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, 1999
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________ to ____________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
Common Stock, par value $1.00 on which registered
and Preference Share Purchase Rights New York Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, par value $100
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months, and (2) has been
subject to such filing requirements for the past 90 days. Yes X . No
__.
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. X
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 25, 2000:
$1,041,284,000.
Indicate the number of shares outstanding of each of the
Registrant's classes of common stock, as of February 25, 2000:
57,056,646 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 27 through 55 of the Registrant's Annual Report to
Stockholders for 1999 are incorporated by reference in Part II,
Items 6 and 8 of this Report.
2. Portions of the Registrant's Proxy Statement, dated March 10, 2000
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
Oil and Natural Gas 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 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), the 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 the Northern Great Plains.
The company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), and Utility
Services, Inc. (Utility Services).
WBI Holdings is comprised of the pipeline and energy
services and the oil and natural gas 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
marketing and management services throughout the United
States. The oil and natural gas production segment is
engaged in oil and natural gas acquisition, exploration
and production throughout 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.
Utility Services is a full-service engineering, design
and build company operating in the western United States
specializing in construction and maintenance of power and
natural gas distribution and transmission systems as well
as communication and fiber optic facilities.
As of December 31, 1999, the company had 3,791 full-time
employees with 78 employed at MDU Resources Group, Inc., 910 at
Montana-Dakota, 326 at WBI Holdings, 1,883 at Knife River's
operations and 594 at Utility Services. Approximately 438 and 85
of the Montana-Dakota and WBI Holdings 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, 2001, with the United Mine Workers of America,
which represents its coal operation's hourly workforce
aggregating 111 employees. In addition, Knife River has 19 labor
contracts which represent 550 of its construction materials
employees. Utility Services has 33 labor contracts representing
the majority of its employees.
During 1999, the company underwent segment operating and
reporting changes. The financial results and data applicable to
each of the company's business segments as well as their
financing requirements and a discussion regarding the previously
mentioned operating segment changes are set forth in Item 7 --
Management's Discussion and Analysis of Financial Condition and
Results of Operations and Notes to Consolidated Financial
Statements.
Any reference to the company's Consolidated Financial
Statements and Notes thereto shall be to pages 27 through 53 in
the company's Annual Report to Stockholders for 1999 (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 177 communities and adjacent rural areas as
of December 31, 1999. 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, 1999, Montana-Dakota's net electric plant investment
approximated $278.6 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 1999 electric utility operating revenues by
jurisdiction is as follows: North Dakota -- 61 percent;
Montana -- 22 percent; South Dakota -- 8 percent and Wyoming --
9 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 426,400 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 from Basin Electric Power
Cooperative for its interconnected system.
The following table sets forth details applicable to the
company's electric generating stations:
1999 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 752,862
Heskett Steam 86,000 103,000 526,121
Williston Combustion
Turbine 7,800 9,600 76
South Dakota --
Big Stone* Steam 94,111 103,660 828,840
Montana --
Lewis & Clark Steam 44,000 50,170 226,663
Glendive Combustion
Turbine 34,780 31,800 12,125
Miles City Combustion
Turbine 23,150 21,420 4,082
393,488 426,400 2,350,769
- -----------------------------
* Reflects Montana-Dakota's ownership interest.
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. See Item 3 --
Legal Proceedings for a discussion of the resolution of a suit
and arbitration filed by the Co-owners of the Coyote Station
against Knife River and the company. 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, 1995, through
December 31, 1999, the average cost of coal consumed, 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 so consumed
was as follows:
Years Ended December 31,
1999 1998 1997 1996 1995
Average cost of
coal per
million Btu $.90 $.93 $.95 $.93 $.94
Average cost of
coal per ton $13.31 $13.67 $14.22 $13.64 $12.90
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 420,550 kW in July 1999. 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 2005 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 2005 will
approximate 0.8 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 will 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.
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.
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. Based on the
provisions of such restructuring bill, because the company's
utility division operates in more than one state, the company has
the option of deferring its transition to full customer choice
until 2006. 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 the State. 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 (22 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 1999 and does not
expect to incur any significant capital expenditures related to
environmental compliance through 2002.
NATURAL GAS DISTRIBUTION
General --
Montana-Dakota sells natural gas and propane at retail,
serving over 209,000 residential, commercial and industrial
customers located in 141 communities and adjacent rural areas as
of December 31, 1999, and provides natural gas transportation
services to certain customers on its system. These services are
provided through a distribution system aggregating over 4,300
miles. Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct natural gas and propane
distribution operations in all of the municipalities it serves
where such franchises are required. As of December 31, 1999,
Montana-Dakota's net natural gas and propane distribution plant
investment approximated $81.2 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 and propane 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 percentage of
Montana-Dakota's 1999 natural gas and propane utility operating
revenues by jurisdiction is as follows: North Dakota -- 42
percent; Montana -- 29 percent; South Dakota -- 22 percent and
Wyoming -- 7 percent.
System Supply, System Demand and Competition --
Montana-Dakota serves 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,
Williston, Minot and Jamestown; 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 Montana-Dakota's natural gas and
propane sales, natural gas transportation volumes and degree days
as a percentage of normal during the last five years:
Years Ended December 31,
1999 1998 1997 1996 1995
Mdk (thousands of decatherms)
Sales:
Residential 18,059 18,614 20,126 22,682 20,135
Commercial 12,030 12,458 13,799 15,325 13,509
Industrial 842 952 395 276 295
Total 30,931 32,024 34,320 38,283 33,939
Transportation:
Commercial 1,975 1,995 1,612 1,677 1,742
Industrial 9,576 8,329 8,455 7,746 9,349
Total 11,551 10,324 10,067 9,423 11,091
Total Throughput 42,482 42,348 44,387 47,706 45,030
Degree days
(% of normal) 88.8% 93.7% 99.3% 116.2% 101.6%
The restructuring of the natural gas industry, as described
under Pipeline and Energy Services Operations and Property, has
resulted in additional competition in retail natural gas markets.
In response to these changed market conditions Montana-Dakota has
established various natural gas transportation service rates for
its distribution business to retain interruptible commercial and
industrial load. Certain of these services include
transportation under flexible rate schedules whereby Montana-
Dakota's interruptible customers can avail themselves of the
advantages of open access transportation on 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 competitive posture with alternate
fuels, although certain of Montana-Dakota's customers have the
potential of bypassing Montana-Dakota's distribution system by
directly accessing Williston Basin's facilities.
