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.
MDU RESOURCES GROUP, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Years Ended December 31,
1999 1998 1997 1996 1995
(In thousands of dollars)
Earnings Available for
Fixed Charges:
Net Income per
Consolidated
Statements of
Income $ 84,080 $ 34,107 $ 54,617 $ 45,470 $ 41,633
Income Taxes 49,310 17,485 30,743 16,087 23,057
133,390 51,592 85,360 61,557 64,690
Rents (a) 2,018 1,749 1,249 1,031 894
Interest (b) 36,539 31,587 33,047 34,101 29,924
Total Earnings
Available for
Fixed Charges $171,947 $ 84,928 $119,656 $ 96,689 $ 95,508
Preferred Dividend
Requirements $ 772 $ 777 $ 782 $ 787 $ 792
Ratio of Income
Before Income
Taxes to Net
Income 159% 151% 156% 135% 155%
Preferred Dividend
Factor on Pretax
Basis 1,227 1,173 1,220 1,062 1,228
Fixed Charges (c) 38,557 33,336 34,296 35,132 30,818
Combined Fixed
Charges and
Preferred Stock
Dividends $ 39,784 $ 34,509 $ 35,516 $ 36,194 $ 32,046
Ratio of Earnings
to Fixed Charges 4.5x 2.5x 3.5x 2.8x 3.1x
Ratio of Earnings
to Combined
Fixed Charges
and Preferred
Stock Dividends 4.3x 2.5x 3.4x 2.7x 3.0x
(a) Represents portion (33 1/3%) of rents which is estimated to
approximately constitute the return to the lessors on their
investment in leased premises.
(b) Represents interest and amortization of debt discount and expense
on all indebtedness and excludes amortization of gains or losses
on reacquired debt which, under the Uniform System of Accounts, is
classified as a reduction of, or increase in, interest expense in
the Consolidated Statements of Income. Also includes carrying
costs associated with natural gas available under a repurchase
agreement with Frontier Gas Storage Company. In May 1999, the
company purchased the remaining natural gas subject to the
repurchase commitment thereby extinguishing the repurchase
commitment.
(c) Represents rents and interest, both as defined above.
MDU RESOURCES GROUP, INC.
Report of Management
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with generally accepted accounting principles as applied to
the company's regulated and nonregulated businesses and necessarily
include some amounts that are based on informed judgments and estimates
of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis, that
transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an organizational
structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Auditing Department. In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct. Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions. The company's
Internal Auditing Department is charged with the responsibility for
determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Arthur Andersen LLP have full and free access to the audit
committee, without management present, to discuss auditing, internal
accounting control and financial reporting matters.
Arthur Andersen LLP is engaged to express an opinion on the financial
statements. Their audit is conducted in accordance with generally
accepted auditing standards and includes examining, on a test basis,
supporting evidence, assessing the company's accounting principles used
and significant estimates made by management and evaluating the overall
financial statement presentation to the extent necessary to allow them
to report on the fairness, in all material respects, of the financial
condition and operating results of the company.
Martin A. White Warren L. Robinson
President and Chief Executive Vice President,
Executive Officer Treasurer and Chief
Financial Officer
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1999 1998 1997
(In thousands, except per share amounts)
Operating revenues $1,279,809 $896,627 $607,674
Operating expenses:
Fuel and purchased power 51,802 49,829 45,604
Purchased natural gas sold 349,215 158,908 77,082
Operation and maintenance 608,104 448,290 283,894
Depreciation, depletion and
amortization 81,818 77,786 65,767
Taxes, other than income 29,119 24,871 23,766
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
1,120,058 825,684 496,113
Operating income 159,751 70,943 111,561
Other income -- net 9,645 10,922 4,008
Interest expense 36,006 30,273 30,209
Income before income taxes 133,390 51,592 85,360
Income taxes 49,310 17,485 30,743
Net income 84,080 34,107 54,617
Dividends on preferred stocks 772 777 782
Earnings on common stock $ 83,308 $ 33,330 $ 53,835
Earnings per common share--basic $ 1.53 $ .66 $ 1.24
Earnings per common share--diluted $ 1.52 $ .66 $ 1.24
Dividends per common share $ .82 $ .7834 $ .7534
Weighted average common shares
outstanding -- basic 54,615 50,536 43,315
Weighted average common shares
outstanding -- diluted 54,870 50,837 43,478
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1999 1998
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 77,504 $ 39,216
Receivables 169,560 124,114
Inventories 64,608 44,865
Deferred income taxes 15,600 16,918
Prepayments and other current assets 24,424 15,536
351,696 240,649
Investments 43,128 43,029
Property, plant and equipment 2,042,281 1,810,800
Less accumulated depreciation,
depletion and amortization 794,105 726,123
1,248,176 1,084,677
Deferred charges and other assets 123,303 84,420
$1,766,303 $1,452,775
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 14,693 $ 15,000
Long-term debt and preferred
stock due within one year 4,428 3,292
Accounts payable 81,262 60,023
Taxes payable 6,842 9,226
Dividends payable 12,171 10,799
Other accrued liabilities,
including reserved revenues 67,931 71,129
187,327 169,469
Long-term debt (Note 5) 563,545 413,264
Deferred credits and other liabilities:
Deferred income taxes 213,771 173,094
Other liabilities 115,627 129,506
329,398 302,600
Preferred stock subject to mandatory
redemption (Note 6) 1,500 1,600
Commitments and contingencies (Notes 11, 14 and 15)
Stockholders' equity:
Preferred stocks (Note 6) 15,000 15,000
Common stockholders' equity:
Common stock (Note 7)
Authorized -- 150,000,000 shares,
$1.00 par value in 1999,
75,000,000 shares,
$3.33 par value in 1998
Issued -- 57,277,915 shares in 1999 and
53,272,951 shares in 1998 57,278 177,399
Other paid-in capital 372,312 171,486
Retained earnings 243,569 205,583
Treasury stock at cost - 239,521 shares (3,626) (3,626)
Total common stockholders' equity 669,533 550,842
Total stockholders' equity 684,533 565,842
$1,766,303 $1,452,775
The accompanying notes are an integral part of these consolidated
statements.
<TABLE>
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
MDU RESOURCES GROUP, INC.
<CAPTION>
Years ended December 31, 1999, 1998 and 1997
Other
Common Stock Paid-in Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total
(In thousands, except shares)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at
December 31, 1996 28,476,981 $ 94,828 $ 64,305 $ 191,541 --- $ --- $350,674
Net income --- --- --- 54,617 --- --- 54,617
Dividends on
preferred stocks --- --- --- (782) --- --- (782)
Dividends on
common stock --- --- --- (32,653) --- --- (32,653)
Issuance of common
stock:
Acquisitions 225,629 751 3,622 --- --- --- 4,373
Other 440,722 1,468 8,599 --- --- --- 10,067
Balance at
December 31, 1997 29,143,332 97,047 76,526 212,723 --- --- 386,296
Net income --- --- --- 34,107 --- --- 34,107
Dividends on
preferred stocks --- --- --- (777) --- --- (777)
Dividends on
common stock --- --- --- (40,470) --- --- (40,470)
Issuance of
common stock:
Acquisitions
(pre-split) 4,973,629 16,562 112,353 --- --- --- 128,915
Other
(pre-split) 869,068 2,894 26,900 --- --- --- 29,794
Treasury stock
acquired --- --- --- --- (159,681) (3,626) (3,626)
Three-for-two
common stock
split (Note 7) 17,493,014 58,252 (58,252) --- (79,840) --- ---
Issuance of common
stock:
Acquisitions
(post-split) 672,863 2,241 11,234 --- --- --- 13,475
Other
(post-split) 121,045 403 2,725 --- --- --- 3,128
Balance at
December 31, 1998 53,272,951 177,399 171,486 205,583 (239,521) (3,626) 550,842
Net income --- --- --- 84,080 --- --- 84,080
Dividends on
preferred stocks --- --- --- (772) --- --- (772)
Dividends on
common stock --- --- --- (45,322) --- --- (45,322)
Reduction in par
value of common
stock --- (124,126) 124,126 --- --- --- ---
Issuance of
common stock:
Acquisitions 3,882,390 3,882 73,639 --- --- --- 77,521
Other 122,574 123 3,061 --- --- --- 3,184
Balance at
December 31, 1999 57,277,915 $ 57,278 $ 372,312 $243,569 (239,521) $(3,626) $669,533
<FN>
The accompanying notes are an integral part of these consolidated statements.
