 11,054
Asphalt (tons) 3,310 2,993 1,790
Ready-mixed concrete
(cubic yards) 1,696 1,186 1,021
Coal (tons) 3,111 3,236 3,113
Amounts presented in the preceding tables for operating
revenues, purchased natural gas sold and operation and
maintenance expense will not agree with the Consolidated
Statements of Income due to the elimination of intercompany
transactions between the pipeline and energy services segment
and the natural gas distribution and natural gas and oil
production segments. The amounts relating to the elimination
of intercompany transactions for operating revenues,
purchased natural gas sold and operation and maintenance
expense are as follows: $96.9 million, $96.0 million and $.9
million for 2000; $64.5 million, $64.0 million and $.5
million for 1999; and $58.0 million, $57.5 million and $.5
million for 1998, respectively.
2000 compared to 1999
Electric
Electric earnings increased due to higher demand-related
retail sales to all major customer classes, higher average
realized rates and lower employee benefit-related expenses.
Increased fuel and purchased power costs, largely higher
purchased power costs, increased coal costs, and higher
natural gas generation-related costs, partially offset the
earnings increase. Higher maintenance expense at certain of
the company's electric generating stations, and increased
depreciation, depletion and amortization expense, resulting
from higher property, plant and equipment balances, also
partially offset the earnings increase.
Natural Gas Distribution
Earnings improved at the natural gas distribution
business largely due to higher weather-related retail sales
volumes resulting from weather in the fourth quarter which
was 46 percent colder than a year ago. Increased service and
repair margins, earnings from Great Plains, which was
acquired in July 2000, and higher transportation volumes also
added to the earnings increase. Increased depreciation,
depletion and amortization expense, due to higher property,
plant and equipment balances, and lower average realized
transportation rates, partially offset the earnings increase.
Utility Services
Utility services earnings increased as a result of earnings
from businesses acquired since the comparable period last year,
higher work load in the Rocky Mountain region, primarily related
to fiber optic installation projects, and increases from
engineering services. This increase was somewhat offset by
decreased construction activity for utilities on the West Coast,
largely the result of utility merger activity and the California
energy crisis.
Pipeline and Energy Services
Pipeline and energy services earnings decreased primarily
due to the absence in 2000 of a 1999 $4.4 million after-tax
reserve revenue adjustment and resulting increase to income
associated with FERC orders received in the 1992 and 1995
general rate proceedings, the recognition in 1999 of a $3.9
million after-tax reserve adjustment and resulting increase to
income relating to the resolution of certain production tax and
other state tax matters, and the recognition in income in 1999
of $1.7 million after-tax resulting from a favorable order
received from the United States Court of Appeals for the D.C.
Circuit Court (D.C. Circuit Court) relating to the 1992 general
rate proceeding. An asset impairment charge of $3.9 million
after-tax in 2000 at one of the company's energy services
companies also lowered earnings. In addition, higher bad debt
expense and lower natural gas margins from energy services, and
higher operation and maintenance expenses at the pipeline,
largely higher compressor-related expenses and payroll costs,
contributed to the decline in earnings. Partially offsetting
the decline in earnings was the recognition in 2000 of a $6.7
million after-tax reserve revenue adjustment and resulting
increase to income relating to the resolution of the 1995
general rate proceeding. Higher natural gas transportation
volumes combined with higher average transportation rates and
increased gathering volumes at the pipeline also partially
offset the earnings decline. The increase in energy services
revenue and the related increase in purchased natural gas sold
resulted from significantly higher natural gas prices and
increased volumes.
Natural Gas and Oil Production
Natural gas and oil production earnings increased primarily
due to significantly higher realized natural gas and oil
prices. Higher natural gas and oil production due to
acquisitions since the comparable period last year and ongoing
development of existing properties, along with increased other
revenue due to higher sales of inventoried natural gas, added
to the earnings increase. Partially offsetting the earnings
improvement were increased depreciation, depletion and
amortization expense, due to higher production volumes and
higher rates, and increased operation and maintenance expense,
mainly from higher lease operating expenses and higher general and
administrative costs due primarily to acquisitions, and
increased maintenance on existing properties. Increased
interest expense due to higher average borrowings and interest
rates also partially offset the earnings increase. Hedging
activities for natural gas and oil production for 2000 resulted
in realized prices that were 87 percent and 82 percent,
respectively, of what otherwise would have been received.