Montana-Dakota acquires its system requirements directly from
producers, processors and marketers. Such natural gas is
supplied under contracts specifying market-based pricing, and is
transported under firm transportation agreements by Williston
Basin, Northern Gas Company, South Dakota Intrastate Pipeline
Company and Northern Border Pipeline Company. 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. Montana-Dakota estimates that, based on
regional supplies of natural gas currently available through its
suppliers and expected to be available, it will have adequate
supplies of natural gas to meet its system requirements for the
next five years.
Regulatory Matters --
Montana-Dakota's 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 to
recover increases or refund decreases in such costs within 24
months from the time such changes occur.
Environmental Matters --
Montana-Dakota's natural gas and propane distribution
operations are subject to federal, state and local
environmental, facility siting, zoning and planning laws and
regulations. Montana-Dakota believes it is in substantial
compliance with those regulations.
UTILITY SERVICES
Utility Services offers contract services in electric and
natural gas transmission and distribution construction and
maintenance, fiber optic cable construction, engineering and
material sales. These services are provided to electric,
natural gas and telecommunication companies throughout the
western United States.
During 1999, the company acquired utility services companies
based in Montana and Oregon. None of these acquisitions were
individually material.
Utility Services operates in a highly competitive business.
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 all mobile and
can be moved to wherever the markets are. As a result, the
market area can be large. 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. 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 3,700 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, 1999, Williston Basin's net plant
investment was approximately $158.7 million.
WBI Holdings also owns a gathering entity with operations in
Wyoming which include various field gathering lines and leased
compression facilities 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 and transmission pipelines and associated onshore
pipeline and related processing facilities are also owned by WBI
Holdings.
In addition, 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
and operating two retail propane operations in north-central and
southeastern North Dakota. 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.
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. Beginning in the mid-1980s, customers began
switching their natural gas service from a bundled merchant
service to transportation, and with the implementation of Order
636 which unbundled pipelines' services, this transition was
accelerated. 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 along with interconnections with
other pipelines serve to enhance Williston Basin's competitive
position.
Although a significant portion of Williston Basin's firm
customers, including 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, 1999, represented 88 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 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. Williston Basin expects to
facilitate the movement of these supplies by making available its
transportation and storage services. Opportunities may exist to
increase transportation and storage services through system
expansion or other pipeline interconnections or enhancements
which could provide substantial future benefits to Williston
Basin.
Regulatory Matters and Revenues Subject to Refund --
Williston Basin had pending with the FERC a general natural
gas rate change application implemented in 1992. In
October 1997, Williston Basin appealed to the United States Court
of Appeals for the D.C. Circuit (D.C. Circuit Court) certain
issues decided by the FERC in orders concerning the 1992
proceeding. On January 22, 1999, the D.C. Circuit Court issued
its opinion remanding the issues of return on equity, ad valorem
taxes and throughput to the FERC for further explanation and
justification. The mandate was issued by the D.C. Circuit Court
to the FERC on March 11, 1999. By order dated June 1, 1999, the
FERC remanded the return on equity issue to an Administrative Law
Judge for further proceedings. On October 13, 1999, the FERC
approved a settlement proposed by the parties to the proceeding
which resolves the remanded return on equity issue and concludes
the proceeding. Based on the FERC's approval of this settlement,
Williston Basin sought reimbursement from its customers in the
fourth quarter of 1999 of a portion of the refunds made in 1997
relating to the return on equity issue.
In June 1995, Williston Basin filed a general rate increase
application with the 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. On June 1,
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. On July 1, 1999, Williston Basin
requested rehearing of certain issues which were contained in the
June 1, 1999 FERC order. On September 29, 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, on October 29, 1999, Williston Basin
issued refunds to its customers totaling $11.3 million, all from
amounts which had previously been reserved. In mid-December
1999, a hearing was held before the FERC regarding the return on
equity issue. In addition, on July 29, 1999, Williston Basin
appealed to the D.C. Circuit Court certain issues concerning
storage cost allocations as decided by the FERC in its June 1,
1999 order. On October 12, 1999, the D.C. Circuit Court issued
an order which dismissed Williston Basin's appeal but permitted
Williston Basin to again appeal such previously contested issues
upon final determination of all issues by the FERC in this
proceeding.
On December 1, 1999, Williston Basin filed a general natural
gas rate change application with the FERC. Williston Basin will
begin 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 June 1, 1999 FERC
orders referenced above, Williston Basin in the second quarter of
1999 determined that reserves it had previously established
exceeded its expected refund obligation and, accordingly,
reversed reserves in the amount of $4.4 million after tax.
Williston Basin believes that its remaining reserves are adequate
based on its assessment of the ultimate outcome of the various
proceedings.
Environmental Matters --
WBI Holdings is 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.
Other --
During the third quarter of 1999, the company and Williston
Basin reached resolution with respect to certain production tax
and other state tax matters that had been outstanding, some
dating back to 1989. Deficiency claims of approximately $5.6
million, plus interest, had been received with respect to these
issues. As a result in September 1999, Williston Basin reversed
reserves which were no longer needed in an amount of $3.9 million
after tax.
OIL AND NATURAL GAS 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 oil
and natural gas resources. Fidelity's operations 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 throughout
the United States and in the Gulf of Mexico in proportion to its
interests.
Fidelity also owns in fee or holds natural gas leases for the
properties it operates in Montana, North Dakota and Colorado.
These rights are in the Cedar Creek Anticline in southeastern
Montana, in the Bowdoin area located in north-central Montana and
the Bonny Field located in eastern Colorado.
The oil and natural gas 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 continuing
success in these endeavors.
Operating Information --
Information on oil and natural gas production, average prices
and production costs per net equivalent Mcf related to oil and
natural gas interests for 1999, 1998 and 1997, are as follows:
1999 1998 1997
Oil:
Production (000's of barrels) 1,758 1,912 2,088
Average price $15.34 $12.71 $17.50
Natural Gas:
Production (MMcf) 24,652 20,699 20,407
Average price $ 1.94 $ 1.81 $ 2.02
Production costs, including taxes,
per net equivalent Mcf $0.62 $0.52 $0.58
Well and Acreage Information --
Gross and net productive well counts and gross and net
developed and undeveloped acreage related to interests at
December 31, 1999, are as follows:
Gross Net
Productive Wells:
Oil 1,229 159
Natural Gas 1,407 849
Total 2,636 1,008
Developed Acreage (000's) 788 301
Undeveloped Acreage (000's) 435 119
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1999, 1998 and 1997:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1999 1 2 3 70 2 72 75
1998 2 2 4 54 --- 54 58
1997 1 2 3 23 1 24 27
At December 31, 1999, there were nine gross wells in the
process of drilling, six of which were exploratory wells and
three of which were development wells.
