Back to GetFilings.com
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, 1998
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)
Registrant's telephone number, including area code: (701) 222-7900
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
Common Stock, par value $3.33 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 26, 1999: $1,248,942,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 26, 1999: 53,146,476 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 25 through 53 of the Annual Report to Stockholders for 1998,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 15, 1999, incorporated in Part III,
Items 10, 11, 12 and 13 of this Report.
CONTENTS
PART I
Items 1 and 2 -- Business and Properties
General
Montana-Dakota Utilities Co. --
Electric Generation, Transmission and Distribution
Retail Natural Gas and Propane Distribution
WBI Holdings, Inc.
Knife River Corporation --
Construction Materials Operations
Coal Operations
Consolidated Construction Materials and Mining
Operations
Fidelity Oil Group
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, distributes natural gas and
operates electric power generation, transmission and distribution
facilities, serving 256 communities in North Dakota, eastern
Montana, northern and western South Dakota and northern Wyoming.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc.,(WBI
Holdings), Knife River Corporation (Knife River), the Fidelity Oil
Group (Fidelity Oil) and Utility Services, Inc. (Utility Services).
WBI Holdings, through its wholly owned subsidiary,
Williston Basin Interstate Pipeline Company,
(Williston Basin), produces natural gas and provides
underground storage, transportation and gathering
services through an interstate pipeline system serving
Montana, North Dakota, South Dakota and Wyoming. In
addition, WBI Holdings, through its wholly owned
subsidiary, WBI Energy Services, Inc. and its
subsidiaries, seeks new energy markets while
continuing to expand present markets for natural gas
and propane in the Midwestern, Southern and Central
regions of the United States.
Knife River, through its wholly owned subsidiary, KRC
Holdings, Inc. (KRC Holdings) and its subsidiaries,
mines and markets aggregates and construction
materials in Alaska, California, Hawaii and Oregon,
and operates lignite coal mines in Montana and North
Dakota.
Fidelity Oil is comprised of Fidelity Oil Co. and
Fidelity Oil Holdings, Inc., which own oil and natural
gas interests throughout the United States, the Gulf
of Mexico and Canada.
Utility Services, through its wholly owned
subsidiaries, installs and repairs electric
transmission and distribution power lines, fiber optic
cable and natural gas pipeline and provides related
supplies, equipment and engineering services
throughout the western United States and Hawaii.
The significant industries within the Company's retail utility
service area consist of agriculture and the related processing of
agricultural products and energy-related activities such as oil and
natural gas production, oil refining, coal mining and electric
power generation.
As of December 31, 1998, the Company had 2,882 full-time
employees with 72 employed at MDU Resources Group, Inc., 900 at
Montana-Dakota, 301 at WBI Holdings, 1,084 at Knife River's
construction materials operations, 151 at Knife River's coal
operations, 12 at Fidelity Oil and 362 at Utility Services.
Approximately 434 and 84 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 May 1999, for both Montana-
Dakota and WBI Holdings. Knife River has a labor contract through
August 1999, with the United Mine Workers of America, which
represents its coal operation's hourly workforce aggregating 90
employees. In addition, Knife River has 15 labor contracts which
represent 232 of its construction materials employees. Utility
Services has 19 labor contracts representing the majority of its
employees.
The financial results and data applicable to each of the
Company's business segments as well as their financing requirements
are set forth in Item 7 -- "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Notes to
Consolidated Financial Statements.
Any reference to the Company's Consolidated Financial
Statements and Notes thereto shall be to pages 25 through 51 in the
Company's Annual Report to Stockholders for 1998 (Annual Report),
which are incorporated by reference herein.
ENERGY DISTRIBUTION OPERATIONS AND PROPERTY (MONTANA-DAKOTA)
Electric Generation, Transmission and Distribution
General --
Montana-Dakota provides electric service at retail, serving
over 114,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as of
December 31, 1998. 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
3,900 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, 1998,
Montana-Dakota's net electric plant investment approximated $279.2
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 W. T. Cunningham, 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 (MPSC), South Dakota Public
Utilities Commission (SDPUC) and Wyoming Public Service Commission
(WPSC). The percentage of Montana-Dakota's 1998 electric utility
operating revenues by jurisdiction is as follows: North Dakota --
60 percent; Montana -- 22 percent; South Dakota -- 8 percent and
Wyoming -- 10 percent.
System Supply and System Demand --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and major
communities -- western North Dakota, including Bismarck, Dickinson
and Williston; eastern Montana, including Glendive and Miles City;
and northern South Dakota, including Mobridge. The interconnected
system consists of seven on-line electric generating stations which
have an aggregate turbine nameplate rating attributable to Montana-
Dakota's interest of 393,488 Kilowatts (kW) and a total summer net
capability of 415,408 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 (Basin) for its interconnected system.