Construction Materials and Mining
Construction materials and mining earnings increased largely
due to the absence in 2000 of $5.6 million in after-tax charges
to earnings in 1999, the result of the resolution of the coal
arbitration proceeding. Higher earnings at the construction
materials operations as a result of earnings from businesses
acquired since the comparable period last year, higher aggregate,
ready-mixed concrete and cement volumes at existing operations
and a gain of $1.2 million after-tax on the sale of a
nonstrategic property also added to the earnings improvement.
Increased interest expense resulting from higher acquisition-
related borrowings, higher selling, general and administrative
costs, higher energy costs and increased depreciation, depletion
and amortization expense due to increased aggregate volumes and
increased plant balances, partially offset the earnings
improvement at the construction materials operations.
1999 compared to 1998
Electric
Electric earnings improved primarily due to increased sales
for resale revenue caused by a 61 percent increase in volumes
at higher margins, both largely resulting from favorable
contracts. Lower retail fuel and purchased power costs
primarily due to decreased purchased power demand charges
resulting from the 1998 pass-through of periodic maintenance
costs, related to a participation power contract, also added to
the earnings increase. Increased operation and maintenance
expense resulting mainly from higher subcontractor costs,
primarily at the Lewis & Clark Station due to boiler and
turbine maintenance, and increased payroll expense partially
offset the earnings improvement.
Natural Gas Distribution
Earnings decreased at the natural gas distribution business
due primarily to lower sales volumes caused by weather that was 5
percent and 11 percent warmer than last year and normal,
respectively. Increased operation and maintenance expense
resulting from higher payroll expenses also added to the
reduction in earnings. Increased volumes transported, primarily
to industrial customers, and higher service and repair income
partially offset the earnings decline.
Utility Services
Utility services earnings increased primarily due to
businesses acquired since the comparable period last year and
higher earnings from existing operations due to increased
construction work load and higher margins.
Pipeline and Energy Services
Pipeline and energy services earnings increased largely due
to a $4.4 million after-tax reserve revenue adjustment and a $3.9
million after-tax reserve adjustment, both as previously
discussed. The recognition of $1.7 million after-tax resulting
from a favorable order received from the D.C. Circuit Court, as
previously discussed, also contributed to the increase in
earnings. Decreased transportation to storage and off-system
markets at lower average transportation rates and reduced sales
of inventoried natural gas somewhat offset the earnings increase.
The $3.1 million after-tax reversal of reserves in 1998 for
certain contingencies relating to a FERC order concerning a
compliance filing also partially offset the 1999 earnings
increase. The increase in energy services revenue and the
related increase in purchased natural gas sold resulted primarily
from the acquisition of a natural gas marketing business in July
1998.
Natural Gas and Oil Production
Natural gas and oil production earnings increased largely as
a result of the 1998 $66.0 million ($39.9 million after tax)
noncash write-downs of natural gas and oil properties, as
discussed in Note 1 of Notes to Consolidated Financial
Statements. Higher natural gas and oil prices and increased
natural gas production due to both new acquisitions and the
ongoing development of existing properties also increased
earnings. In addition, decreased depreciation, depletion and
amortization expense due largely to lower rates resulting from
the write-downs of natural gas and oil properties also added to
the earnings improvement. Decreased oil production, resulting
mainly from normal production declines and the sale of
nonstrategic properties, and higher operation and maintenance
expense partially offset the increase in earnings. Higher
operation and maintenance expense resulted from changes in
production mix and higher general and administrative expenses.
Hedging activities for natural gas and oil production for 1999
resulted in realized natural gas prices which were unchanged and
realized oil prices that were 94 percent of what otherwise would
have been received.
Construction Materials and Mining
Construction materials and mining earnings decreased
primarily due to lower earnings at the coal operations largely
resulting from $5.6 million in after-tax charges and lower
average coal prices, both relating to the coal contract
arbitration proceeding. Earnings at the construction materials
businesses increased due to businesses acquired since the
comparable period last year and increased activity at existing
construction materials operations. Higher asphalt volumes,
increased average ready-mixed concrete prices and increased
construction and sales of other product lines all contributed to
the earnings increase at the construction materials operations.