Reserve Information --
Fidelity's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 14.7 million barrels and
268.9 Bcf, respectively, at December 31, 1999.
For additional information related to oil and natural gas
interests, see Notes 1 and 17 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 1999, the company acquired several construction
materials and mining companies with operations in California,
Montana, Oregon and Wyoming. None of these acquisitions were
individually material.
Knife River's construction materials business has continued
to grow since its first acquisition in 1992 and now comprises the
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 should 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 $107
million in backlog in mid-February 2000, compared to
approximately $100 million in mid-February 1999. The company
anticipates that a significant amount of the current backlog will
be completed during the year ending December 31, 2000.
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 1999, 1998 and 1997,
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. The average annual production
from the Beulah and Savage mines approximates 2.8 million and
300,000 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,
1999 1998 1997 1996 1995
(In thousands)
Tons sold:
Montana-Dakota generating stations 717 702 530 528 453
Jointly-owned generating stations --
Montana-Dakota's share 611 583 434 565 883
Others 1,831 1,749 1,303 1,695 2,767
Industrial and other sales 77 79 108 111 115
Total 3,236 3,113 2,375 2,899 4,218
Revenues $34,841 $35,949 $27,906 $32,696 $39,956
Knife River's lignite coal operations are subjected to
competition from coal and other 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 2000, and December 2002, respectively. See
Item 3 -- Legal Proceedings for a discussion of the resolution of
a suit and arbitration filed by the Co-owners of the Coyote
Station against Knife River and the company. In 1999, Knife River
supplied approximately 3.1 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. Knife River believes it is in
substantial compliance with those regulations.
Reserve Information --
As of December 31, 1999, the combined construction materials
operations had under ownership or lease approximately 740 million
tons of recoverable aggregate reserves.
As of December 31, 1999, Knife River had under ownership or
lease, reserves of approximately 183 million tons of recoverable
lignite coal, 91 million tons of which are at present mining
locations. Knife River estimates that approximately 46 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 November 1993, the estate of W.A. Moncrief (Moncrief), a
producer from whom Williston Basin purchased a portion of its
natural gas supply, filed suit in Federal District Court for the
District of Wyoming (Federal District Court) against Williston
Basin and the company disputing certain price and volume issues
under the contract.
Through the course of this action Moncrief submitted damage
calculations which totaled approximately $19 million or, under
its alternative pricing theory, approximately $39 million.
In June 1997, the Federal District Court issued its order
awarding Moncrief damages of approximately $15.6 million. In
July 1997, the Federal District Court issued an order limiting
Moncrief's reimbursable costs to post-judgment interest, instead
of both pre- and post-judgment interest as Moncrief had sought.
In August 1997, Moncrief filed a notice of appeal with the United
States Court of Appeals for the Tenth Circuit (U.S. Court of
Appeals) related to the Federal District Court's orders. In
September 1997, Williston Basin and the company filed a notice of
cross-appeal.
On April 20, 1999, the U.S. Court of Appeals issued its order
which affirmed in part and reversed in part the Federal District
Court's June 1997 decision. Additionally, the U.S. Court of
Appeals remanded the case to the Federal District Court for
further determination of the prices and volumes to be used for
determination of damages. The U.S. Court of Appeals also
remanded to the lower court for further consideration the issue
of whether pre-judgment interest on damages is recoverable by
Moncrief. As a result of the decision by the U.S. Court of
Appeals, the prior judgment of $15.6 million by the Federal
District Court was vacated. On December 8, 1999, a settlement
was entered into between Williston Basin and Moncrief whereby
Williston Basin paid Moncrief $3.0 million in settlement of all
claims. On December 28, 1999, the United States District Court,
District of Wyoming dismissed the case.
On February 17, 2000, the FERC issued an order which
entitles Williston Basin to recover from customers virtually all
of the costs which were incurred as a result of the settlement of
this litigation as supply realignment transition costs pursuant
to the provisions of the FERC's Order 636. Williston Basin began
collecting such amounts from customers effective February 1,
2000.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota Northwest
Judicial District Court (North Dakota District Court) against
Williston Basin and the company. Apache and Snyder are oil and
natural gas producers which had processing agreements with Koch
Hydrocarbon Company (Koch). Williston Basin and the company had
a natural gas purchase contract with Koch. Apache and Snyder
alleged they were entitled to damages for the breach of Williston
Basin's and the company's contract with Koch. Apache and Snyder
submitted damage estimates under differing theories aggregating
up to $4.8 million without interest. In November 1998, the North
Dakota District Court entered an order directing the entry of
judgment in favor of Williston Basin and the company. On March
31, 1999, judgment was entered, thereby dismissing Apache and
Snyder's claims against Williston Basin and the company. Apache
and Snyder filed a notice of appeal with the North Dakota Supreme
Court on May 17, 1999. On December 28, 1999, the North Dakota
Supreme Court affirmed the decision of the North Dakota District
Court, thereby dismissing Apache and Snyder's claims against
Williston Basin and the company.
In a related matter, in March 1997, a suit was filed by 11
other producers, several of which had unsuccessfully tried to
intervene in the Apache and Snyder litigation, against Koch,
Williston Basin and the company. The parties to this suit are
making claims similar to those in the Apache and Snyder
litigation, although no specific damages have been stated.
In Williston Basin's opinion, the claims of the 11 other
producers are without merit. If any amounts are ultimately found
to be due, Williston Basin plans to file with the FERC for
recovery from customers. However, the amount of costs that can
ultimately be recovered is subject to approval by the FERC and
market conditions.