The following table sets forth details applicable to the Company's
electric generating stations:
1998 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 676,989
Heskett Steam 86,000 102,000 445,417
Williston Combustion
Turbine 7,800 8,900 (79)**
South Dakota --
Big Stone* Steam 94,111 99,558 668,171
Montana --
Lewis & Clark Steam 44,000 45,200 287,591
Glendive Combustion
Turbine 34,780 31,600 15,906
Miles City Combustion
Turbine 23,150 21,400 9,204
393,488 415,408 2,103,199
* Reflects Montana-Dakota's ownership interest.
** Station use, to meet MAPP's accreditation requirements, exceeded
generation.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. See "Construction
Materials and Mining Operations and Property (Knife River) -- Coal
Operations" for a discussion 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 Westmoreland
Resources, Inc. under a contract which expires on December 31,
1999.
During the years ended December 31, 1994, through December 31,
1998, 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,
1998 1997 1996 1995 1994
Average cost of
coal per
million Btu $.93 $.95 $.93 $.94 $.97
Average cost of
coal per ton $13.67 $14.22 $13.64 $12.90 $12.88
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 412,700 kW in August 1995. The 1998 summer peak was
402,500 kW, although assuming normal weather, the 1998 summer peak
was previously forecasted to have been approximately 415,500 kW.
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 2004 will
approximate 1.5 percent annually. Montana-Dakota's latest forecast
indicates that its kilowatt-hour (kWh) sales growth rate, on a
normalized basis, through 2004 will approximate 0.9 percent
annually. Montana-Dakota currently estimates that it has adequate
capacity available through existing generating stations and long-
term firm purchase contracts until the year 2000. If additional
capacity is needed in 2000 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. Montana-
Dakota estimates this annual peak will be exceeded in the winter of
1999/2000.
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. As a result of competition in
electric generation, wholesale power markets have become
increasingly competitive and evaluations are ongoing concerning
retail competition.
In April 1996, the FERC issued a final rule (Order No. 888) on
wholesale electric transmission open access and recovery of
stranded costs. Montana-Dakota filed proposed tariffs with the
FERC in compliance with Order 888, which became effective in July
1996. Montana-Dakota is awaiting final approval of the proposed
tariffs by the FERC.
In a related matter, 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. The
FERC has requested additional information from the MAPP on its
market-based rate proposal before it will take further action.
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 WPSC 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 extensive
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 all existing environmental regulations and permitting
requirements.
The United States Clean Air Act (Clean Air Act) requires electric
generating facilities to reduce sulfur dioxide emissions by the year
2000 to a level not exceeding 1.2 pounds per million Btu.
Montana-Dakota's baseload electric generating stations are coal fired.
All of these stations, with the exception of the Big Stone Station,
are either equipped with scrubbers or utilize an atmospheric fluidized
bed combustion boiler, which permits them to operate with emission
levels less than the 1.2 pounds per million Btu. The emissions
requirement at the Big Stone Station is expected to be met by
switching to competitively priced lower sulfur ("compliance") coal.
In addition, the Clean Air Act limits the amount of nitrous oxide
emissions. Montana-Dakota's generating stations are within the
limitations set by the United States Environmental Protection Agency
(EPA).
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 evolving laws or regulations, cannot now be accurately
predicted. Montana-Dakota did not incur any significant environmental
expenditures in 1998 and does not expect to incur any significant
capital expenditures related to environmental compliance through 2001.
Retail Natural Gas and Propane Distribution
General --
Montana-Dakota sells natural gas and propane at retail, serving
over 206,000 residential, commercial and industrial customers located
in 141 communities and adjacent rural areas as of December 31, 1998,
and provides natural gas transportation services to certain customers
on its system. These services are provided through a distribution
system aggregating over 4,200 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, 1998, Montana-Dakota's net natural gas and propane
distribution plant investment approximated $79.9 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 W. T. Cunningham,
successor trustees.