Higher selling, general and administrative costs and increased
interest expense resulting from increased acquisition-related
long-term debt somewhat offset the increased earnings at the
construction materials business. Normal seasonal losses realized
in the first quarter of 1999 by construction materials businesses
not owned during the full first quarter in 1998 also partially
offset the earnings improvement at the construction materials
business.
Safe Harbor for Forward-looking Statements
The company is including the following cautionary statement
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 which are other than statements of historical facts.
From time to time, the company may publish or otherwise make
available forward-looking statements of this nature, including
statements contained within Prospective Information. All such
subsequent forward-looking statements, whether written or oral
and whether made by or on behalf of the company, are also
expressly qualified by these cautionary statements.
Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed. The company's expectations, beliefs and
projections are expressed in good faith and are believed by the
company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the company's records and other data available from
third parties, but there can be no assurance that the company's
expectations, beliefs or projections will be achieved or
accomplished. Furthermore, any forward-looking statement speaks
only as of the date on which such statement is made, and the
company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances that
occur after the date on which such statement is made or to
reflect the occurrence of unanticipated events. New factors
emerge from time to time, and it is not possible for management
to predict all of such factors, nor can it assess the effect of
each such factor on the company's business or the extent to which
any such factor, or combination of factors, may cause actual
results to differ materially from those contained in any forward-
looking statement.
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the company to differ materially from those
discussed in forward-looking statements include prevailing
governmental policies and regulatory actions with respect to
allowed rates of return, financings, or industry and rate
structures, acquisition and disposal of assets or facilities,
operation and construction of plant facilities, recovery of
purchased power and purchased gas costs, present or prospective
generation and availability of economic supplies of natural gas.
Other important factors include the level of governmental
expenditures on public projects and the timing of such projects,
changes in anticipated tourism levels, the effects of competition
(including but not limited to electric retail wheeling and
transmission costs and prices of alternate fuels and system
deliverability costs), natural gas and oil commodity prices,
drilling successes in natural gas and oil operations, ability to
acquire natural gas and oil properties, and the availability of
economic expansion or development opportunities.
The business and profitability of the company are also
influenced by economic and geographic factors, including
political and economic risks, changes in and compliance with
environmental and safety laws and policies, weather conditions,
population growth rates and demographic patterns, market demand
for energy from plants or facilities, changes in tax rates or
policies, unanticipated project delays or changes in project
costs, unanticipated changes in operating expenses or capital
expenditures, labor negotiations or disputes, changes in credit
ratings or capital market conditions, inflation rates, inability
of the various counterparties to meet their contractual
obligations, changes in accounting principles and/or the
application of such principles to the company, changes in
technology and legal proceedings, and the ability to effectively
integrate the operations of acquired companies.
Prospective Information
The following information includes highlights of the key
growth strategies, projections and certain assumptions for the
company over the next few years and other matters for each of its
six major business segments. Many of these highlighted points are
forward-looking statements. There is no assurance that the
company's projections, including estimates for growth and
increases in revenues and earnings, will in fact be achieved.
Reference should be made to assumptions contained in this
section, changes in which, as well as the various important
factors listed under the heading Safe Harbor for Forward-looking
Statements, that could cause actual future results to differ
materially from the company's targeted growth, revenue and
earnings projections.
MDU Resources Group, Inc.
- - Based on current expectations, the company anticipates that
its three to five year compound annual earnings per share growth
rate from operations will be in the general range of 10 to 12
percent.
- - Earnings per share, diluted, from operations for 2001 are
projected in the $1.95 to $2.05 range.
- - The company expects the percentage of 2001 earnings per
share from operations by quarter to be in the following
approximate ranges:
- First Quarter: 13 to 18 percent
- Second Quarter: 20 to 25 percent
- Third Quarter: 35 to 40 percent
- Fourth Quarter: 22 to 27 percent
- - The company expects to issue and sell equity from time to
time to keep its debt at the nonregulated businesses at no more
than 40 percent of total capitalization.