In November 1995, a suit was filed in District Court, County
of Burleigh, State of North Dakota (State District Court) by
Minnkota Power Cooperative, Inc., Otter Tail Power Company,
Northwestern Public Service Company and Northern Municipal Power
Agency (Co-owners), the owners of an aggregate 75 percent
interest in the Coyote electric generating station (Coyote
Station), against the company (an owner of a 25 percent interest
in the Coyote Station) and Knife River. In its complaint, the Co-
owners alleged a breach of contract against Knife River with
respect to the long-term coal supply agreement (Agreement)
between the owners of the Coyote Station and Knife River. The Co-
owners requested a determination by the State District Court of
the pricing mechanism to be applied to the Agreement and further
requested damages during the term of such alleged breach on the
difference between the prices charged by Knife River and the
prices that may ultimately be determined by the State District
Court. The Co-owners also alleged a breach of fiduciary duties
by the company as operating agent of the Coyote Station,
asserting essentially that the company was unable to cause Knife
River to reduce its coal price sufficiently under the Agreement,
and the Co-owners sought damages in an unspecified amount. In
May 1996, the State District Court stayed the suit filed by the
Co-owners pending arbitration, as provided for in the Agreement.
In September 1996, the Co-owners notified the company and
Knife River of their demand for arbitration of the pricing
dispute that had arisen under the Agreement. The demand for
arbitration, filed with the American Arbitration Association
(AAA), did not make any direct claim against the company in its
capacity as operator of the Coyote Station. The Co-owners
requested that the arbitrators make a determination that the
prices charged by Knife River were excessive and that the Co-
owners be awarded damages, based upon the difference between the
prices that Knife River charged and a "fair and equitable" price.
Upon application by the company and Knife River, the AAA
administratively determined that the company was not a proper
party defendant to the arbitration, and the arbitration proceeded
against Knife River. In October 1998, a hearing before the
arbitration panel was completed. At the hearing the Co-owners
requested damages of approximately $24 million, including
interest, plus a reduction in the future price of coal under the
Agreement. During 1999, the arbitration panel issued three
Memorandum Opinions (Opinions) and held an additional hearing.
Based on its assessment of the proceedings, Knife River's
earnings in the second quarter of 1999 reflected a $3.7 million
after-tax charge regarding this matter. As a result of the
Memorandum Opinion rendered by the arbitrators in August 1999,
Knife River's 1999 third quarter earnings included a $1.9 million
after-tax charge reflecting the resolution of this matter. The
arbitration panel also revised the pricing terms of the Agreement
beginning April 1, 1999. The revised pricing terms retained the
minimum return on sales provision but at a lower guaranteed level
than the Agreement previously provided.
On January 5, 2000, the State District Court entered a
judgment agreed to by all parties that dismissed the company from
the action, confirmed the Opinions of the arbitration panel,
filed the Opinions under seal pursuant to a confidentiality
agreement among the parties, held that each party shall bear its
own costs subject to any contractual agreements to the contrary,
dismissed the November 1995 action, and confirmed that all sums
due pursuant to the arbitration have been paid and satisfied.
On June 3, 1999, several oil and gas royalty interest owners
filed suit in Colorado State District Court, in the City and
County of Denver, against WBI Production, Inc. (WBI Production),
an indirect wholly owned subsidiary of the company, and several
former producers of natural gas with respect to certain gas
production properties in the state of Colorado. The complaint
arose as a result of the purchase by WBI Production effective
January 1, 1999, of certain natural gas producing leaseholds from
the former producers. Prior to February 1, 1999, the natural gas
produced from the leaseholds was sold at above market prices
pursuant to a natural gas contract. Pursuant to the contract,
the royalty interest owners were paid royalties based upon the
above market prices. The royalty interest owners have alleged
that WBI Production took assignment of the rights to the natural
gas contract from the former owner of the contract and, with
respect to natural gas produced from such leases and sold at
market prices thereafter, wrongly ceased paying the higher
royalties on such gas.
In their complaint, the royalty interest owners have alleged,
in part, breach of oil and gas lease obligations and unjust
enrichment on the part of WBI Production and the other former
producers with respect to the amount of royalties being paid to
the royalty interest owners. The royalty interest owners have
requested damages for additional royalties and other costs,
including pre-judgment interest. No specific amount of damages
has been stated. Trial before the Colorado State District Court
has been scheduled for April 24, 2000. WBI Production intends to
vigorously contest the suit.
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
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.
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. The suit has been removed to the U.S. District
Court, District of Kansas. The defendants in this suit have
filed a motion to have the suit transferred to Wyoming and
consolidated with the Grynberg proceedings.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits.
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 1999.
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 1999 and 1998 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
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
1998
First Quarter $ 25.25 $ 18.83 $ .1917
Second Quarter 25.13 21.13 .1917
Third Quarter 28.88 22.06 .2000
Fourth Quarter 27.63 24.88 .2000
$ .7834
NOTE: Common stock share amounts reflect the company's three-for-
two common stock split effected in July 1998.
As of December 31, 1999, the company's common stock was held
by approximately 14,000 stockholders of record.
Between October 1, 1999 and December 31, 1999, the company
issued 373,111 shares of Common Stock, $1.00 par value, as part
of the consideration for all of the issued and outstanding
capital stock with respect to businesses acquired during this
period and 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, and now shareholders of
the company, are accredited investors and have acknowledged that
they would hold the company's Common Stock as an investment and
not with a view to distribution.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 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
Prior to the fourth quarter of 1999, the company reported
five operating segments consisting of electric, natural gas
distribution, natural gas transmission, construction materials
and mining, and oil and natural gas production. During the
fourth quarter of 1999, the company revised the components of the
segments reported based on organizational changes and the
significance of current segments. As a result, a utility
services segment was separated from the electric segment; gas
production activities previously included in the natural gas
transmission segment are now reflected in the oil and natural gas
production segment; and the remaining operations of the natural
gas transmission business were renamed pipeline and energy
services.
The company's operations are now conducted through six
business segments and all prior period information has been
restated to reflect this change. 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. Utility
services includes all the operations of Utility Services, Inc.