The natural gas and propane distribution operations of
Montana-Dakota are subject to regulation by the NDPSC, MPSC, SDPUC and
WPSC regarding retail rates, service, accounting and, in certain
instances, security issuances. The percentage of Montana-Dakota's
1998 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,
1998 1997 1996 1995 1994
Mdk (thousands of decatherms)
Sales:
Residential 18,614 20,126 22,682 20,135 19,039
Commercial 12,458 13,799 15,325 13,509 12,403
Industrial 952 395 276 295 398
Total 32,024 34,320 38,283 33,939 31,840
Transportation:
Commercial 1,995 1,612 1,677 1,742 2,011
Industrial 8,329 8,455 7,746 9,349 7,267
Total 10,324 10,067 9,423 11,091 9,278
Total Throughput 42,348 44,387 47,706 45,030 41,118
Degree days
(% of normal) 93.7% 99.3% 116.2% 101.6% 96.7%
The restructuring of the natural gas industry, as described under
"Natural Gas Transmission Operations and Property (WBI Holdings)", 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 and capacity release contracts whereby
Montana-Dakota's interruptible customers can avail themselves of the
advantages of open access transportation on the Williston Basin
system. 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
purchase natural gas at more uniform daily volumes throughout the year
and, thus, meet winter peak requirements as well as allow it to better
manage its natural gas costs. Montana-Dakota estimates that, based on
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 generally subject to extensive federal, state and local
environmental, facility siting, zoning and planning laws and
regulations. Except as set forth below, Montana-Dakota believes it
is in substantial compliance with those regulations.
Montana-Dakota and Williston Basin discovered polychlorinated
biphenyls (PCBs) in portions of their natural gas systems and
informed the EPA in January 1991. Montana-Dakota and Williston
Basin believe the PCBs entered the system from a valve sealant. In
January 1994, Montana-Dakota, Williston Basin and Rockwell
International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell has reimbursed
and will continue to reimburse Montana-Dakota and Williston Basin
for a portion of certain remediation costs. On the basis of
findings to date, Montana-Dakota and Williston Basin estimate future
environmental assessment and remediation costs will aggregate $3
million to $15 million. Based on such estimated cost, the expected
recovery from Rockwell and the ability of Montana-Dakota and
Williston Basin to recover their portions of such costs from
ratepayers, Montana-Dakota and Williston Basin believe that the
ultimate costs related to these matters will not be material to each
of their respective financial positions or results of operations.
CENTENNIAL ENERGY HOLDINGS, INC.
NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY (WBI HOLDINGS)
General --
Williston Basin owns and operates over 3,800 miles of
transmission, gathering and storage lines and 22 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, suppliers 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. In addition, Williston Basin produces
natural gas from owned reserves which is sold to others. Williston
Basin has interconnections with seven pipelines in Wyoming, Montana
and North Dakota which provide for supply and market access.
WBI Energy Services, Inc. and its subsidiaries seek 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. In addition, WBI Energy Services,
Inc. operates two retail propane operations in north-central and
southeastern North Dakota. In 1998 the Company acquired a natural
gas marketing business in Kentucky which transacts the majority of
its business on the Texas Gas interstate pipeline system and serves
customers in the Southern and Central regions of the United States.
The Texas Gas interstate pipeline system originates in the Louisiana
Gulf Coast area and in East Texas.
At December 31, 1998, the net natural gas transmission plant
investment, inclusive of transmission, storage, gathering,
production, marketing and propane facilities, was approximately
$177.0 million.
Under the Natural Gas Act, as amended, Williston Basin is
subject to the jurisdiction of the FERC regarding certificate, rate
and accounting matters.
System Demand and Competition --
The natural gas transmission 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 essentially all of Montana-Dakota's
natural gas under firm transportation agreements, which in 1998,
represented 90 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.
For additional information regarding Williston Basin's
transportation for 1996 through 1998, see Item 7 -- "Management's
Discussion and Analysis of Financial Condition and Results of
Operations."
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.
Natural Gas Production --
Williston Basin owns in fee or holds natural gas leases and
operating rights primarily applicable to the shallow rights (above
2000 feet) in the Cedar Creek Anticline in southeastern Montana and
to all rights in the Bowdoin area located in north-central Montana.
Information on Williston Basin's natural gas production, average
sales prices and production costs per Mcf related to its natural gas
interests for 1998, 1997 and 1996 is as follows:
1998 1997 1996
Production (MMcf) 7,684 7,215 6,324
Average sales price $1.37 $1.30 $1.11
Production costs, including taxes $.38 $.46 $.43
Williston Basin's gross and net productive well counts and gross
and net developed and undeveloped acreage for its natural gas
interests at December 31, 1998, are as follows:
Gross Net
Productive Wells 576 528
Developed Acreage (000's) 234 214
Undeveloped Acreage (000's) 47 41
The following table shows the results of natural gas development
wells drilled and tested during 1998, 1997 and 1996:
1998 1997 1996
Productive 50 20 32
Dry Holes --- --- ---
Total 50 20 32
At December 31, 1998, there was one well in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 140.2 Bcf at December 31, 1998.