- - Based on existing operations, annual goodwill amortization
expense is expected to be approximately $4 million.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric and natural gas
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. Currently, a smaller town in western North Dakota
is considering municipalization of Montana-Dakota's electric and
natural gas facilities. Montana-Dakota is vigorously contesting
any such proposal but is currently unable to determine the
ultimate outcome of any such proceeding. 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
- - Annual natural gas throughput for 2001 is expected to be
approximately 56 million decatherms, with about 40 million
decatherms from sales and 16 million from transportation.
- - The number of natural gas retail customers at existing
operations is expected to grow by approximately 1.5 to 2 percent
on an annual basis over the next three to five years.
- - Earnings are expected to increase from the growth in sales
of new value-added products and services such as appliance repair
contracts and home security systems.
Utility services
- - Revenues for this segment are expected to exceed $300
million in 2001.
- - This segment's goal is to achieve compound annual revenue
and earnings growth rates of approximately 20 to 25 percent over
the next five years.
Pipeline and energy services
- - Two pipeline projects related to the company's coal bed
natural gas drilling program in the Powder River Basin of Wyoming
and Montana were completed in 2000. The two projects provide the
pipeline company the ability to move approximately 40 percent
more coal bed natural gas through its system than has
historically been transported, as well as enabling additional
deliveries to other pipeline systems. The largest project
involved building a 75-mile, nonregulated pipeline through the
heart of the basin, to move gas produced from throughout the
Powder River Basin to interconnecting pipeline systems, including
the company's own transmission system.
- - In 2001, Williston Basin's natural gas throughput is
expected to increase by approximately 9 percent.
- - This segment continues business development activities
looking for assets and resources that add value to existing
operations through further vertical integration of its natural
gas delivery and storage systems.
Natural gas and oil production
- - The 2001 drilling program is projected to include over 500
wells, 90 percent of which are expected to be drilled on operated
properties and the emphasis will continue to be on natural gas.
The 2001 drilling program is expected to be the largest drilling
program in the company's history.
- - Combined natural gas and oil production at this segment is
expected to be 30 to 40 percent higher in 2001 than in 2000.
- - The company's estimates for natural gas prices in the Rocky
Mountain region are in the range of $2.50 to $3.00 per Mcf during
2001. The company's estimates for natural gas prices on the New
York Mercantile Exchange (NYMEX) for 2001 are in the range of $3
to $4 per Mcf.
- - The company's 2001 estimates for NYMEX crude oil prices are
in the range of $23 to $26 per barrel.
- - This segment has entered into hedging arrangements for a
portion of its 2001 production. The company has entered into
swap agreements and fixed price forward sales representing
approximately one-fourth of 2001 estimated annual natural gas
production. Natural gas swap prices range from $4.57 to $4.60 per
Mcf based on NYMEX and $4.04 to $4.44 per Mcf for Rocky Mountain
gas sales. In addition, approximately one-third of 2001
estimated annual oil production is hedged at NYMEX prices ranging
from $28.65 to $29.22 per barrel.
Construction materials and mining
- - On September 28, 2000, the company announced an agreement to
sell its coal operations to Westmoreland Coal Company for $28.8
million cash, excluding final settlement cost adjustments. The
agreement is subject to various closing conditions and therefore
will not be finalized unless and until the parties are satisfied
that those conditions are met. Earnings from coal operations
would normally be expected to contribute less than 10 percent of
annual earnings of the construction materials and mining segment.
- - Excluding the effects of potential future acquisitions,
aggregate, asphalt and ready-mixed concrete volumes are expected
to increase by approximately 15 percent, 32 percent and 13
percent, respectively, in 2001.
- - This segment expects to achieve compound annual revenue and
earnings growth rates of approximately 10 to 20 percent over the
next five years.
- - Earnings are expected to increase from a combination of
acquisitions and by optimizing both synergies and improvements at
existing operations.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133), amended by Statement of Financial Accounting
Standards No. 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133" and Statement of Financial Accounting
Standards No. 138, "Accounting for Certain Derivative Instruments
and Certain Hedging Activities" (all such statements hereinafter
referred to as SFAS No. 133). For further information on SFAS
No. 133, see Note 1 of Notes to Consolidated Financial
Statements.
In December 1999, the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 101, "Revenue Recognition"
(SAB No. 101), which provides guidance on the recognition,
presentation and disclosure of revenue in financial statements.
The company adopted SAB No. 101 in the fourth quarter of 2000.