Pipeline and energy services includes WBI Holdings'
transportation, storage, gathering and energy marketing and
management services. Oil and natural gas production includes the
oil and natural gas acquisition, exploration, development 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,
1999 1998 1997
Electric $ 16.0 $ 13.9 $ 12.4
Natural gas distribution 3.2 3.5 4.5
Utility services 6.5 3.3 1.0
Pipeline and energy services 21.0 18.6 9.9
Oil and natural gas production 16.2 (30.5) 15.9
Construction materials and mining 20.4 24.5 10.1
Earnings on common stock $ 83.3 $ 33.3 $ 53.8
Earnings per common share - basic $ 1.53 $ .66 $ 1.24
Earnings per common share - diluted $ 1.52 $ .66 $ 1.24
Return on average common equity 13.9% 6.5% 14.6%
- ------------------------
NOTE: Common stock share amounts reflect the company's three-for-
two common stock split effected in July 1998.
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
oil and natural gas production business, largely resulting from
the 1998 $39.9 million in noncash after-tax write-downs of oil
and natural gas 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.
1998 compared to 1997
Consolidated earnings for 1998 decreased $20.5 million from
the comparable period a year ago due to lower earnings at the oil
and natural gas production business, largely resulting from the
aforementioned write-downs of oil and natural gas properties.
Decreased earnings at the natural gas distribution business also
added to the earnings decline. Higher earnings at all other
business segments partially offset the earnings decrease.
________________________________
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,
1999 1998 1997
Operating revenues:
Retail sales $ 130.9 $ 130.9 $ 130.3
Sales for resale and other 24.0 16.4 11.3
154.9 147.3 141.6
Operating expenses:
Fuel and purchased power 51.8 49.8 45.6
Operation and maintenance 41.6 40.1 40.5
Depreciation, depletion and
amortization 18.4 18.1 17.5
Taxes, other than income 7.4 7.1 6.7
119.2 115.1 110.3
Operating income $ 35.7 $ 32.2 $ 31.3
Retail sales (million kWh) 2,075.5 2,053.9 2,041.2
Sales for resale (million kWh) 943.5 586.5 361.9
Average cost of fuel and
purchased power per kWh $ .016 $ .017 $ .018
Natural Gas Distribution
Years ended December 31,
1999 1998 1997
Operating revenues:
Sales $ 154.1 $ 150.6 $ 153.6
Transportation and other 3.6 3.5 3.4
157.7 154.1 157.0
Operating expenses:
Purchased natural gas sold 110.2 106.5 107.2
Operation and maintenance 29.2 28.5 28.5
Depreciation, depletion and
amortization 7.4 7.1 7.0
Taxes, other than income 4.2 4.0 3.9
151.0 146.1 146.6
Operating income $ 6.7 $ 8.0 $ 10.4
Volumes (MMdk):
Sales 30.9 32.0 34.3
Transportation 11.6 10.3 10.1
Total throughput 42.5 42.3 44.4
Degree days (% of normal) 88.8% 93.7% 99.3%
Average cost of natural gas,
including transportation
thereon, per dk $ 3.56 $ 3.33 $ 3.12
Utility Services
Years ended December 31,
1999 1998 1997
Operating revenues $ 99.9 $ 64.2 $ 22.8
Operating expenses:
Operation and maintenance 82.8 54.4 19.6
Depreciation, depletion and
amortization 2.6 1.7 .3
Taxes, other than income 3.0 2.2 1.1
88.4 58.3 21.0
Operating income $ 11.5 $ 5.9 $ 1.8
Pipeline and Energy Services
Years ended December 31,
1999 1998 1997
Operating revenues:
Pipeline $ 69.6 $ 60.8 $ 60.0*
Energy services 313.9 119.9 27.1
383.5 180.7 87.1
Operating expenses:
Purchased natural gas sold 301.5 109.9 20.6
Operation and maintenance 28.2 26.3 31.9*
Depreciation, depletion and
amortization 8.2 7.0 4.8
Taxes, other than income 5.0 3.9 3.9
342.9 147.1 61.2
Operating income $ 40.6 $ 33.6 $ 25.9
Transportation volumes (MMdk):
Montana-Dakota 31.5 32.2 35.5
Other 46.6 56.8 50.0
78.1 89.0 85.5
- ------------------------
*Includes $5.5 million of amortization and related recovery of
deferred natural gas contract buy-out/buy-down and gas supply
realignment costs.
Oil and Natural Gas Production
Years ended December 31,
1999 1998 1997
Operating revenues:
Oil $ 26.9 $ 24.3 $ 36.6
Natural gas 47.9 37.6 41.2
Other 3.6 --- .1
78.4 61.9 77.9
Operating expenses:
Purchased natural gas sold 1.5 --- ---
Operation and maintenance 24.8 18.8 19.9
Depreciation, depletion and
amortization 19.2 23.3 25.1
Taxes, other than income 6.0 4.2 5.3
Write-downs of oil and
natural gas properties --- 66.0 ---
51.5 112.3 50.3
Operating income (loss) $ 26.9 $ (50.4) $ 27.6
Production:
Oil (000's of barrels) 1,758 1,912 2,088
Natural gas (MMcf) 24,652 20,699 20,407
Average prices:
Oil (per barrel) $ 15.34 $ 12.71 $ 17.50
Natural gas (per Mcf) $ 1.94 $ 1.81 $ 2.02
Construction Materials and Mining
Years ended December 31,
1999 1998 1997*
Operating revenues:
Construction materials $ 435.1 $ 310.5 $ 146.2
Coal 34.8 35.9 27.9
469.9 346.4 174.1
Operating expenses:
Operation and maintenance 402.0 280.7 145.6
Depreciation, depletion and
amortization 26.0 20.6 11.0
Taxes, other than income 3.5 3.5 2.9
431.5 304.8 159.5
Operating income $ 38.4 $ 41.6 $ 14.6
Sales (000's):
Aggregates (tons) 13,981 11,054 5,113
Asphalt (tons) 2,993 1,790 758
Ready-mixed concrete
(cubic yards) 1,186 1,021 516
Coal (tons) 3,236 3,113 2,375
- ------------------------
*Prior to August 1, 1997, financial results did not include
consolidated information related to Knife River's ownership
interest in Hawaiian Cement, 50 percent of which was acquired
in September 1995, and was accounted for under the equity
method. On July 31, 1997, Knife River acquired the 50 percent
interest in Hawaiian Cement that it did not previously own, and
subsequent to that date financial results are consolidated into
Knife River's financial statements.