These amounts are supported by a report dated January 15, 1999,
prepared by Ralph E. Davis Associates, Inc., an independent firm of
petroleum and natural gas engineers.
Beginning in 1994, Williston Basin engaged in a long-term
developmental drilling program to enhance the performance of its
investment in natural gas reserves. As a result of this effort,
1998 production levels are up 91 percent since 1993. The production
increases from these reserves are expected to provide additional
natural gas supplies for WBI Energy Services, Inc. to enable it to
enhance its marketing efforts.
For additional information related to Williston Basin's natural
gas interests, see Note 18 of Notes to Consolidated Financial
Statements.
Pending 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. Oral argument
before the U.S. Court of Appeals was held September 23, 1998.
Williston Basin and the Company are awaiting a decision from the
U.S. Court of Appeals.
Williston Basin believes that it is entitled to recover from
customers virtually all of the costs which might ultimately be
incurred as a result 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 have alleged they
are entitled to damages for the breach of Williston Basin's and the
Company's contract with Koch. Williston Basin and the Company
believe that if Apache and Snyder have any legal claims, such claims
are with Koch, not with Williston Basin or the Company as Williston
Basin, the Company and Koch have settled their disputes. Apache and
Snyder have submitted damage estimates under differing theories
aggregating up to $4.8 million without interest. A motion to
intervene in the case by several other producers, all of which had
contracts with Koch but not with Williston Basin, was denied in
December 1996. The trial before the North Dakota District Court was
completed in November 1997. On November 25, 1998, the North Dakota
District Court entered an order directing the entry of judgment in
favor of Williston Basin and the Company. On December 15, 1998,
Apache and Snyder filed a motion for relief asking the North Dakota
District Court to reconsider its November 25, 1998 order. On
February 4, 1999, the North Dakota District Court denied the motion
for relief filed by Apache and Snyder.
In a related matter, in March 1997, a suit was filed by nine
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 Apache and Synder
are without merit and overstated and the claims of the nine 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.
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 prior 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. Williston Basin is awaiting
a decision from the FERC and believes that if the FERC decides to
change its prior order in a manner consistent with the D.C. Circuit
Court's suggestions, the results for the Company are expected to be
positive since Williston Basin should be entitled to seek
reimbursement from ratepayers for a portion of the refunds made in
1997 that were related to these issues.
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 resulting in an
increase of $8.9 million or 19.1 percent over the then current
effective rates. Williston Basin began collecting such increase
effective January 1, 1996, subject to refund. On July 29, 1998, the
FERC issued an order which addressed various issues including
storage cost allocations, return on equity and throughput. On
August 28, 1998, Williston Basin requested rehearing of such order.
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. Williston Basin believes that such reserves
are adequate based on its assessment of the ultimate outcome of the
various proceedings.
Natural Gas Repurchase Commitment --
The Company has offered for sale since 1984 the inventoried
natural gas owned by Frontier, a special purpose, nonaffiliated
corporation. Through an agreement, Williston Basin is obligated to
repurchase all of the natural gas at Frontier's original cost and
reimburse Frontier for all of its financing and general
administrative costs. Frontier has financed the purchase of the
natural gas under a term loan agreement with several banks. At
December 31, 1998 and 1997, borrowings totaled $14.8 million and
$32.0 million, respectively, at a weighted average interest rate of
6.19 percent and 6.63 percent, respectively. At December 31, 1998
and 1997, the natural gas repurchase commitment of $14.3 million and
$30.4 million, respectively, is reflected on the Company's
Consolidated Balance Sheets under "Other liabilities" and $551,000
and $1.6 million, respectively, is reflected under "Other accrued
liabilities." The financing costs associated with this repurchase
commitment, consisting principally of interest and related financing
fees, approximated $5.7 million in 1996. The costs incurred in 1998
and 1997 were not material and are included in "Other income -- net"
on the Consolidated Statements of Income. The term loan agreement
will terminate on October 2, 1999, subject to an option to renew
this agreement upon the lenders' consent for up to five years,
unless terminated earlier by the occurrence of certain events.
The FERC has issued orders that have held that storage costs
should be allocated to this gas, prospectively beginning May 1992,
as opposed to being included in rates applicable to Williston
Basin's customers. These storage costs, as initially allocated to
the Frontier gas, approximated $2.1 million annually, for which
Williston Basin has provided reserves. Williston Basin appealed
these orders to the D.C. Circuit Court which in December 1996 issued
its order ruling that the FERC's actions in allocating storage
capacity costs to the Frontier gas were appropriate. On August 28,
1998, Williston Basin requested rehearing of the July 29, 1998 FERC
order which addressed various issues, including a requirement that
storage deliverability costs be allocated to the Frontier gas.