The adoption of SAB No. 101 did not have a material effect on the
company's financial position or results of operations.
Liquidity and Capital Commitments
The company's capital expenditures (in millions) for 1998
through 2000 and as anticipated for 2001 through 2003 are
summarized in the following table, which also includes the
company's capital needs for the retirement of maturing long-term
debt and preferred stock.
Actual Estimated*
1998 1999 2000 Capital Expenditures: 2001 2002 2003
$ 13.0 $ 18.2 $ 15.8 Electric $ 14.8 $ 16.6 $ 20.9
8.3 9.2 21.3 Natural gas distribution 13.9 11.2 10.7
18.3 16.1 42.6 Utility services 52.6 30.5 31.7
17.6 35.1 69.0 Pipeline and energy services 61.4 56.8 38.0
Natural gas and oil
100.6 64.3 173.5 production 103.6 130.5 109.8
Construction materials
172.1 105.1 218.7 and mining 126.4 92.9 73.8
329.9 248.0 540.9 372.7 338.5 284.9
Net proceeds from
sale or disposition
(4.3) (16.6) (11.0) of property (31.6) (.4) (.1)
325.6 231.4 529.9 Net capital expenditures 341.1 338.1 284.8
Retirement of long-term
113.7 18.8 29.4 debt and preferred stock 19.7 50.5 282.8
$439.3 $250.2 $559.3 $360.8 $388.6 $567.6
- ------------------------
* The estimated 2001 through 2003 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 2000, 1999 and 1998, related to
acquisitions, in the preceding table include the following
noncash transactions: issuance of the company's equity securities
and the conversion of a note receivable to purchase consideration
of $132.1 million in 2000; the issuance of the company's equity
securities of $77.5 million in 1999; and the issuance of the
company's equity securities, less treasury stock acquired, in
1998 of $138.8 million.
In 2000, the company acquired a number of businesses, none
of which was individually material, including construction
materials and mining businesses with operations in Alaska,
California, Montana and Oregon; a coal bed natural gas
development operation based in Colorado with related oil and gas
leases and properties in Montana and Wyoming; utility services
businesses based in California, Colorado, Montana and Ohio; a
natural gas distribution business serving southeastern North
Dakota and western Minnesota; and an energy services company
based in Texas. The total purchase consideration for these
businesses, consisting of the company's common stock, cash and
the conversion of a note receivable to purchase consideration was
$286.0 million.
The 2000 capital expenditures, including those for the
previously mentioned acquisitions, and retirements of long-term
debt and preferred stock, were met from internal sources, the
issuance of long-term debt and the company's equity securities.
Capital expenditures for the years 2001 through 2003, include
those for system upgrades, routine replacements, service
extensions, routine equipment maintenance and replacements,
pipeline and gathering expansion projects, the building of
construction materials handling and transportation facilities,
the further enhancement of natural gas and oil production and
reserve growth, and for 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
estimates in the preceding table. It is anticipated that all of
the funds required for capital expenditures and retirements of
long-term debt and preferred stock for the years 2001 through
2003 will be met from various sources. These sources include
internally generated funds, the company's $40 million revolving
credit and term loan agreement, an existing line of credit of
$8.2 million, a commercial paper credit facility at Centennial,
as described below, and through the issuance of long-term debt
and the company's equity securities. At December 31, 2000, $40
million under the revolving credit and term loan agreement and
$6.3 million under the line of credit were outstanding.
Centennial, a direct wholly owned subsidiary of the company,
has a revolving credit agreement with various banks on behalf of
its subsidiaries that supports $315 million of Centennial's $325
million commercial paper program. Under the Centennial
commercial paper program, $261.4 million was outstanding at
December 31, 2000. The commercial paper borrowings are
classified as long term as Centennial intends to refinance these
borrowings on a long-term basis through continued commercial
paper borrowings supported by the revolving credit agreement due
September 29, 2003. Centennial intends to renew this existing
credit agreement on an annual basis.
Centennial has an uncommitted long-term master shelf
agreement on behalf of its subsidiaries that allows for
borrowings of up to $200 million. Under the master shelf
agreement, $150 million was outstanding at December 31, 2000.