Amounts presented in the preceding tables for operating
revenues, purchased natural gas sold and operation and
maintenance expenses 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 oil and natural gas
production segments. The amounts relating to the elimination
of intercompany transactions for operating revenues,
purchased natural gas sold and operation and maintenance
expenses are as follows: $64.5 million, $64.0 million and
$.5 million for 1999; $58.0 million, $57.5 million and $.5
million for 1998; and $52.8 million, $50.7 million and $2.1
million for 1997, respectively.
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 workload and higher margins.
Pipeline and Energy Services
Earnings at the pipeline and energy services business
increased largely due to a $4.4 million after-tax reserve revenue
adjustment in the second quarter associated with FERC orders
received in connection with the 1992 and 1995 rate proceedings
and a $3.9 million after-tax reserve adjustment relating to the
resolution of certain production tax and other state tax matters
in the third quarter. The recognition of $1.7 million in the
first quarter resulting from a favorable order received from the
D.C. Circuit Court relating to the 1992 general rate proceeding
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 the first quarter of 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.
Oil and Natural Gas Production
Earnings for the oil and natural gas production business
increased largely as a result of the 1998 $66.0 million ($39.9
million after tax) noncash write-downs of oil and natural gas
properties, as discussed in Note 1 of Notes to Consolidated
Financial Statements. Higher oil and natural gas 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 due largely to lower rates resulting from the write-
downs of oil and natural gas 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.
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 proceedings. For more information on the coal
contract arbitration resolution, see Item 3 -- Legal Proceedings.
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.
1998 compared to 1997
Electric
Electric earnings increased primarily due to increased
sales for resale revenue and decreased maintenance expense.
Sales for resale revenue improved due to 62 percent higher
volumes and 19 percent higher margins, both due to favorable
market conditions. Also contributing to the earnings
increase was the absence in 1998 of $1.9 million in
maintenance expenses incurred in 1997 associated with a ten-
week maintenance outage at the Coyote Station. Slightly
higher retail sales and decreased net interest expense also
contributed to the earnings improvement. Increased fuel and
purchased power costs, largely higher purchased power demand
charges resulting from the pass-through of periodic
maintenance costs, and increased operations expense due to
higher payroll and benefit-related costs, partially offset
the earnings improvement. Depreciation expense increased due
to higher average depreciable plant, also partially
offsetting the increase in earnings.
Natural Gas Distribution
Earnings decreased at the natural gas distribution business
due to reduced weather-related sales, the result of 6 percent
warmer weather. Increased average realized rates and decreased
net interest costs somewhat offset the earnings decline.
Utility Services
Earnings at utility services increased due to earnings from
businesses acquired since mid-1997.
Pipeline and Energy Services
Earnings at the pipeline and energy services business
increased due to increases in transportation revenues resulting
from a $3.1 million after-tax reversal of reserves for certain
contingencies in the first quarter of 1998 relating to a FERC
order concerning a compliance filing. Higher volumes transported
at higher average transportation rates also contributed to the
revenue increase. Gains realized on the sale of natural gas held
under the repurchase commitment and lower net interest costs also
added to the increase in earnings. The increase in energy
services revenue and the related increase in purchased natural
gas sold resulted from the acquisition of a natural gas marketing
business in July 1998.
Oil and Natural Gas Production
Earnings for the oil and natural gas production business
decreased largely as a result of $66.0 million ($39.9 million
after tax) in noncash write-downs of oil and natural gas
properties, as discussed in Note 1 of Notes to Consolidated
Financial Statements. Lower oil and natural gas revenues also
added to the decrease in earnings. The decrease in revenues
was due to realized oil and natural gas prices which were
27 percent and 10 percent lower than the prior year,
respectively, and slightly lower oil production. Decreased
depreciation, depletion and amortization due to lower
production and lower rates resulting from the aforementioned
write-downs partially offset the decrease in earnings.
Decreased operation and maintenance expenses, the result of
lower production and decreased well maintenance, and
decreased production taxes resulting from lower commodity prices,
also partially offset the earnings decline.
Construction Materials and Mining
Construction materials and mining earnings increased
primarily due to businesses acquired since mid-1997 and increased
earnings at existing construction materials operations.
Increased aggregate and asphalt sales volumes due to increased
construction activity, and lower cement and asphalt costs
contributed to the increase at the existing operations. Earnings
at the coal operations increased largely due to increased
revenues resulting from higher sales, primarily due to a 1997 ten-
week maintenance outage at the Coyote Station. Higher interest
expense resulting mainly from increased acquisition-related long-
term debt partially offset the increase in earnings.
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. 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 project schedules, 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), oil and natural gas commodity prices, drilling successes
in oil and natural gas operations, ability to acquire oil and
natural gas 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 obligations with
respect to the company's financial instruments, changes in
accounting principles and/or the application of such principles
to the company, changes in technology and legal proceedings, the
ability to effectively integrate the operations of acquired
companies, and the ability of the company and third parties,
including suppliers and vendors, to identify and address year
2000 issues in a timely manner.
Prospective Information
Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required. As franchises expire, Montana-Dakota may face
increasing competition in its service areas, particularly its
service to smaller towns, from rural electric cooperatives.
Montana-Dakota intends to protect its service area and seek
renewal of all expiring franchises and will continue to take
steps to effectively operate in an increasingly competitive
environment.
In January 2000, the company announced an agreement to
acquire Great Plains Natural Gas Company (Great Plains). Great
Plains is a natural gas distribution company serving 19
communities in western Minnesota and southeastern North Dakota.
The acquisition is currently pending approval from the Minnesota
Public Utilities Commission and the North Dakota Public Service
Commission.
Also in January 2000, the company announced that the Board of
Directors had approved the acquisition of Connolly-Pacific Co., a
southern California aggregate mining and marine construction
company. Thomas Everist, a member of the company's Board of
Directors, has an interest in L.G. Everist, Incorporated, which
has owned Connolly-Pacific Co. since 1977. In accordance with
New York Stock Exchange rules, the acquisition is subject to the
approval of the stockholders of the company. For more
information regarding this acquisition, see Item 13 -- Certain
Relationships and Related Transactions.