Williston Basin sells and transports natural gas held under the
repurchase commitment. In the third quarter of 1996, Williston
Basin, based on a number of factors including differences in
regional natural gas prices and natural gas sales occurring at that
time, wrote down 43.0 MMdk of this gas to its then current value.
The value of this gas was determined using the sum of discounted
cash flows of expected future sales occurring at then current
regional natural gas prices as adjusted for anticipated future price
increases. This resulted in a write-down aggregating $18.6 million
($11.4 million after tax). In addition, Williston Basin wrote off
certain other costs related to this natural gas of approximately
$2.5 million ($1.5 million after tax). The amounts related to this
write-down are included in "Costs on natural gas repurchase
commitment" in the Consolidated Statements of Income. At December
31, 1998 and 1997, natural gas held under the repurchase commitment
of $6.9 million and $14.6 million, respectively, is included in the
Company's Consolidated Balance Sheets under "Deferred charges and
other assets." The amount of this natural gas in storage as of
December 31, 1998 was 7.0 MMdk.
Environmental Matters --
Williston Basin's interstate natural gas transmission
operations are generally subject to federal, state and local
environmental, facility-siting, zoning and planning laws and
regulations. Except as may be found with regard to the issues
described below, Williston Basin believes it is in substantial
compliance with those regulations.
See "Environmental Matters" under "Montana-Dakota -- Retail
Natural Gas and Propane Distribution" for a discussion of PCBs
contained in Montana-Dakota's and Williston Basin's natural gas
systems.
CONSTRUCTION MATERIALS AND MINING OPERATIONS AND PROPERTY
(KNIFE RIVER)
Construction Materials Operations:
General --
Knife River, through KRC Holdings, operates construction
materials and mining businesses in Alaska, California, Oregon and
Hawaii. 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, the Alaska, California and Oregon 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.
On March 5, 1998, the Company acquired Morse Bros., Inc. (MBI)
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. MBI sells aggregate, ready-mixed concrete,
asphaltic concrete, prestress concrete and construction services in
the Willamette Valley from Portland to Eugene. S2 - F Corp. sells
aggregate and construction services. In addition, in 1998 the
Company also acquired several smaller construction materials and
mining businesses in Oregon.
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 surface mining 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 benefit
from the Transportation Equity Act for the 21st century (TEA-21),
which was signed into law in June 1998. TEA-21 represents a 44
percent average increase in federal highway construction funding
for the six fiscal years 1998 to 2003.
The construction materials business had approximately $100
million in backlog in mid-February 1999 and anticipates that a
significant amount of the backlog will be completed during the year
ending December 31, 1999.
For information regarding sales volumes and revenues for the
construction materials operations for 1996 through 1998, see Item
7 -- "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
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 1998, 1997 and 1996, no
single customer accounted for more than 10 percent of annual
construction materials revenues.
Coal Operations:
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 2.7 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,
1998 1997 1996 1995 1994
(In thousands)
Tons sold:
Montana-Dakota generating stations 702 530 528 453 691
Jointly-owned generating stations --
Montana-Dakota's share 583 434 565 883 1,049
Others 1,749 1,303 1,695 2,767 3,358
Industrial and other sales 79 108 111 115 108
Total 3,113 2,375 2,899 4,218 5,206
Revenues $35,949 $27,906 $32,696 $39,956 $45,634
The decrease in total tons sold in 1997 compared to 1996,
reflected in the above table, is the result of lower tons sold to
the Coyote Station due to a ten-week maintenance outage. See Item
7 -- "Management's Discussion and Analysis of Financial Condition
and Results of Operations" for more information regarding the sales
volumes and revenues for the coal operations for 1996 through 1998.
Knife River's lignite coal operations are subjected to
competition from coal and other alternate fuel sources. In recent
years, in response to competitive pressures from other mines, Knife
River has limited its coal price increases to less than those
allowed under its contracts. Although Knife River has contracts in
place specifying the selling price of coal, these price concessions
are being made in an effort to remain competitive and maximize
sales. Effective January 1, 1998, Montana-Dakota and Knife River
agreed to a new five year coal contract for Montana-Dakota's Lewis
& Clark generating station. In 1998, Knife River supplied
approximately 280,000 tons of coal to this station.
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 have 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 have requested a
determination by the State District Court of the pricing mechanism
to be applied to the Agreement and have 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 are seeking 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 pricing dispute is not a proper subject for
arbitration. By an April 1997 order, the arbitration panel
concluded that the claims raised by the Co-owners are arbitrable.