On October 4, 2000, the company filed an application with the
FERC seeking authorization to issue a combination of certain
securities, as the company determines to be necessary, not to
exceed a total of $750 million. The FERC approved the company's
application on November 7, 2000.
On November 20 and December 26, 2000, and February 2, 2001,
the company reported sales that together totaled 1,038,739 shares
of the company's Common Stock to Acqua Wellington North American
Equities Fund Ltd. (Acqua Wellington), pursuant to purchase
agreements by and between the company and Acqua Wellington. The
company received total proceeds from these sales of $29.5
million. These proceeds were used for refunding outstanding debt
obligations and for other general corporate purposes.
The company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of
its Indenture of Mortgage. Generally, those restrictions require
the company to pledge $1.43 of unfunded property to the Trustee
for each dollar of indebtedness incurred under the Indenture and
that annual earnings (pretax and before interest charges), as
defined in the Indenture, equal at least two times its annualized
first mortgage bond interest costs. Under the more restrictive
of the two tests, as of December 31, 2000, the company could have
issued approximately $295 million of additional first mortgage
bonds.
The company's coverage of fixed charges including preferred
dividends was 4.1 and 4.3 times for 2000 and 1999, respectively.
Additionally, the company's first mortgage bond interest coverage
was 8.3 times in 2000 compared to 7.1 times in 1999. Common
stockholders' equity as a percent of total capitalization was 54
percent at both December 31, 2000 and 1999.
Effects of Inflation
Inflation did not have a significant effect on the company's
operations in 2000, 1999 or 1998.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity price risk --
The company utilizes derivative financial instruments,
including price swap and collar agreements, to manage a portion
of the market risk associated with fluctuations in the price of
natural gas and oil. 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 financial
instruments in the event of nonperformance by counterparties, but
does not expect any counterparties to fail to meet their
obligations given their existing credit ratings.
The swap and collar agreements call for the company to
receive monthly payments from or make payments to counterparties
based upon the difference between a fixed and a variable price as
specified by the agreements. The variable price is either a
quoted natural gas price on the NYMEX, Colorado Interstate Gas
Index or other various indexes or an oil price quoted on the
NYMEX. The company believes that there is a high degree of
correlation because the timing of purchases and production and
the swap and collar agreements are closely matched, and hedge
prices are established in the areas of operations. For the years
ending December 31, 2000, 1999 and 1998, gains or losses on the
swap and collar agreements were matched and reported in operating
revenues on the Consolidated Statements of Income as a component
of the related commodity transaction at the time of settlement
with the counterparty.
The following table summarizes hedge agreements entered into
by certain wholly owned subsidiaries of the company, as of
December 31, 2000. These agreements call for the subsidiaries to
receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing $ 4.45 5,461 $(12,311)
in 2001
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2001 $28.80 593 $ 2,261
The following table summarizes hedge agreements entered into
by certain wholly owned subsidiaries of the company, as of
December 31, 1999. These agreements call for the subsidiaries to
receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2000 $2.33 5,307 $ 597
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2000 $19.55 769 $ (1,870)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2000 $2.34/$2.68 3,196 $ 112
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreement
maturing in 2000 $20.00/$22.33 183 $ (134)
The fair value of these derivative financial instruments
reflects the estimated amounts that the company would receive or
pay to terminate the contracts at the reporting date, thereby
taking into account the current favorable or unfavorable position
on open contracts. The favorable or unfavorable position is not
recorded on the company's Consolidated Balance Sheets as of
December 31, 2000 and 1999. Favorable and unfavorable positions
related to commodity hedge agreements are expected to be
generally offset by corresponding increases and decreases in the
value of the underlying commodity transactions.
In the event a derivative financial instrument does not
qualify for hedge accounting or when the underlying commodity
transaction matures, is sold, is extinguished, or is terminated,
the current favorable or unfavorable position on the open
contract would be included in results of operations. The
company's policy requires approval to terminate a hedge agreement
prior to its original maturity. In the event a hedge agreement
is terminated, the realized gain or loss at the time of
termination would be deferred until the underlying commodity
transaction is sold or matures and is expected to generally
offset the corresponding increases or decreases in the value of
the underlying commodity transaction.