Year 2000 Compliance
The year 2000 issue is the result of computer programs having
been written using two digits rather than four digits to define
the applicable year. In 1997, the company established a task
force with coordinators in each of its major operating units to
address the year 2000 issue. The scope of the year 2000
readiness effort included information technology (IT) and non-IT
systems, including computer hardware, software, networking,
communications, embedded and micro-processor controlled systems,
building controls and office equipment. The company completed
its year 2000 plan in a timely manner. The plan was based on a
six-phase approach involving awareness, inventory, assessment,
remediation, testing and implementation. To date, the company
has not experienced nor is it aware of any material year 2000
related problems. The total incremental costs to the company of
the year 2000 issue were $1.3 million. These costs were funded
through cash flows from 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). In June 1999, the FASB issued Statement of
Financial Accounting Standards No. 137, "Accounting for
Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133" (SFAS No. 137), which
delayed the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. For further information on SFAS
No. 133 and SFAS No. 137, 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.
SAB No. 101 is effective for the first fiscal quarter of the
fiscal year beginning after December 15, 1999. SAB No. 101 is
not expected to 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 of dollars)
for 1997 through 1999 and as anticipated for 2000 through 2002
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*
1997 1998 1999 Capital Expenditures: 2000 2001 2002
$ 18.4 $ 13.0 $ 18.2 Electric $ 14.5 $ 14.0 $ 19.1
8.8 8.3 9.2 Natural gas distribution 10.6 10.2 7.7
9.6 18.3 16.1 Utility services 6.7 4.5 4.7
9.7 17.6 35.1 Pipeline and energy services 18.9 9.8 9.6
Oil and natural gas
34.1 100.6 64.3 production 65.5 88.1 86.6
Construction materials
41.5 172.1 105.1 and mining 57.2 40.6 27.8
122.1 329.9 248.0 173.4 167.2 155.5
Net (proceeds) payments from
sale or disposition
(4.5) (4.3) (16.6) of property (.6) (.8) .2
117.6 325.6 231.4 Net capital expenditures 172.8 166.4 155.7
Retirement of long-term
48.0 113.7 18.8 debt and preferred stock 4.4 24.7 272.4
$165.6 $439.3 $250.2 $177.2 $191.1 $428.1
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* The anticipated 2000 through 2002 capital expenditures
reflected in the above table do not include potential future
acquisitions. The company continues to seek additional growth
opportunities, including investing in the development of
related lines of business. To the extent that acquisitions
occur, the company anticipates that such acquisitions would be
financed with existing credit facilities and the issuance of
long-term debt and the company's equity securities.
Capital expenditures for 1999, 1998 and 1997, related to
acquisitions, in the above table include the following noncash
transactions: issuance of the company's equity securities in 1999
of $77.5 million; issuance of the company's equity securities,
less treasury stock acquired, in 1998 of $138.8 million; and
assumed debt and the issuance of the company's equity securities
in total for 1997 of $9.9 million.
In 1999, the company acquired a number of businesses, none of
which were individually material, including construction
materials and mining companies with operations in California,
Montana, Oregon and Wyoming and utility services companies based
in Montana and Oregon. The total purchase consideration for
these businesses, consisting of the company's common stock and
cash, was $81.9 million.
The 1999 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 2000 through 2002, excluding those
for potential acquisitions, include those for system upgrades,
routine replacements, service extensions, routine equipment
maintenance and replacements, pipeline expansion projects, the
building of construction materials handling and transportation
facilities, and the further enhancement of oil and natural gas
production and reserve growth. It is anticipated that all of the
funds required for capital expenditures and retirements of long-
term debt and preferred stock for the years 2000 through 2002
will be met from various sources. These sources include
internally generated funds, the company's $40 million revolving
credit and term loan agreement, existing lines of credit
aggregating $18.2 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,
1999, $40 million under the revolving credit and term loan
agreement and $5.9 million under the lines 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 allows for borrowings of up to $240
million. This facility supports the Centennial commercial paper
program. Under the Centennial commercial paper program, $223.2
million was outstanding at December 31, 1999. The commercial
paper borrowings are classified as long term as the company
intends to refinance these borrowings on a long term basis
through continued commercial paper borrowings supported by the
revolving credit agreement due September 1, 2002. The company
intends to renew this existing credit agreement on an annual
basis.
Effective December 27, 1999, Centennial entered into an
uncommitted long-term master shelf agreement with The Prudential
Insurance Company of America on behalf of its subsidiaries that
allows for borrowings of up to $200 million, none of which was
outstanding at December 31, 1999.
In January 2000, the company announced that its Board of
Directors approved a stock repurchase program, authorizing the
purchase of up to 1 million shares of the company's outstanding
common stock. The amount and timing of purchases will depend on
market conditions. It is anticipated that the funds required for
this program will be met from internally generated funds, the
issuance of long-term or short-term debt or other sources that
become available from time to time. Unless extended, the stock
repurchase program will be terminated on or prior to December 31,
2001.
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, 1999, the company could have
issued approximately $287 million of additional first mortgage
bonds.
The company's coverage of fixed charges including preferred
dividends was 4.3 and 2.5 times for 1999 and 1998, respectively.
Additionally, the company's first mortgage bond interest coverage
was 7.1 times in 1999 compared to 6.1 times in 1998. Common
stockholders' equity as a percent of total capitalization was 54
percent and 56 percent at December 31, 1999 and 1998,
respectively.
Effects of Inflation
Inflation did not have a significant effect on the company's
operations in 1999, 1998 or 1997.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk --
From time to time, the company utilizes derivative financial
instruments, including price swap and collar agreements and
natural gas futures, to manage a portion of the market risk
associated with fluctuations in the price of oil and natural gas.
The company's policy prohibits the use of derivative instruments
for trading purposes 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 an oil
price quoted on the New York Mercantile Exchange (NYMEX) or a
quoted natural gas price on the NYMEX, Colorado Interstate Gas
Index or Williams Gas Index. 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. Gains or losses on futures contracts are deferred
until the commodity transaction occurs.
The following table summarizes hedge agreements entered into
by Fidelity Oil Co. and WBI Production, Inc., indirect wholly
owned subsidiaries of the company, as of December 31, 1999.
These agreements call for Fidelity Oil Co. and WBI Production,
Inc. to receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
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 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
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreement
maturing in 2000 $20.00/$22.33 183 $ (134)
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
At December 31, 1998, Fidelity Oil Co. had natural gas collar
agreements outstanding for 2.9 million MMBtu's of natural gas
with a weighted average floor price and ceiling price of $2.10
and $2.51, respectively. The company's net favorable position on
the natural gas collar agreements outstanding at December 31,
1998, was $597,000. These agreements call for Fidelity Oil Co.
to receive fixed prices and pay variable prices.