</FN>
</TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1999 1998 1997
(In thousands)
Operating activities:
Net income $ 84,080 $ 34,107 $ 54,617
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 81,818 77,786 65,767
Deferred income taxes and
investment tax credit 15,704 (17,256) 12,894
Recovery of deferred natural gas
contract litigation settlement
costs --- --- 5,486
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
Changes in current assets and
liabilities:
Receivables (12,310) (10,464) 6,951
Inventories (13,460) 1,718 (4,214)
Other current assets (4,190) (547) 2,026
Accounts payable 12,492 14,094 (5,605)
Other current liabilities (8,972) (19,805) (6,087)
Other noncurrent changes (289) (7,187) 6,794
Net cash provided by operating
activities 154,873 138,446 138,629
Financing activities:
Net change in short-term borrowings (6,585) 3,933 (5,919)
Issuance of long-term debt 154,546 209,890 54,064
Repayment of long-term debt (18,714) (113,600) (47,899)
Retirement of preferred stocks (100) (100) (100)
Issuance of common stock 3,184 32,922 10,067
Retirement of natural gas
repurchase commitment (14,296) (17,105) (52,090)
Dividends paid (46,094) (41,247) (33,435)
Net cash provided by (used in)
financing activities 71,941 74,693 (75,312)
Investing activities:
Capital expenditures including
acquisitions of businesses (170,510) (191,154) (112,224)
Net proceeds from sale or
disposition of property 16,660 4,275 4,522
Net capital expenditures (153,850) (186,879) (107,702)
Sale of natural gas available
under repurchase commitment 1,330 7,727 27,008
Investments (99) (22,945) (2,248)
Additions to notes receivable (35,907) --- ---
Net cash used in investing
activities (188,526) (202,097) (82,942)
Increase (decrease) in cash
and cash equivalents 38,288 11,042 (19,625)
Cash and cash equivalents --
beginning of year 39,216 28,174 47,799
Cash and cash equivalents --
end of year $ 77,504 $ 39,216 $ 28,174
The accompanying notes are an integral part of these consolidated statements.
NOTE 1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The consolidated financial statements of MDU Resources Group, Inc. and
its subsidiaries (company) include the accounts of the following
segments: electric, natural gas distribution, utility services,
pipeline and energy services, oil and natural gas production, and
construction materials and mining. The electric and natural gas
distribution segments and a portion of the pipeline and energy services
segment are regulated. The company's nonregulated operations include
the utility services, oil and natural gas production, and construction
materials and mining segments, and a portion of the pipeline and energy
services segment. For further descriptions of the company's business
segments see Note 9. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned
electric generation stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the company's
nonregulated businesses.
The company's regulated businesses account for certain income and
expense items under the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Regulation" (SFAS No.
71). SFAS No. 71 allows these businesses to defer as regulatory assets
or liabilities certain items that would have otherwise been reflected
as expense or income, respectively, based on the expected regulatory
treatment in future rates. The expected recovery or flowback of these
deferred items are generally based on specific ratemaking decisions or
precedent for each item. Regulatory assets and liabilities are being
amortized consistently with the regulatory treatment established by the
FERC and the applicable state public service commissions. See Note 2
for more information regarding the nature and amounts of these
regulatory deferrals.
In accordance with the provisions of SFAS No. 71, intercompany coal
sales, which are made at prices approximately the same as those charged
to others, and the related utility fuel purchases are not eliminated.
All other significant intercompany balances and transactions have been
eliminated.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost when
first placed in service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost and cost of removal, less salvage, is charged to accumulated
depreciation. With respect to the retirement or disposal of all other
assets, except for oil and natural gas production properties as
described below, the resulting gains or losses are recognized as a
component of income. The company is permitted to capitalize an
allowance for funds used during construction (AFUDC) on regulated
construction projects and to include such amounts in rate base when the
related facilities are placed in service. In addition, the company
capitalizes interest, when applicable, on certain construction projects
associated with its other operations. The amount of AFUDC and interest
capitalized was $1.7 million, $1.4 million and $970,000 in 1999, 1998
and 1997, respectively. Property, plant and equipment are depreciated
on a straight-line basis over the average useful lives of the assets,
except for oil and natural gas production properties as described
below.
In accordance with the provisions of Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," the company reviews the
carrying values of its long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be
recoverable. As yet, no asset or group of assets has been identified
for which the sum of expected future cash flows (undiscounted and
without interest charges) is less than the carrying amount of the
asset(s) and, accordingly, no impairment losses have been recorded.
However, currently unforeseen events and changes in circumstances could
require the recognition of impairment losses at some future date.
Oil and natural gas
The company uses the full-cost method of accounting for its oil and
natural gas production activities. Under this method, all costs
incurred in the acquisition, exploration and development of oil and
natural gas properties are capitalized and amortized on the units of
production method based on total proved reserves. Any conveyances of
properties, including gains or losses on abandonments of properties,
are treated as adjustments to the cost of the properties with no gain
or loss recognized. Capitalized costs are subject to a "ceiling test"
that limits such costs to the aggregate of the present value of future
net revenues of proved reserves and the lower of cost or fair value of
unproved properties. Future net revenue is estimated based on end-of-
quarter prices adjusted for contracted price changes. If capitalized
costs exceed the full-cost ceiling at the end of any quarter, a
permanent noncash write-down is required to be charged to earnings in
that quarter.
Due to low oil and natural gas prices, the company's capitalized costs
under the full-cost method of accounting exceeded the full-cost ceiling
at June 30, 1998 and December 31, 1998. Accordingly, the company was
required to write down its oil and natural gas producing properties.
These noncash write-downs amounted to $33.1 million ($20.0 million
after tax) and $32.9 million ($19.9 million after tax) for the quarters
ended June 30, 1998 and December 31, 1998, respectively.
Natural gas in underground storage
Natural gas in underground storage for the company's regulated
operations is carried at cost using the last-in, first-out method. The
portion of the cost of natural gas in underground storage expected to
be used within one year is included in inventories and amounted to
$26.1 million and $11.5 million at December 31, 1999 and 1998,
respectively. The remainder of natural gas in underground storage is
included in property, plant and equipment and was $46.8 million and
$43.7 million at December 31, 1999 and 1998, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
company's regulated operations, consist primarily of materials and
supplies and inventories held for resale. These inventories are stated
at the lower of average cost or market.
Revenue recognition
The company recognizes utility revenue each month based on the services
provided to all utility customers during the month. For its
construction businesses, the company recognizes construction contract
revenue on the percentage of completion method. The company generally
recognizes all other revenues when services are rendered or goods are
delivered.
Natural gas costs recoverable through rate adjustments
Under the terms of certain orders of the applicable state public
service commissions, the company is deferring natural gas commodity,
transportation and storage costs which are greater or less than amounts
presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or
refundable through rate adjustments within 24 months from the time such
costs are paid.
Income taxes
The company provides deferred federal and state income taxes on all
temporary differences. Excess deferred income tax balances associated
with the company's rate-regulated activities resulting from the
company's adoption of SFAS No. 109, "Accounting for Income Taxes," have
been recorded as a regulatory liability and are included in "Other
liabilities" in the company's Consolidated Balance Sheets. These
regulatory liabilities are expected to be reflected as a reduction in
future rates charged customers in accordance with applicable regulatory
procedures.
The company uses the deferral method of accounting for investment tax
credits and amortizes the credits on electric and natural gas
distribution plant over various periods which conform to the ratemaking
treatment prescribed by the applicable state public service
commissions.
Earnings per common share
Basic earnings per common share were computed by dividing earnings on
common stock by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share were
computed by dividing earnings on common stock by the total of the
weighted average number of shares of common stock outstanding during
the year, plus the effect of outstanding stock options. Common stock
outstanding includes issued shares less shares held in treasury.
Earnings per common share reflect the three-for-two common stock split
effected in July 1998 as discussed in Note 7.