The company has energy marketing operations that are exposed
to risks, including risks relating to changes in natural gas
prices and counterparty performance (credit risk), associated
with natural gas forward purchase and sale commitments. These
commitments involve the purchase and sale of natural gas and
related delivery of such commodity. The energy marketing
operations seek to match natural gas purchases and sales on
specific contracts so that a margin is obtained on the
transportation of such commodity as distinguished from earning a
margin on changes in market prices. In addition, the energy
marketing contracts are generally entered into on a seasonal
basis with contracts of a duration generally not exceeding 12
months. Contracts related to these activities are valued at fair
value and changes in fair value are recorded as assets or
liabilities on the company's Consolidated Balance Sheets. The
net change in fair value representing unrealized gains and losses
resulting from changes in market prices on these contracts is
reflected in earnings on the company's Consolidated Statements of
Income. Net unrealized gains and losses on these contracts were
not material in 2000, 1999 or 1998. In general, market risk is
the risk of fluctuations in the market price of the commodity
being marketed and is influenced primarily by supply and demand.
The company monitors and manages its exposure to market risk
through a variety of risk management techniques. Such procedures
include monitoring commitments and positions, evaluating
sensitivity to changes in market prices and market volatility,
and reporting to senior management. Credit risk is the risk of
loss from nonperformance by counterparties of their contractual
obligations. The company maintains credit procedures, which
management believes significantly minimize overall credit risk.
The company seeks to mitigate credit risk by applying specific
eligibility criteria to prospective counterparties and may
require letters of credit or similar security to secure payment
on such sales contracts. However, despite mitigation efforts,
defaults by counterparties may occur. To date, no such defaults
have had a material effect on the company's financial position or
results of operations.
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
also has outstanding 15,000 shares of 5.10% Series preferred
stock subject to mandatory redemption as of December 31, 2000.
The company is obligated to make annual sinking fund
contributions to retire the preferred stock and pay cumulative
preferred dividends at a fixed rate of 5.10%. The table below
shows the amount of debt, including current portion, and related
weighted average interest rates, by expected maturity dates and
the aggregate annual sinking fund amount applicable to preferred
stock subject to mandatory redemption and the related dividend
rate, as of December 31, 2000. Weighted average variable rates
are based on forward rates as of December 31, 2000.
Fair
2001 2002 2003 2004 2005 Thereafter Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $19.6 $50.4 $ 21.9 $21.6 $69.9 $303.6 $487.0 $500.8
Weighted average
interest rate 7.8% 9.0% 7.4% 6.6% 8.0% 7.6% 7.7% -
Variable rate - - $260.8 - - - $260.8 $271.3
Weighted average
interest rate - - 6.9% - - - 6.9% -
Preferred stock
subject to
mandatory
redemption $ .1 $ .1 $ .1 $ .1 $ .1 $ 1.0 $ 1.5 $ .9
Dividend rate 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% -
For further information on risk management activities and financial
instruments, see Note 3 of Notes to Consolidated Financial
Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 29 through 53 of the company's
Annual Report, which is incorporated herein by reference.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is made to Pages 2 through 6 and 19 through 21 of
the company's Proxy Statement dated March 9, 2001 (Proxy
Statement) which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 14 through 19 of the Proxy
Statement, which is incorporated herein by reference with the
exception of the compensation committee report on executive
compensation and the MDU Resources Group, Inc. comparison of five-
year total stockholder return.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Pages 21 and 22 of the Proxy Statement,
which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits.
Index to Financial Statements and Financial Statement
Schedules
Page
1. Financial Statements:
Report of Independent Public Accountants *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 2000 *
Consolidated Balance Sheets at December 31,
2000 and 1999 *
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 2000 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 2000 *
Notes to Consolidated Financial Statements *
2. Financial Statement Schedules (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.)
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* The Consolidated Financial Statements listed in the above index
which are included in the company's Annual Report to
Stockholders for 2000 are hereby incorporated by reference.
With the exception of the pages referred to in Items 6 and 8,
the company's Annual Report to Stockholders for 2000 is not to
be deemed filed as part of this report.