The Co-owners have requested the arbitrators to make a determination
that the prices charged by Knife River were excessive and that the
Co-owners should 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 is
proceeding against Knife River. On October 9, 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. The Company is currently awaiting a decision from the
arbitration panel. Although unable to predict the outcome of the
arbitration, Knife River and the Company believe that the Co-owners'
claims are without merit and intend to vigorously defend the prices
charged pursuant to the Agreement.
Consolidated Construction Materials and Mining Operations:
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, 1998, the combined construction materials
operations had under ownership or lease approximately 655 million
tons of recoverable aggregate reserves.
As of December 31, 1998, Knife River had under ownership or
lease, reserves of approximately 190 million tons of recoverable
lignite coal, 94 million tons of which are at present mining
locations. These lignite coal reserve estimates were prepared by
Weir International Mining Consultants, independent mining engineers
and geologists, in a report dated January 1, 1999. Knife River
estimates that approximately 61 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.
OIL AND NATURAL GAS OPERATIONS AND PROPERTY (FIDELITY OIL)
General --
Fidelity Oil is involved in the acquisition, exploration,
development and production of oil and natural gas properties.
Fidelity Oil's operations vary from the acquisition of producing
properties with potential development opportunities to exploratory
drilling and are located throughout the United States, the Gulf of
Mexico and Canada. Fidelity Oil shares revenues and expenses from
the development of specified properties in proportion to its
interests.
Fidelity's oil and natural gas activities have continued to
expand since the mid-1980's. 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 Fidelity Oil's oil and natural gas production,
average sales prices and production costs per net equivalent barrel
related to its oil and natural gas interests for 1998, 1997 and
1996, are as follows:
1998 1997 1996
Oil:
Production (000's of barrels) 1,912 2,088 2,149
Average sales price $12.71 $17.50 $17.91
Natural Gas:
Production (MMcf) 13,025 13,192 14,067
Average sales price $2.07 $2.41 $2.09
Production costs, including taxes,
per net equivalent barrel $3.37 $3.65 $3.31
Well and Acreage Information --
Fidelity Oil's gross and net productive well counts and gross and
net developed and undeveloped acreage related to its interests at
December 31, 1998, are as follows:
Gross Net
Productive Wells:
Oil 2,534 172
Natural Gas 699 117
Total 3,233 289
Developed Acreage (000's) 733 74
Undeveloped Acreage (000's) 1,011 79
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1998, 1997 and 1996:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1998 2 2 4 4 --- 4 8
1997 1 2 3 3 1 4 7
1996 1 2 3 4 --- 4 7
At December 31, 1998, there were three gross wells in the
process of drilling, one of which was an exploratory well and two
of which were development wells.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 11.5 million barrels and 103.4
Bcf, respectively, at December 31, 1998.
For additional information related to Fidelity Oil's oil and
natural gas interests, see Notes 1 and 18 of Notes to Consolidated
Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
Williston Basin --
Williston Basin has been named as a defendant in a legal action
primarily related to certain natural gas price and volume issues.
Such suit was filed by W.A. Moncrief, a producer from whom Williston
Basin purchased a portion of its natural gas supply.
In addition, Williston Basin has been named as a defendant in
a legal action related to a natural gas purchase contract. Such
suit was filed by Apache Corporation and Snyder Oil Corporation.
On November 25, 1998, the North Dakota District Court entered an
order directing the entry of judgment in favor of Williston Basin
and the Company. On December 15, 1998, Apache and Snyder filed a
motion for relief asking the North Dakota District Court to
reconsider its November 25, 1998 order. On February 4, 1999, the
North Dakota District Court denied the motion for relief filed by
Apache and Snyder. In a related matter, Williston Basin has been
named in a suit filed by nine other producers.
The above legal actions are described under Items 1 and 2 --
"Business and Properties -- Natural Gas Transmission Operations and
Property (WBI Holdings)." The Company's assessment of the
proceedings are included in the descriptions of the litigation.
Knife River --
The Company and Knife River have been named as defendants in a
legal action primarily related to coal pricing issues at the Coyote
Station. On October 9, 1998, a hearing before the arbitration panel
was completed. The Company is currently awaiting a decision from
the arbitration panel. Such suit was filed by the Co-owners of the
Coyote Station.
The above legal action is described under Items 1 and 2 --
"Business and Properties -- Construction Materials and Mining
Operations and Property (Knife River)." The Company's assessment
of the proceeding is included in the respective description of the
litigation.
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 1998.