Comprehensive income
For the years ended December 31, 1999, 1998 and 1997, comprehensive
income equaled net income as reported.
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the company to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Estimates are used for such
items as property depreciable lives, tax provisions, uncollectible
accounts, environmental and other loss contingencies, accumulated
provision for revenues subject to refund, unbilled revenues and
actuarially determined benefit costs. As better information becomes
available, or actual amounts are determinable, the recorded estimates
are revised. Consequently, operating results can be affected by
revisions to prior accounting estimates.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 1999 1998 1997
(In thousands)
Interest, net of amount capitalized $30,772 $26,394 $25,626
Income taxes $32,723 $34,498 $18,171
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Reclassifications
Certain reclassifications have been made in the financial statements
for prior years to conform to the current presentation. Such
reclassifications had no effect on net income or common stockholders'
equity as previously reported.
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). SFAS
No. 133 establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either
an asset or liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset the related results on the hedged item in
the income statement, and requires that a company must formally
document, designate and assess the effectiveness of transactions that
receive hedge accounting treatment.
In 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," which delayed the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. The company will adopt SFAS No. 133 on
January 1, 2001. The company continues to evaluate the effect of
adopting SFAS No. 133 but has not yet determined what impact this
adoption will have on the company's financial position or results of
operations.
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.
NOTE 2
REGULATORY ASSETS AND LIABILITIES
The following table summarizes the individual components of unamortized
regulatory assets and liabilities included in the accompanying
Consolidated Balance Sheets as of December 31:
1999 1998
(In thousands)
Regulatory assets:
Long-term debt refinancing costs $ 9,514 $ 10,995
Deferred income taxes 7,274 13,364
Natural gas contract settlement and
restructuring costs 3,000 ---
Postretirement benefit costs 1,742 2,036
Plant costs 2,835 3,004
Other 6,789 6,063
Total regulatory assets 31,154 35,462
Regulatory liabilities:
Reserves for regulatory matters 24,231 39,981
Taxes refundable to customers 11,504 14,130
Plant decommissioning costs 6,989 6,413
Deferred income taxes 6,785 7,047
Natural gas costs refundable
through rate adjustments 2,579 274
Other 710 157
Total regulatory liabilities 52,798 68,002
Net regulatory position $(21,644) $ (32,540)
As of December 31, 1999, substantially all of the company's regulatory
assets are being reflected in rates charged to customers and are being
recovered over the next 1 to 17 years.
If, for any reason, the company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 3
FINANCIAL INSTRUMENTS
Derivatives
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. Amounts payable or receivable on the swap and collar
agreements are matched and reported in operating revenues on the
Consolidated Statements of Income as a component of the related
commodity transaction at the time of settlement with the counterparty.
Gains or losses on futures contracts are deferred until the underlying
commodity transaction occurs, at which point they are reported in
"Purchased natural gas sold" on the Consolidated Statements of Income.
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 Fair
(Per barrel) (In barrels) Value
Oil swap agreements
maturing in 2000 $19.55 769 $(1,870)
Weighted
Average Notional
Fixed Price Amount Fair
(Per MMBtu) (In MMBtu's) Value
Natural gas swap
agreements maturing
in 2000 $2.33 5,307 $ 597
Weighted
Average
Floor/Ceiling Notional
Price Amount Fair
(Per barrel) (In barrels) Value
Oil collar agreement
maturing in 2000 $20.00/$22.33 183 $ (134)
Weighted
Average
Floor/Ceiling Notional
Price Amount Fair
(Per MMBtu) (In MMBtu's) 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. The
favorable or unfavorable position is currently not recorded on the
company's financial statements. Favorable and unfavorable positions
related to commodity hedge agreements are expected to be generally
offset by corresponding increases and decreases in the value of the
underlying commodity transactions.
In the event a derivative financial instrument does not qualify for
hedge accounting or when the underlying commodity transaction matures,
is sold, is extinguished, or is terminated, the current favorable or
unfavorable position on the open contract would be included in results
of operations. The company's policy requires approval to terminate a
hedge agreement prior to its original maturity. In the event a hedge
agreement is terminated, the realized gain or loss at the time of
termination would be deferred until the underlying commodity
transaction is sold or matures and is expected to generally offset the
corresponding increases or decreases in the value of the underlying
commodity transaction.
Fair value of other financial instruments
The estimated fair value of the company's long-term debt and preferred
stock subject to mandatory redemption is based on quoted market prices
of the same or similar issues. The estimated fair value of the
company's long-term debt and preferred stock subject to mandatory
redemption at December 31 is as follows:
1999 1998
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $567,873 $555,730 $416,456 $435,078
Preferred stock
subject to mandatory
redemption $ 1,600 $ 1,418 $ 1,700 $ 1,592
The fair value of other financial instruments for which estimated fair
value has not been presented is not materially different than the
related carrying amount.
NOTE 4
SHORT-TERM BORROWINGS
The company and its subsidiaries had unsecured short-term lines of
credit from a number of banks totaling $81.9 million at December 31,
1999. These line of credit agreements provide for bank borrowings
against the lines and/or support for commercial paper issues. The
agreements provide for commitment fees at varying rates. Amounts
outstanding on the short-term lines of credit were $14.7 million at
December 31, 1999, and $15 million at December 31, 1998. The weighted
average interest rate for borrowings outstanding at December 31, 1999
and 1998, was 6.97 percent and 5.45 percent, respectively. The unused
portions of the lines of credit are subject to withdrawal based on the
occurrence of certain events.
NOTE 5
LONG-TERM DEBT AND INDENTURE PROVISIONS
Long-term debt outstanding at December 31 is as follows:
1999 1998
(In thousands)
First mortgage bonds and notes:
Pollution Control Refunding Revenue
Bonds, Series 1992,
6.65%, due June 1, 2022 $ 20,850 $ 20,850
Secured Medium-Term Notes,
Series A at a weighted
average rate of 7.59%, due on
dates ranging from October 1, 2004
to April 1, 2012 110,000 110,000
Total first mortgage bonds and notes 130,850 130,850
Pollution control note obligation,
6.20%, due March 1, 2004 3,100 3,400
Senior notes at a weighted
average rate of 7.19%, due on
dates ranging from December 31, 2000
to October 30, 2018 151,400 141,000
Commercial paper at a weighted average
rate of 6.80%, supported by a revolving
credit agreement due on September 1, 2002 223,169 82,921
Revolving lines of credit at a
weighted average rate of 8.37%,
due on dates ranging from
November 1, 2001 through December 31, 2002 45,900 45,200
Term credit agreements at a weighted
average rate of 7.52%, due on dates
ranging from January 1, 2000
through November 25, 2012 13,970 13,211
Other (516) (126)
Total long-term debt 567,873 416,456
Less current maturities 4,328 3,192
Net long-term debt $ 563,545 $413,264
Centennial Energy Holdings, Inc., 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
and $82.9 million were outstanding at December 31, 1999 and 1998,
respectively. 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.
Under the revolving lines of credit, the company and certain
subsidiaries have $58.2 million available as of December 31, 1999.
Amounts outstanding under the revolving lines of credit were
$45.9 million and $45.2 million at December 31, 1999 and 1998,
respectively.
The amounts of scheduled long-term debt maturities for the five years
following December 31, 1999 aggregate $4.3 million in 2000;
$24.6 million in 2001; $272.3 million in 2002; $6.6 million in 2003 and
$21.6 million in 2004.
Substantially all of the company's electric and natural gas
distribution properties, with certain exceptions, are subject to the
lien of its Indenture of Mortgage. Under the terms and conditions of
the Indenture, the company could have issued approximately $287 million
of additional first mortgage bonds at December 31, 1999. Certain other
debt instruments of the company and its subsidiaries contain
restrictive covenants, all of which the company and its subsidiaries
are in compliance with at December 31, 1999.