3. Exhibits:
3(a) Restated Certificate of Incorporation of
the company, as amended to date, filed as
Exhibit 3(a) to Form 10-Q for the quarter
ended June 30, 1999, in File No. 1-3480 *
3(b) By-laws of the company, as amended to date,
filed as Exhibit 3(b) to Form 10-Q for the
quarterly period ended September 30, 1998,
in File No. 1-3480 *
4(a) Indenture of Mortgage, dated as of May 1,
1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of
April 21, 1992, and the Forty-Sixth
through Forty-Ninth Supplements thereto
between the company and the New York Trust
Company (The Bank of New York, successor
Corporate Trustee) and A. C. Downing
(Douglas J. MacInnes, successor Co-
Trustee), filed as Exhibit 4(a) in
Registration No. 33-66682; and Exhibits
4(e), 4(f) and 4(g) in Registration
No. 33-53896; and Exhibit 4(c)(i) in
Registration No. 333-49472 *
4(b) Rights agreement, dated as of November 12,
1998, between the company and Norwest Bank
Minnesota, N.A., Rights Agent, filed as
Exhibit 4.1 to Form 8-A on November 12,
1998, in File No. 1-3480 *
+ 10(a) Executive Incentive Compensation Plan,
as amended to date, filed as Exhibit 10(a)
to Form 10-K for the year ended December 31,
1998, in File No. 1-3480 *
+ 10(b) 1992 Key Employee Stock Option Plan, as
amended to date, filed as Exhibit 10(a) to
Form 10-Q for the quarter ended June 30,
2000 in File No. 1-3480 *
+ 10(c) Supplemental Income Security Plan, as
amended to date, filed as Exhibit 10(d) to
Form 10-K for the year ended December 31,
1996, in File No. 1-3480 *
+ 10(d) Directors' Compensation Policy, as amended
to date, filed as Exhibit 10(b) to Form
10-Q for the quarter ended June 30, 2000,
in File No. 1-3480 *
+ 10(e) Deferred Compensation Plan for Directors,
as amended to date, filed as Exhibit 10(c)
to Form 10-Q for the quarter ended June 30,
2000, in File No. 1-3480 *
+ 10(f) Non-Employee Director Stock Compensation
Plan, as amended to date, filed as Exhibit
10(b) to Form 10-Q for the quarter ended
March 31, 1999, in File No. 1-3480 *
+ 10(g) 1997 Non-Employee Director Long-Term
Incentive Plan, as amended to date, 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 to date **
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 2000 **
21 Subsidiaries of MDU Resources Group, Inc. **
23 Consent of Independent Public Accountants **
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* 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
14(c) of this report.
(b) Reports on Form 8-K
Form 8-K was filed on November 20, 2000. Under Item 5 --
Other Events, the company reported the sale of 246,532 shares of
company Common Stock to Acqua Wellington North American Equities
Fund, Ltd.
Form 8-K was filed on December 27, 2000. Under Item 5 --
Other Events, the company reported the sale of 263,420 shares of
company Common Stock to Acqua Wellington North American Equities
Fund, Ltd.
Form 8-K was filed on January 26, 2001. Under Item 5 --
Other Events, the company reported the press release issued
January 25, 2001 regarding earnings for the year ended December
31, 2000.
Form 8-K was filed on February 2, 2001. Under Item 5 --
Other Events, the company reported the sale of 528,787 shares of
company Common Stock to Acqua Wellington North American Equities
Fund, Ltd.
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: March 2, 2001 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 March 2, 2001
Martin A. White (Chairman of the Board Officer
President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief March 2, 2001
Douglas C. Kane (Executive Vice President, Administrative &
Chief Administrative & Corporate Corporate
Development Officer) Development Officer
and Director
/s/ Warren L. Robinson Chief Financial March 2, 2001
Warren L. Robinson (Executive Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting March 2, 2001
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ Thomas Everist Director March 2, 2001
Thomas Everist
/s/ Dennis W. Johnson Director March 2, 2001
Dennis W. Johnson
/s/ Richard L. Muus Director March 2, 2001
Richard L. Muus
/s/ Robert L. Nance Director March 2, 2001
Robert L. Nance
/s/ John L. Olson Director March 2, 2001
John L. Olson
/s/ Harry J. Pearce Director March 2, 2001
Harry J. Pearce
/s/ Homer A. Scott, Jr. Director March 2, 2001
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director March 2, 2001
Joseph T. Simmons
/s/ Sister Thomas Welder Director March 2, 2001
Sister Thomas Welder