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 1998 and 1997 and dividends
declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High)* (Low)* Per Share*
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
1997
First Quarter $15.33 $14.00 $.1850
Second Quarter 16.83 14.25 .1850
Third Quarter 18.46 14.83 .1917
Fourth Quarter 22.33 17.75 .1917
$.7534
* Reflects the Company's three-for-two common stock split effected
in July 1998.
As of December 31, 1998, the Company's common stock was held by
approximately 13,900 stockholders of record.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 52 and 53
of the Company's Annual Report which is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For purposes of segment financial reporting and discussion of
results of operations, electric includes the electric operations of
Montana-Dakota, as well as the operations of Utility Services.
Natural gas distribution includes Montana-Dakota's natural gas
distribution operations. Natural gas transmission includes WBI
Holdings' storage, transportation, gathering, natural gas production
and energy marketing operations. Construction materials and mining
includes the results of Knife River's operations, while oil and
natural gas production includes the operations of Fidelity Oil.
Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of the
Company's businesses.
Years ended December 31,
1998 1997 1996
Electric $ 17.2 $13.4 $11.4
Natural gas distribution 3.5 4.5 4.9
Natural gas transmission 20.8 11.3 2.5
Construction materials and mining 24.5 10.1 11.5
Oil and natural gas production (32.7) 14.5 14.4
Earnings on common stock $ 33.3 $53.8 $44.7
Earnings per common share - basic* $ .66 $1.24 $1.05
Earnings per common share - diluted* $ .66 $1.24 $1.04
Return on average common equity 6.5% 14.6% 13.0%
* Reflects the Company's three-for-two common stock split effected
in July 1998.
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 $39.9 million
in noncash after-tax 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 the construction
materials and mining, natural gas transmission and electric
businesses partially offset the earnings decrease.
1997 compared to 1996
Consolidated earnings for 1997 increased $9.1 million when
compared to 1996. This increase includes the effect of the one-time
adjustment in the third quarter of 1996 of $3.7 million or 9 cents
per common share, reflecting the write-down to market value of
natural gas being held under a repurchase commitment and certain
reserve adjustments. The improvement is attributable to increased
earnings from the natural gas transmission, electric, and oil and
natural gas production businesses, partially offset by a decrease in
construction materials and mining, and natural gas distribution
earnings.
________________________________
Reference should be made to Items 1 and 2 -- "Business and
Properties" 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 units. Certain reclassifications have been made in the
following statistics for prior years to conform to the current
presentation. Such reclassifications had no effect on net income or
common stockholders' equity as previously reported.
Electric Operations
Years ended December 31,
1998 1997 1996
Operating revenues:
Retail sales $ 130.9 $ 130.3 $ 128.8
Sales for resale and other 16.4 11.3 10.0
Utility services 64.2 22.8 ---
211.5 164.4 138.8
Operating expenses:
Fuel and purchased power 49.8 45.6 44.0
Operation and maintenance 94.5 60.1 41.4
Depreciation, depletion and
amortization 19.8 17.8 17.1
Taxes, other than income 9.3 7.8 6.8
173.4 131.3 109.3
Operating income $ 38.1 $ 33.1 $ 29.5
Retail sales (million kWh) 2,053.9 2,041.2 2,067.9
Sales for resale (million kWh) 586.5 361.9 374.6
Average cost of fuel and
purchased power per kWh $ .017 $ .018 $ .017
Natural Gas Distribution Operations
Years ended December 31,
1998 1997 1996
Operating revenues:
Sales $ 150.6 $ 153.6 $ 151.5
Transportation and other 3.5 3.4 3.5
154.1 157.0 155.0
Operating expenses:
Purchased natural gas sold 106.5 107.2 102.7
Operation and maintenance 28.5 28.5 30.0
Depreciation, depletion and
amortization 7.1 7.0 6.9
Taxes, other than income 4.0 3.9 3.9
146.1 146.6 143.5
Operating income $ 8.0 $ 10.4 $ 11.5
Volumes (MMdk):
Sales 32.0 34.3 38.3
Transportation 10.3 10.1 9.4
Total throughput 42.3 44.4 47.7
Degree days (% of normal) 93.7% 99.3% 116.2%
Average cost of natural gas,
including transportation,
per dk $ 3.33 $ 3.12 $ 2.67
Natural Gas Transmission Operations
Years ended December 31,
1998 1997 1996
Operating revenues:
Transportation and storage $ 60.8 $ 60.1* $ 71.6*
Energy marketing and
natural gas production 119.9 33.3 7.0
180.7 93.4 78.6
Operating expenses:
Purchased natural gas sold 99.8 17.9 ---
Operation and maintenance 29.0 35.5* 37.2*
Depreciation, depletion and
amortization 8.5 5.5 6.7
Taxes, other than income 5.3 5.3 4.5
142.6 64.2 48.4
Operating income $ 38.1 $ 29.2 $ 30.2
Transportation volumes (MMdk):
Montana-Dakota 32.2 35.5 43.4
Other 56.8 50.0 38.8
89.0 85.5 82.2
Produced (Mdk) 7,412 6,949 6,073
* Includes $5.5 million and $10.6 million for 1997 and 1996 respectively, of
amortization and related recovery of deferred natural gas contract buy-
out/buy-down and gas supply realignment costs.