NOTE 6
PREFERRED STOCKS
Preferred stocks at December 31 are as follows:
1999 1998
(Dollars in thousands)
Authorized:
Preferred --
500,000 shares, cumulative,
par value $100, issuable in series
Preferred stock A --
1,000,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Preference --
500,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Outstanding:
Subject to mandatory redemption --
Preferred --
5.10% Series -- 16,000 shares in 1999
and 17,000 shares in 1998 $ 1,600 $ 1,700
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000
15,000 15,000
Total preferred stocks 16,600 16,700
Less sinking fund requirements 100 100
Net preferred stocks $16,500 $16,600
The preferred stocks outstanding are subject to redemption, in whole or
in part, at the option of the company with certain limitations on 30
days notice on any quarterly dividend date.
The company is obligated to make annual sinking fund contributions to
retire the 5.10% Series preferred stock. The redemption prices and
sinking fund requirements, where applicable, are summarized below:
Redemption Sinking Fund
Series Price (a) Shares Price (a)
Preferred stocks:
4.50% $105 (b) --- ---
4.70% $102 (b) --- ---
5.10% $102 1,000 (c) $100
(a) Plus accrued dividends.
(b) These series are redeemable at the sole discretion of the company.
(c) Annually on December 1, if tendered.
In the event of a voluntary or involuntary liquidation, all preferred
stock series holders are entitled to $100 per share, plus accrued
dividends.
The aggregate annual sinking fund amount applicable to preferred stock
subject to mandatory redemption for each of the five years following
December 31, 1999, is $100,000.
NOTE 7
COMMON STOCK
At the Annual Meeting of Stockholders held on April 27, 1999, the
company's common stockholders approved an amendment to the Certificate
of Incorporation increasing the authorized number of common shares from
75 million shares to 150 million shares and reducing the par value of
the common stock from $3.33 per share to $1.00 per share.
In May 1998, the company's Board of Directors approved a three-for-two
common stock split effected in the form of a 50 percent common stock
dividend. The additional shares of common stock were distributed on
July 13, 1998, to common stockholders of record on July 3, 1998.
Common stock information appearing in the accompanying Consolidated
Statements of Income and Notes to Consolidated Financial Statements
give retroactive effect to the stock split.
The company's Automatic Dividend Reinvestment and Stock Purchase Plan
(DRIP) provides participants in the DRIP the opportunity to invest all
or a portion of their cash dividends in shares of the company's common
stock and to make optional cash payments of up to $5,000 per month for
the same purpose. Holders of all classes of the company's capital
stock, legal residents in any of the 50 states, and beneficial owners,
whose shares are held by brokers or other nominees through
participation by their brokers or nominees, are eligible to participate
in the DRIP. The company's Tax Deferred Compensation Savings Plan(s)
(K-Plan(s)), which were merged effective January 1, 1999, pursuant to
Section 401(k) of the Internal Revenue Code are funded with the
company's common stock. Since January 1, 1989, the DRIP and K-Plan(s)
have been funded primarily by the purchase of shares of common stock on
the open market, except for a portion of 1997 where shares of
authorized but unissued common stock were used to fund the DRIP and
K-Plan(s) and from October 1, 1998 through March 31, 1999, when shares
of authorized but unissued common stock were used to fund the DRIP. At
December 31, 1999, there were 8.1 million shares of common stock
reserved for original issuance under the DRIP and K-Plan.
In November 1998, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) for each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-thousandth of a share of Series B
Preference Stock of the company, without par value, at an exercise
price of $125 per one one-thousandth, subject to certain adjustments.
The rights are currently not exercisable and will be exercisable only
if a person or group (acquiring person) either acquires ownership of 15
percent or more of the company's common stock or commences a tender or
exchange offer that would result in ownership of 15 percent or more.
In the event the company is acquired in a merger or other business
combination transaction or 50 percent or more of its consolidated
assets or earnings power are sold, each right entitles the holder to
receive, upon the exercise thereof at the then current exercise price
of the right multiplied by the number of one one-thousandth of a Series
B Preference Stock for which a right is then exercisable, in accordance
with the terms of the rights agreement, such number of shares of common
stock of the acquiring person having a market value of twice the then
current exercise price of the right. The rights, which expire on
December 31, 2008, are redeemable in whole, but not in part, for a
price of $.01 per right, at the company's option at any time until any
acquiring person has acquired 15 percent or more of the company's
common stock.
The company has stock option plans for directors, key employees and
employees, which grant options to purchase shares of the company's
stock. The company accounts for these option plans in accordance with
APB Opinion No. 25 under which no compensation expense has been
recognized. The option exercise price is the market value of the stock
on the date of grant. Options granted to the key employees
automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance
goals or upon a change in control of the company. Options granted to
directors and employees vest at date of grant and three years after
date of grant, respectively, and expire ten years after the date of
grant. Under the stock option plans, the company is authorized to grant
options for up to 4.3 million shares of common stock and has granted
options on 1.9 million shares through December 31, 1999.
Had the company recorded compensation expense for the fair value of
options granted consistent with SFAS No. 123, "Accounting for Stock-
Based Compensation" (SFAS No. 123), net income would have been reduced
on a pro forma basis by $498,000 in 1999, $820,000 in 1998 and $51,400
in 1997. On a pro forma basis, basic and diluted earnings per share
for 1999 and 1998 would have been reduced by $.01 and $.02,
respectively, and there would have been no effect for 1997. Since SFAS
No. 123 does not require this accounting to be applied to options
granted prior to January 1, 1995, the resulting pro forma compensation
costs may not be representative of those to be expected in future
years.
A summary of the status of the stock option plans at December 31, 1999,
1998 and 1997, and changes during the years then ended are as follows:
1999 1998 1997
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 1,516,808 $19.17 594,180 $12.07 635,965 $11.77
Granted 22,500 23.31 1,225,920 21.12 22,500 16.37
Forfeited (57,966) 20.38 (37,875) 21.05 (13,600) 11.41
Exercised (54,080) 11.95 (265,417) 11.98 (50,685) 10.50
Balance at end
of year 1,427,262 19.46 1,516,808 19.17 594,180 12.07
Exercisable at
end of year 301,681 $13.89 333,261 $12.94 112,461 $11.67
Exercise prices on options outstanding at December 31, 1999, range from
$10.50 to $23.84 with a weighted average remaining contractual life of
approximately 8 years.
The fair value of each option is estimated on the date of grant using
the Black-Scholes option pricing model. The weighted average fair
value of the options granted and the assumptions used to estimate the
fair value of options are as follows:
1999 1998 1997
Fair value of options at grant date $ 4.82 $ 2.40 $ 2.09
Weighted average risk-free
interest rate 5.98% 4.78% 6.60%
Weighted average expected
price volatility 22.03% 16.27% 14.51%
Weighted average expected
dividend yield 4.22% 5.13% 5.48%
Expected life in years 7 7 7
NOTE 8
INCOME TAXES
Income tax expense is summarized as follows:
Years ended December 31, 1999 1998 1997
(In thousands)
Current:
Federal $29,574 $ 28,256 $15,427
State 3,874 5,880 2,362
Foreign 158 605 60
33,606 34,741 17,849
Deferred:
Investment tax credit (888) (975) (1,150)
Income taxes --
Federal 12,902 (14,214) 11,844
State 3,690 (2,067) 2,200
15,704 (17,256) 12,894
Total income tax expense $49,310 $ 17,485 $30,743
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1999 1998
(In thousands)
Deferred tax assets:
Regulatory matters $ 14,562 $ 22,319
Accrued pension costs 10,898 9,274
Deferred investment tax credits 2,028 2,336
Accrued land reclamation 2,803 2,907
Other 16,892 17,572
Total deferred tax assets 47,183 54,408
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 218,355 188,375
Basis differences on oil and
natural gas producing properties 17,163 9,604
Regulatory matters 6,785 7,047
Other 3,051 5,558
Total deferred tax liabilities 245,354 210,584
Net deferred income tax liability $(198,171)$(156,176)
The following table reconciles the change in the net deferred income
tax liability from December 31, 1998, to December 31, 1999, to the
deferred income tax expense included in the Consolidated Statements of
Income:
1999
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 41,995
Change in tax effects of income tax-related
regulatory assets and liabilities (4,293)
Deferred taxes associated with acquisitions (21,110)
Deferred income tax expense for the period $ 16,592
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for this difference are as follows:
Years ended December 31, 1999 1998 1997
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $46,686 35.0 $18,057 35.0 $29,876 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,300) (1.0) (1,571) (3.0) (828) (1.0)
State income taxes --
net of federal
income tax benefit 5,921 4.4 2,312 4.5 3,473 4.1
Investment tax credit
amortization (888) (.6) (975) (1.9) (1,150) (1.4)
Other items (1,109) (.8) (338) (.7) (628) (.7)
Total income tax expense $49,310 37.0 $17,485 33.9 $30,743 36.0
NOTE 9
BUSINESS SEGMENT DATA
The company's reportable segments are those that are based on the
company's method of internal reporting, which generally segregates the
strategic business units due to differences in products, services and
regulation. Prior to the fourth quarter of 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. As of December 31, 1999, all of the company's operations
are located within the United States. The electric business generates,
transmits and distributes electricity and the natural gas distribution
business distributes natural gas, and these operations also supply
related value-added products and services in the Northern Great Plains.