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. 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.
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 16,000 shares of 5.10% Series preferred
stock subject to mandatory redemption as of December 31, 1999.
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, 1999. Weighted average variable rates
are based on forward rates as of December 31, 1999.
Fair
2000 2001 2002 2003 2004 Thereafter Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $4.3 $24.6 $ 49.6 $ 6.6 $21.6 $238.5 $345.2 $331.6
Weighted average
interest rate 7.4% 7.5% 8.2% 6.9% 6.6% 7.4% 7.4% ---
Variable rate --- --- $222.7 --- --- --- $222.7 $224.1
Weighted average
interest rate --- --- 6.8% --- --- --- 6.8% ---
Preferred stock
subject to mandatory
redemption $ .1 $ .1 $ .1 $ .1 $ .1 $ 1.1 $ 1.6 $ 1.4
Dividend rate 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% ---
For further information on derivatives and other financial
instruments, see Note 3 of Notes to Consolidated Financial
Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 27 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 3 through 8 and 43 and 44 of the
company's Proxy Statement dated March 10, 2000 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 38 through 43 of the Proxy
Statement, with the exception of the compensation committee
report on executive compensation and the MDU Resources Group,
Inc. comparison of five year total stockholder return, which is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 45 of the Proxy Statement which is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In January 2000, the company announced that the Board of
Directors had approved the acquisition of Connolly-Pacific Co., a
southern California aggregate mining and marine construction
company, from the shareholders of Connolly-Pacific Co., including
L.G. Everist, Incorporated. The company will acquire all of the
outstanding capital stock of Connolly-Pacific Co. in exchange for
2,826,087 shares of common stock of the company, having a value
of $57,765,218 based on the $20.44 per share closing price of the
company's common stock on January 24, 2000, the date on which the
acquisition agreement was signed. The consideration paid by the
company for Connolly-Pacific Co. is subject to adjustment after
the closing of the acquisition based on Connolly-Pacific Co.'s
working capital on the closing date. Because of the restrictions
on transfer by L.G. Everist, Incorporated, of the shares of the
company's common stock that it receives as a result of the
acquisition, the value of those shares may, for financial
accounting purposes, be discounted. In accordance with New York
Stock Exchange rules, the acquisition is subject to the approval
of the stockholders of the company. Stockholder approval will be
requested at the MDU Resources Annual Stockholders' Meeting,
which is scheduled for April 25, 2000.
Thomas Everist, a member of the company's Board of Directors,
has an interest in L.G. Everist, Incorporated, which has owned
Connolly-Pacific Co. since 1977. Thomas Everist is President and
Director, and owns 50% of the outstanding voting stock, and 26.5%
of the total outstanding equity, of L.G. Everist, Incorporated,
which owns 96.5% of the capital stock of Connolly-Pacific Co.
Members of Thomas Everist's family and trusts for their benefit
own or control the remaining 50% of the outstanding voting stock,
and the remaining 73.5% of the total outstanding equity, of L.G.
Everist, Incorporated.
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, 1999 *
Consolidated Balance Sheets at December 31,
1999 and 1998 *
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 1999 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1999 *
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 1999 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 1999 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-Eighth 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 *
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) Key Employee Stock Option Plan, as amended
to date, filed as Exhibit 10(a) to
Form 10-Q for the quarter ended March 31,
1999 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(d) to Form
10-K for the year ended December 31, 1998,
in File No. 1-3480 *
+ 10(e) Deferred Compensation Plan for Directors,
as amended to date, filed as Exhibit 10(e)
to Form 10-K for the year ended December 31,
1998, 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(g) to Form 10-K for the year
ended December 31, 1998, in File No. 1-3480 *
+ 10(h) 1997 Executive Long-Term Incentive Plan,
as amended to date, filed as Exhibit 10(h)
to Form 10-K for the year ended December 31,
1998, in File No. 1-3480 *
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 1999 **
21 Subsidiaries of MDU Resources Group, Inc. **
23 Consent of Independent Public Accountants **
27 Financial Data Schedule **
- ------------------------
* 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 February 11, 2000. Under Item 5 --
Other Events, the company announced that its Board of Directors
authorized the repurchase of up to 1 million shares of the
company's outstanding common stock.
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 3, 2000 By: /s/ Martin A. White
Martin A. White (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 3, 2000
Martin A. White Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief March 3, 2000
Douglas C. Kane (Executive Vice President, Administrative &
Chief Administrative & Corporate Corporate
Development Officer) Development Officer
and Director
/s/ Warren L. Robinson Chief Financial March 3, 2000
Warren L. Robinson (Executive Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting March 3, 2000
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director March 3, 2000
John A. Schuchart (Chairman of the Board)
/s/ San W. Orr, Jr. Director March 3, 2000
San W. Orr, Jr. (Vice Chairman of the Board)
/s/ Thomas Everist Director March 3, 2000
Thomas Everist
/s/ Richard L. Muus Director March 3, 2000
Richard L. Muus
/s/ Robert L. Nance Director March 3, 2000
Robert L. Nance
/s/ John L. Olson Director March 3, 2000
John L. Olson
Director
Harry J. Pearce
/s/ Homer A. Scott, Jr. Director March 3, 2000
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director March 3, 2000
Joseph T. Simmons
/s/ Sister Thomas Welder Director March 3, 2000
Sister Thomas Welder
EXHIBIT INDEX
Exhibit No.
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-Eighth 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 *
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) Key Employee Stock Option Plan, as amended
to date, filed as Exhibit 10(a) to
Form 10-Q for the quarter ended March 31,
1999 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(d) to Form
10-K for the year ended December 31, 1998,
in File No. 1-3480 *
+ 10(e) Deferred Compensation Plan for Directors,
as amended to date, filed as Exhibit 10(e)
to Form 10-K for the year ended December 31,
1998, 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(g) to Form 10-K for the year
ended December 31, 1998, in File No. 1-3480 *
+ 10(h) 1997 Executive Long-Term Incentive Plan,
as amended to date, filed as Exhibit 10(h)
to Form 10-K for the year ended December 31,
1998, in File No. 1-3480 *
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 1999 **
21 Subsidiaries of MDU Resources Group, Inc. **
23 Consent of Independent Public Accountants **
27 Financial Data Schedule **
- ------------------------
* 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.