The utility services business 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. The pipeline and energy services business 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 business is engaged in oil and natural
gas acquisition, exploration and production throughout the United
States and in the Gulf of Mexico. The construction materials and
mining business mines and markets aggregates and related value-added
construction materials products and services in the western United
States, including Alaska and Hawaii. It also operates lignite coal
mines in Montana and North Dakota.
Segment information follows the same accounting policies as described
in the Summary of Significant Accounting Policies. Segment information
included in the accompanying Consolidated Balance Sheets as of
December 31 and included in the Consolidated Statements of Income for
the years then ended is as follows:
1999 1998 1997
(In thousands)
Operating revenues - external:
Electric $ 154,869 $ 147,221 $ 141,590
Natural gas distribution 157,692 154,147 157,005
Utility services 99,917 64,232 22,761
Pipeline and energy services 334,188 132,826 36,999
Oil and natural gas production 63,238 51,750 75,172
Construction materials and mining 455,939 331,988 163,006
Total operating revenues - external $1,265,843 $ 882,164 $ 596,533
Operating revenues - intersegment:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- --- ---
Pipeline and energy services 49,344 47,906 50,019
Oil and natural gas production 15,156 10,092 2,744
Construction materials and mining(a) 13,966 14,463 11,141
Intersegment eliminations (64,500) (57,998) (52,763)
Total operating revenues -
intersegment(a) $ 13,966 $ 14,463 $ 11,141
Depreciation, depletion and
amortization:
Electric $ 18,375 $ 18,129 $ 17,491
Natural gas distribution 7,348 7,150 7,013
Utility services 2,591 1,669 280
Pipeline and energy services 8,248 6,972 4,888
Oil and natural gas production 19,248 23,304 25,096
Construction materials and mining 26,008 20,562 10,999
Total depreciation, depletion
and amortization $ 81,818 $ 77,786 $ 65,767
Interest expense:
Electric $ 9,692 $ 9,979 $ 10,735
Natural gas distribution 3,614 3,728 3,698
Utility services 812 325 214
Pipeline and energy services 7,281 5,800 8,117
Oil and natural gas production 3,405 3,039 2,942
Construction materials and mining 11,202 7,402 4,503
Total interest expense $ 36,006 $ 30,273 $ 30,209
Income taxes:
Electric $ 8,678 $ 7,767 $ 7,011
Natural gas distribution 1,443 2,681 2,987
Utility services 4,323 2,437 631
Pipeline and energy services 13,356 12,579 7,566
Oil and natural gas production 10,032 (23,134) 8,156
Construction materials and mining 11,478 15,155 4,392
Total income taxes $ 49,310 $ 17,485 $ 30,743
Earnings on common stock:
Electric $ 15,973 $ 13,908 $ 12,441
Natural gas distribution 3,192 3,501 4,514
Utility services 6,505 3,272 947
Pipeline and energy services 20,972 18,651 9,955
Oil and natural gas production 16,207 (30,501)(b) 15,867
Construction materials and mining 20,459 24,499 10,111
Total earnings on common stock $ 83,308 $ 33,330 $ 53,835
Capital expenditures:
Electric $ 18,218 $ 13,035 $ 18,363
Natural gas distribution 9,246 8,256 8,858
Utility services 16,052 18,343 9,607
Pipeline and energy services 35,123 17,603 9,684
Oil and natural gas production 64,294 100,572 34,172
Construction materials and mining 105,098 172,108 41,472
Net proceeds from sale or
disposition of property (16,660) (4,275) (4,522)
Total net capital expenditures $ 231,371 $ 325,642 $ 117,634
Identifiable assets:
Electric(c) $ 307,417 $ 305,627
Natural gas distribution(c) 131,294 129,654
Utility services 67,755 38,677
Pipeline and energy services 302,587 239,507
Oil and natural gas production 255,416 192,642
Construction materials and mining 655,499 500,720
Corporate assets(d) 46,335 45,948
Total identifiable assets $1,766,303 $1,452,775
Property, plant and equipment:
Electric $ 581,090 $ 567,282
Natural gas distribution 185,797 178,522
Utility services 21,876 15,765
Pipeline and energy services 308,409 276,325
Oil and natural gas production 343,157 288,487
Construction materials and mining 601,952 484,419
Less accumulated depreciation,
depletion and amortization 794,105 726,123
Net property, plant and equipment $1,248,176 $1,084,677
(a) In accordance with the provision of SFAS No. 71,
intercompany coal sales are not eliminated.
(b) Reflects $39.9 million in noncash after-tax write-
downs of oil and natural gas properties.
(c) Includes, in the case of electric and natural gas distribution
property, allocations of common utility property.
(d) Corporate assets consist of assets not directly assignable to a
business segment (i.e., cash and cash equivalents, certain accounts
receivable and other miscellaneous current and deferred assets).
Capital expenditures for 1999, 1998 and 1997, related to acquisitions,
in the preceding 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.
NOTE 10
ACQUISITIONS
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.
In March 1998, the company acquired Morse Bros., Inc. and S2 - F Corp.,
privately held construction materials companies located in Oregon's
Willamette Valley. The purchase consideration for such companies
consisted of $98.2 million of the company's common stock and cash.
Morse Bros., Inc. sells aggregate, ready-mixed concrete, asphalt,
prestressed concrete and construction services in the Willamette Valley
from Portland to Eugene. S2 - F Corp. sells aggregate and construction
services.
The company also acquired a number of other businesses in 1998, none of
which were individually material, including construction materials and
mining businesses in Oregon, utility services construction and
engineering businesses in California and Montana and a natural gas
marketing business in Kentucky. The total purchase consideration,
consisting of the company's common stock and cash, for these businesses
was $62.7 million.
In 1997, the company acquired several businesses, none of which were
individually material, including the remaining 50 percent interest in
Hawaiian Cement (See Note 12) and utility services construction and
construction supplies and equipment businesses in Oregon. The total
purchase consideration, consisting of the company's common stock and
cash, for these businesses was $35.2 million.
The above acquisitions were accounted for under the purchase method of
accounting and accordingly, the acquired assets and liabilities assumed
have been recorded at their respective fair values as of the date of
acquisition. The results of operations of the acquired businesses are
included in the financial statements since the date of each
acquisition. Pro forma financial amounts reflecting the effects of the
above acquisitions are not presented as such acquisitions were not
material to the company's financial position or results of operations.
NOTE 11
EMPLOYEE BENEFIT PLANS
The company has noncontributory defined benefit pension plans and other
postretirement benefit plans. There were no additional minimum pension
liabilities required to be recognized as of December 31, 1999 and 1998.
Changes in benefit obligation and plan assets for the years ended
December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $187,665 $178,199 $70,338 $ 73,838
Service cost 4,894 4,509 1,451 1,502
Interest cost 12,573 12,248 4,720 4,848
Plan participants' contributions --- --- 617 475
Amendments 3,612 437 3,691 (4,810)
Actuarial (gain) loss (17,134) 5,971 (11,047) (1,695)
Benefits paid (10,613) (13,699) (3,831) (3,820)
Benefit obligation at
end of year 180,997 187,665 65,939 70,338
Change in plan assets:
Fair value of plan assets at
beginning of year 251,194 225,201 39,543 30,595
Actual return on plan assets 35,874 39,604 5,223 6,226
Employer contribution 4 88 5,595 6,067
Plan participants' contributions --- --- 617 475
Benefits paid (10,613) (13,699) (3,831) (3,820)
Fair value of plan assets at end
of year 276,459 251,194 47,147 39,543
Funded status 95,462 63,529 (18,792) (30,795)
Unrecognized actuarial gain (108,593) (73,963) (21,299) (8,036)
Unrecognized prior service cost 10,206 7,645 --- (1,433)
Unrecognized net transition
obligation (asset) (4,402) (5,340) 30,910 31,029
Accrued benefit cost $ (7,327) $ (8,129) $(9,181) $ (9,235)
Weighted average assumptions for the company's pension and other
postretirement benefit plans as of December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 5.00% 4.50% 5.00% 4.50%
Health care rate assumptions for the company's other postretirement
benefit plans as of December 31 are as follows:
1999 1998
Health care trend rate 6.00%-8.00% 6.50%-8.50%
Health care cost trend rate - ultimate 5.00%-6.00% 5.00%-6.00%
Year in which ultimate trend rate achieved 1999-2004 1999-2004
Components of net periodic benefit cost for the company's pension and
other postretirement benefit plans are as follows:
Other
Pension Postretirement
Benefits Benefits
Years ended December 31, 1999 1998 1997 1999 1998 1997
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 4,894 $ 4,509 $ 3,889 $1,451 $1,502 $1,272
Interest cost 12,573 12,248 11,651 4,720 4,848 4,691
Expected return on assets (17,489) (15,892) (14,321) (2,807) (2,395) (1,748)
Amortization of prior
service cost 842 848 811 --- --- ---
Recognized net actuarial
gain (995) (621) (666) (200) (169) (105)
Amortization of net
transition obligation
(asset) (997) (994) (988) 2,377 2,458 2,458
Net periodic benefit cost
(income) (1,172) 98 376 5,541 6,244 6,568
Less amount capitalized (87) 79 70 463 628 625
Net periodic benefit
expense (income) $ (1,085) $ 19 $ 306 $5,078 $5,616 $5,943
The company has other postretirement benefit plans including health
care and life insurance. The plans underlying these benefits may
require contributions by the employee depending on such employee's age
and years of service at retirement or the date of retirement. The
accounting for the health care plan anticipates future cost-sharing
changes that are consistent with the company's expressed intent to
generally increase retiree contributions each year by the excess of the
expected health care cost trend rate over 6 percent.
Assumed health care cost trend rates may have a significant effect on
the amounts reported for the health care plans. A one percentage point
change in the assumed health care cost trend rates would have the
following effects at December 31, 1999:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 240 $ (217)
Effect on postretirement benefit
obligation $3,004 $(2,683)
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for defined
benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants which is payable to the
company upon the employee's death. The cost of these benefits was
$3.3 million, $2.7 million and $2.2 million in 1999, 1998 and 1997,
respectively.
The company sponsors various defined contribution plans for eligible
employees. Costs incurred by the company under these plans were
$4.4 million in 1999, $3.1 million in 1998 and $2.1 million in 1997.
The costs incurred in each year reflect additional participants as a
result of business acquisitions.
NOTE 12
PARTNERSHIP INVESTMENT
In September 1995, KRC Holdings, Inc., through its wholly owned
subsidiary, Knife River Hawaii, Inc., acquired a 50 percent interest in
Hawaiian Cement, which was previously owned by Lone Star Industries,
Inc. Knife River Dakota, Inc., a wholly owned subsidiary of KRC
Holdings, Inc. acquired the remaining 50 percent interest in Hawaiian
Cement from the previous owner, Adelaide Brighton Cement (Hawaii), Inc.
of Adelaide, Australia, in July 1997.
In August 1997, the company began consolidating Hawaiian Cement into
its financial statements. Prior to August 1997, the company's net
investment in Hawaiian Cement was not consolidated and was accounted
for by the equity method. The company's share of operating results for
the seven months ended July 31, 1997, is included in "Other income --
net" in the accompanying Consolidated Statements of Income for the year
ended December 31, 1997. Summarized operating results for Hawaiian
Cement for the seven months ended July 31, 1997, when accounted for by
the equity method, are as follows: net sales of $33.5 million,
operating margin of $4.7 million and income before income taxes of $2.0
million.
NOTE 13
JOINTLY OWNED FACILITIES
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets, liabilities
and expenses of the Big Stone Station and the Coyote Station,
respectively. Each owner of the Big Stone and Coyote stations is
responsible for financing its investment in the jointly owned
facilities.
The company's share of the Big Stone Station and Coyote Station
operating expenses is reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
1999 1998
(In thousands)
Big Stone Station:
Utility plant in service $ 49,889 $ 49,762
Less accumulated depreciation 29,611 28,781
$ 20,278 $ 20,981
Coyote Station:
Utility plant in service $121,919 $121,726
Less accumulated depreciation 60,350 56,770
$ 61,569 $ 64,956
NOTE 14
REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
Williston Basin Interstate Pipeline Company, an indirect wholly owned
subsidiary of the company, 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.
NOTE 15
COMMITMENTS AND CONTINGENCIES
Litigation
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.
Williston Basin believes that it is entitled to recover from customers
virtually all of the costs which were incurred as a result of the
settlement of this litigation as gas supply realignment transition
costs pursuant to the provisions of the FERC's Order 636. However, the
amount of costs that can ultimately be recovered is subject to approval
by the FERC and market conditions.
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.
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.
The company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that there is no
pending legal proceeding against or involving the company, except those
discussed above, for which the outcome is likely to have a material
adverse effect upon the company's financial position or results of
operations.
Electric purchased power commitments
Through October 31, 2006, Montana-Dakota has contracted to purchase
66,400 kW of participation power from Basin Electric Power Cooperative.
In addition, Montana-Dakota, under a power supply contract through
December 31, 2006, is purchasing up to 55,000 kW of capacity from Black
Hills Power and Light Company.
NOTE 16
QUARTERLY DATA (UNAUDITED)
The following unaudited information shows selected items by quarter for
the years 1999 and 1998:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
1999
Operating revenues $259,046 $290,267 $375,591 $354,905
Operating expenses 233,585 254,619 321,535 310,319
Operating income 25,461 35,648 54,056 44,586
Net income 12,721 17,796 29,098 24,465
Earnings per common share:
Basic .24 .33 .53 .43
Diluted .23 .33 .52 .42
Weighted average common shares
outstanding:
Basic 53,147 53,373 54,995 56,898
Diluted 53,420 53,603 55,278 57,127
1998*
Operating revenues $170,122 $179,715 $269,978 $276,812
Operating expenses 137,913 186,310 227,283 274,178
Operating income (loss) 32,209 (6,595) 42,695 2,634
Net income (loss) 17,793 (5,785) 22,538 (439)
Earnings (loss) per common share:
Basic .39 (.12) .42 (.01)
Diluted .39 (.12) .42 (.01)
Weighted average common shares
outstanding:
Basic 45,375 50,936 52,703 53,021
Diluted 45,629 50,936 53,062 53,021
* Reflects $20.0 million and $19.9 million in noncash after-tax write-
downs of oil and natural gas properties for the second quarter and
fourth quarter of 1998, respectively.
Certain company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 17
OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)
Fidelity Exploration & Production Company, an indirect wholly owned
subsidiary of the company, 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 information that follows includes the company's proportionate share
of all its oil and natural gas interests held by Fidelity.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to oil and natural gas
producing activities at December 31:
1999 1998 1997
(In thousands)
Subject to amortization $319,448 $266,301 $252,291
Not subject to amortization 23,464 22,153 9,408
Total capitalized costs 342,912 288,454 261,699
Less accumulated depreciation,
depletion and amortization 129,211 111,472 95,611
Net capitalized costs $213,701 $176,982 $166,088
NOTE: Net capitalized costs as of December 31, 1998, reflect noncash
write-downs of the company's oil and natural gas properties as
discussed in Note 1.
Capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities are as follows:
Years ended December 31, 1999 1998 1997
(In thousands)
Acquisitions $ 30,842 $ 63,419 $ 59
Exploration 11,010 15,976 13,344
Development 21,822 21,148 18,874
Total capital expenditures $ 63,674 $100,543 $ 32,277
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs:
Years ended December 31, 1999 1998 1997
(In thousands)
Revenues $ 75,327 $ 61,831 $ 77,756
Production costs 25,402 19,419 23,251
Depreciation, depletion and
amortization 19,136 23,050 24,864
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
Pretax income 30,789 (46,638) 29,641
Income tax expense (benefit) 11,815 (19,268) 10,968
Results of operations for
producing activities $ 18,974 $(27,370) $ 18,673
The following table summarizes the company's estimated quantities of
proved oil and natural gas reserves at December 31, 1999, 1998 and
1997, and reconciles the changes between these dates. Estimates of
economically recoverable oil and natural gas reserves and future net
revenues therefrom are based upon a number of variable factors and
assumptions. For these reasons, estimates of economically recoverable
reserves and future net revenues may vary from actual results.
1999 1998 1997
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 11,500 243,600 14,900 184,900 16,100 200,200
Production (1,800) (24,700) (1,900) (20,700) (2,100) (20,400)
Extensions and
discoveries 800 21,800 200 21,300 600 12,100
Purchases of proved
reserves 700 38,200 2,000 56,600 --- 200
Sales of reserves
in place (400) (9,300) --- (100) (200) (2,300)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 3,900 (700) (3,700) 1,600 500 (4,900)
Balance at end
of year 14,700 268,900 11,500 243,600 14,900 184,900
Proved developed reserves:
January 1, 1997 15,400 168,200
December 31, 1997 14,500 163,800
December 31, 1998 10,700 193,000
December 31, 1999 13,300 213,400
All of the company's interests in oil and natural gas reserves are
located in the United States and in the Gulf of Mexico.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various oil
and natural gas interests at December 31 is as follows:
1999 1998 1997
(In thousands)
Future net cash flows before
income taxes $ 492,000 $246,700 $306,600
Future income tax expenses 131,500 40,500 86,600
Future net cash flows 360,500 206,200 220,000
10% annual discount for estimated
timing of cash flows 131,400 81,100 81,000
Discounted future net cash flows
relating to proved oil and natural
gas reserves $ 229,100 $125,100 $139,000
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1999 1998 1997
(In thousands)
Beginning of year $ 125,100 $139,000 $234,000
Net revenues from production (49,900) (42,400) (54,500)
Change in net realization 123,100 (70,500) (158,400)
Extensions, discoveries and improved
recovery, net of future
production-related costs 33,500 18,200 19,400
Purchases of proved reserves 57,700 51,000 200
Sales of reserves in place (14,700) (100) (2,800)
Changes in estimated future
development costs, net of those
incurred during the year (9,800) (16,600) 7,700
Accretion of discount 16,700 18,600 32,800
Net change in income taxes (59,800) 30,100 62,100
Revisions of previous quantity
estimates 7,400 (1,600) (1,300)
Other (200) (600) (200)
Net change 104,000 (13,900) (95,000)
End of year $ 229,100 $125,100 $139,000
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end oil and
natural gas prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying
statutory tax rates (adjusted for permanent differences and tax
credits) to estimated net future pretax cash flows.
Report of Independent Public Accountants
To MDU Resources Group, Inc.
We have audited the accompanying consolidated balance sheets of MDU
Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of
December 31, 1999 and 1998, and the related consolidated statements of
income, common stockholders' equity and cash flows for each of the
three years in the period ended December 31, 1999. These financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of MDU
Resources Group, Inc. and Subsidiaries as of December 31, 1999 and
1998, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1999, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 24, 2000
<TABLE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
<CAPTION>
1999 1998* 1997 1996 1995 1994 1989
<S> <C> <C> <C> <C> <C> <C> <C>
Selected Financial Data
Operating revenues: (000's)
Electric $ 154,869 $ 147,221 $ 141,590 $ 138,761 $ 134,609 $ 133,953 $ 126,228
Natural gas distribution 157,692 154,147 157,005 155,012 150,532 155,319 142,310
Utility services 99,917 64,232 22,761 --- --- --- ---
Pipeline and energy services 383,532 180,732 87,018 71,580 67,186 63,874 107,014
Oil and natural gas production 78,394 61,842 77,916 75,350 53,505 44,936 27,351
Construction materials and mining 469,905 346,451 174,147 132,222 113,066 116,646 41,643
Intersegment eliminations (64,500) (57,998) (52,763) (58,224) (54,652) (65,200) (91,773)
$1,279,809 $ 896,627 $ 607,674 $ 514,701 $ 464,246 $ 449,528 $ 352,773
Operating income: (000's)
Electric $ 35,727 $ 32,167 $ 31,307 $ 29,476 $ 29,898 $ 27,596 $ 32,592
Natural gas distribution 6,688 8,028 10,410 11,504 6,917 3,948 7,781
Utility services 11,518 5,932 1,782 --- --- --- ---
Pipeline and energy services 40,627 33,651 25,822 27,697 24,043 19,024 23,683
Oil and natural gas production 26,845 (50,444) 27,638 26,786 15,255 11,014 11,572
Construction materials and mining 38,346 41,609 14,602 16,062 14,463 16,593 9,087
$ 159,751 $ 70,943 $ 111,561 $ 111,525 $ 90,576 $ 78,175 $ 84,715
Earnings on common stock: (000's)
Electric $ 15,973 $ 13,908 $ 12,441 $ 11,436 $ 12,000 $ 11,719 $ 13,385
Natural gas distribution 3,192 3,501 4,514 4,892 1,604 285 3,123
Utility services 6,505 3,272 947 --- --- --- ---
Pipeline and energy services 20,972 18,651 9,955 1,649 7,804 5,106 3,125
Oil and natural gas production 16,207 (30,501) 15,867 15,185 8,614 10,316 7,362
Construction materials and mining 20,459 24,499 10,111 11,521 10,819 11,622 8,890
$ 83,308 $ 33,330 $ 53,835 $ 44,683 $ 40,841 $ 39,048 $ 35,885
Earnings per common share -- diluted $ 1.52 $ .66 $ 1.24 $ 1.04 $ .95 $ .91 $ .84
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 54,870 50,837 43,478 42,824 42,789 42,763 42,715
Dividends per common share $ .82 $ .7834 $ .7534 $ .7333 $ .7188 $ .7022 $ .6533
Book value per common share $ 11.74 $ 10.39 $ 8.84 $ 8.21 $ 7.90 $ 7.66 $ 6.71
Market price per common share (year-end) $ 20.00 $ 26.31 $ 21.08 $ 15.33 $ 13.25 $ 12.06 $ 10.05
Market price ratios:
Dividend payout 55% 119% 61% 70% 76% 77% 78%
Yield 4.2% 3.0% 3.6% 4.8% 5.5% 5.9% 6.5%
Price/earnings ratio 13.2x 39.9x 17.0x 14.6x 13.9x 13.2x 12.0x
Market value as a percent of book value 170.4% 253.2% 238.5% 186.8% 167.7% 157.4% 149.7%
Profitability Indicators
Return on average common equity 13.9% 6.5% 14.6% 13.0% 12.3% 12.1% 12.5%
Return on average invested capital 9.6% 5.5% 10.3% 9.5% 9.2% 9.1% 9.2%
Interest coverage 7.1x 6.1x 6.0x 5.4x 3.9x 3.3x 2.8x
Fixed charges coverage, including
preferred dividends 4.3x 2.5x 3.4x 2.7x 3.0x 2.8x 2.3x
General
Total assets (000's) $1,766,303 $1,452,775 $1,113,892 $1,089,173 $1,056,479 $1,004,718 $ 971,401
Net long-term debt (000's) $ 563,545 $ 413,264 $ 298,561 $ 280,666 $ 237,352 $ 217,693 $ 234,333
Redeemable preferred stock (000's) $ 1,600 $ 1,700 $ 1,800 $ 1,900 $ 2,000 $ 2,100 $ 2,600
Capitalization ratios:
Common stockholders' equity 54% 56% 55% 54% 57% 58% 53%
Preferred stocks 1 2 2 3 3 3 3
Long-term debt 45 42 43 43 40 39 44
100% 100% 100% 100% 100% 100% 100%
<FN>
* Reflects $39.9 million or 78 cents per common share in noncash after-tax write-downs of oil and natural gas properties.
</FN>
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
</TABLE>
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994 1989
<S>
Electric <C> <C> <C> <C> <C> <C> <C>
Sales to ultimate consumers (thousand kWh) 2,075,446 2,053,862 2,041,191 2,067,926 1,993,693 1,955,136 1,836,099
Sales for resale (thousand kWh) 943,520 586,540 361,954 374,535 408,011 444,492 311,327
Electric system generating and firm purchase
capability -- kW (Interconnected system) 492,800 489,100 487,500 481,800 472,400 470,900 451,600
Demand peak -- kW (Interconnected system) 420,550 402,500 404,600 393,300 412,700 369,800 383,600
Electricity produced (thousand kWh) 2,350,769 2,103,199 1,826,770 1,829,669 1,718,077 1,901,119 1,773,849
Electricity purchased (thousand kWh) 860,508 730,949 769,679 809,261 867,524 700,912 557,650
Average cost of fuel and purchased
power per kWh $ .016 $ .017 $ .018 $ .017 $ .016 $ .017 $ .017
Natural Gas Distribution
Sales (Mdk) 30,931 32,024 34,320 38,283 33,939 31,840 31,643
Transportation (Mdk) 11,551 10,324 10,067 9,423 11,091 9,278 9,321
Weighted average degree days --
% of previous year's actual 89% 94% 85% 114% 105% 92% 112%
Pipeline and Energy Services
Pipeline:
Sales for resale (Mdk) --- --- --- --- --- --- 27,274
Transportation (Mdk) 78,061 88,974 85,464 82,169 68,015 63,870 51,159
Energy services:
Natural gas volumes (Mdk) 131,687 58,495 14,971 4,670 3,556 7,301 843
Propane (thousand gallons) 6,440 7,037 10,005 9,689 7,471 6,462 ---
Oil and Natural Gas Production
Production:
Oil (000's of barrels) 1,758 1,912 2,088 2,149 1,973 1,565 1,348
Natural gas (MMcf) 24,652 20,699 20,407 20,391 17,574 14,162 3,632
Average prices:
Oil (per barrel) $ 15.34 $ 12.71 $ 17.50 $ 17.91 $ 15.07 $ 13.14 $ 16.26
Natural gas (per Mcf) $ 1.94 $ 1.81 $ 2.02 $ 1.79 $ 1.33 $ 1.69 $ 1.33
Net recoverable reserves:
Oil (000's of barrels) 14,700 11,500 14,900 16,100 14,200 12,500 12,000
Natural gas (MMcf) 268,900 243,600 184,900 200,200 179,000 154,200 10,800
Construction Materials and Mining
Construction materials: (000's)
Aggregates (tons sold) 13,981 11,054 5,113 3,374 2,904 2,688 ---
Asphalt (tons sold) 2,993 1,790 758 694 373 391 ---
Ready-mixed concrete (cubic yards sold) 1,186 1,021 516 340 307 315 ---
Recoverable aggregate reserves (tons) 740,030 654,670 169,375 119,800 68,000 71,000 ---
Coal: (000's)
Sales (tons) 3,236 3,113 2,375 2,899 4,218 5,206 4,747
Recoverable reserves (tons) 182,761 190,152 226,560 228,900 231,900 236,100 266,000
</TABLE>
MDU RESOURCES GROUP, INC.
List of Subsidiaries
State or Other
Jurisdiction
in Which
Incorporated
Alaska Basic Industries, Inc. Alaska
Anchorage Sand and Gravel Company, Inc. Alaska
Baldwin Contracting Company, Inc. California
Centennial Energy Holdings, Inc. Delaware
Concrete, Inc. California
DSS Company California
Fidelity Exploration & Production Company Delaware
Fidelity Oil Co. Delaware
Fidelity Oil Holdings, Inc. Delaware
Hap Taylor & Sons, Inc. Oregon
Harp Engineering, Inc. Montana
Harp Line Constructors Co. Montana
High Line Equipment, Inc. Delaware
ILB Hawaii, Inc. Hawaii
Innovative Gas Services, Incorporated Kentucky
International Line Builders, Inc. Delaware
JTL Group, Inc. - Montana Montana
JTL Group, Inc. - Wyoming Wyoming
Kentucky Pipeline and Storage Company, Inc. Delaware
Knife River Corporation Delaware
Knife River Dakota, Inc. Delaware
Knife River Hawaii, Inc. Delaware
Knife River Marine, Inc. Delaware
KRC Aggregate, Inc. Delaware
KRC Holdings, Inc. Delaware
LTM, Incorporated Oregon
Loy Clark Pipeline Co. Oregon
Loy Clark Pipeline of Washington, Inc. Washington
Marcon Energy Corporation Kentucky
Medford Ready Mix, Inc. Delaware
Morse Bros., Inc. Oregon
Pouk & Steinle, Inc. California
Prairie Propane, Inc. Delaware
Prairielands Energy Marketing, Inc. Delaware
Prairielands Energy Technology, Inc. Delaware
Rogue Aggregates, Inc. Oregon
S2 - F Corp. Oregon
Southern Oregon Underground, Inc. Oregon
Utility Services, Inc. Delaware
WBI Canadian Pipeline, Ltd. Canada
WBI Energy Services, Inc. Delaware
WBI Holdings, Inc. Delaware
WBI Offshore Pipeline, Inc. Delaware
WBI Pipeline & Storage Group, Inc. Delaware
WBI Production, Inc. Delaware
WBI Southern, Inc. Delaware
Williams Construction Company Inc. Montana
Williston Basin Interstate Pipeline Company Delaware
Bitter Creek Pipelines, LLC Colorado LLC
Central Oregon Redi-Mix, LLC Oregon LLC
Gascoyne Material Handling & Recycling LLC North Dakota LLC
Hawaiian Cement Hawaii Partnership
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference in this Form 10-K of our report dated
January 24, 2000 included in the MDU Resources Group, Inc. Annual
Report to Stockholders for 1999. We also consent to the
incorporation of our report incorporated by reference in this
Form 10-K into the Company's previously filed Registration
Statements on Form S-3, No. 333-06127 and No. 333-48647, and on
Form S-8, No. 33-54486, No. 333-06103, No. 333-06105, No. 333-
27879, No. 333-27877 and No. 333-72595.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
March 3, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED
STATEMENTS OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000067716
<NAME> MDU RESOURCES GROUP, INC.
<MULTIPLIER> 1000
<CURRENCY> US
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 518,524
<OTHER-PROPERTY-AND-INVEST> 772,780
<TOTAL-CURRENT-ASSETS> 351,696
<TOTAL-DEFERRED-CHARGES> 123,303
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,766,303
<COMMON> 57,038
<CAPITAL-SURPLUS-PAID-IN> 368,926
<RETAINED-EARNINGS> 243,569
<TOTAL-COMMON-STOCKHOLDERS-EQ> 669,533
1,500
15,000
<LONG-TERM-DEBT-NET> 563,545
<SHORT-TERM-NOTES> 1,693
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 13,000
<LONG-TERM-DEBT-CURRENT-PORT> 4,328
100
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 497,604
<TOT-CAPITALIZATION-AND-LIAB> 1,766,303
<GROSS-OPERATING-REVENUE> 1,279,809
<INCOME-TAX-EXPENSE> 49,310
<OTHER-OPERATING-EXPENSES> 1,120,058
<TOTAL-OPERATING-EXPENSES> 1,169,368
<OPERATING-INCOME-LOSS> 110,441
<OTHER-INCOME-NET> 9,645
<INCOME-BEFORE-INTEREST-EXPEN> 120,086
<TOTAL-INTEREST-EXPENSE> 36,006
<NET-INCOME> 84,080
772
<EARNINGS-AVAILABLE-FOR-COMM> 83,308
<COMMON-STOCK-DIVIDENDS> 45,322
<TOTAL-INTEREST-ON-BONDS> 9,731
<CASH-FLOW-OPERATIONS> 154,873
<EPS-BASIC> 1.53
<EPS-DILUTED> 1.52
</TABLE>