Construction Materials and Mining Operations**
Years ended December 31,
1998 1997 1996
Operating revenues:
Construction materials $ 310.5 $ 146.2 $ 99.5
Coal 35.9 27.9 32.7
346.4 174.1 132.2
Operating expenses:
Operation and maintenance 280.7 145.6 105.8
Depreciation, depletion and
amortization 20.6 11.0 7.0
Taxes, other than income 3.5 2.9 3.3
304.8 159.5 116.1
Operating income $ 41.6 $ 14.6 $ 16.1
Sales (000's):
Aggregates (tons) 11,054 5,113 3,374
Asphalt (tons) 1,790 758 694
Ready-mixed concrete
(cubic yards) 1,021 516 340
Coal (tons) 3,113 2,375 2,899
** 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.
Oil and Natural Gas Production Operations
Years ended December 31,
1998 1997 1996
Operating revenues:
Oil $ 24.3 $ 36.6 $ 39.0
Natural gas 27.0 31.8 29.3
51.3 68.4 68.3
Operating expenses:
Operation and maintenance 15.6 15.8 15.6
Depreciation, depletion and
amortization 21.8 24.4 25.0
Taxes, other than income 2.8 3.9 3.5
Write-downs of oil and
natural gas properties 66.0 --- ---
106.2 44.1 44.1
Operating income (loss) $ (54.9) $ 24.3 $ 24.2
Production:
Oil (000's of barrels) 1,912 2,088 2,149
Natural gas (MMcf) 13,025 13,192 14,067
Average sales price:
Oil (per barrel) $ 12.71 $ 17.50 $ 17.91
Natural gas (per Mcf) $ 2.07 $ 2.41 $ 2.09
Amounts presented in the preceding tables for natural gas
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 Montana-Dakota's natural gas distribution business and WBI
Holdings' natural gas transmission business. The amounts relating
to the elimination of intercompany transactions for natural gas
operating revenues and purchased natural gas sold were $47.4 million
for 1998. The amounts relating to the elimination of intercompany
transactions for natural gas operating revenues, purchased natural
gas sold and operation and maintenance expenses were $49.6 million,
$48.0 million and $1.6 million, respectively, for 1997, and $58.2
million, $53.8 million and $4.4 million, respectively, for 1996.
1998 compared to 1997
Electric Operations
Electric earnings increased due to earnings at the utility
services companies acquired since mid-1997 and increased electric
utility earnings. 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 electric utility earnings improvement. Depreciation
expense increased due to higher average depreciable plant, also
partially offsetting the increase in earnings. Utility services
contributed $3.3 million to earnings in 1998.
Natural Gas Distribution Operations
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.
Natural Gas Transmission Operations
Earnings at the natural gas transmission business increased due
to increases in transportation revenues resulting from a $5.0
million ($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. Increased average prices and production from company-
owned natural gas reserves added to the earnings improvement. 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 marketing revenue and the
related increase in purchased gas sold resulted from the acquisition
of a natural gas marketing business in July 1998.
Construction Materials and Mining Operations
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.
Oil and Natural Gas Production Operations
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 14 percent lower than
last year, respectively, and slightly lower production. Decreased
depreciation, depletion and amortization due to lower rates
resulting from the aforementioned write-downs and lower production
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.
1997 compared to 1996
Electric Operations
Higher wholesale electric sales margins, increased average
realized retail rates and revenues from the July 1997 acquisition of
two utility services companies improved operating revenues.
However, decreased retail sales due to warmer fourth quarter weather
somewhat offset the improvement. Operating expenses increased due
to the above-mentioned acquisitions, costs associated with a
planned, but extended, maintenance outage at the Coyote Station and
repairs from an April blizzard. Lower payroll and benefit-related
expenses somewhat offset the operating expense increase. Higher
revenues more than offset the operating expense increase leading to
improved operating income. Earnings increased due to the operating
income increase partially offset by higher interest expense due to
higher average short-term debt balances. Utility services
contributed $1.0 million to 1997 earnings.
Natural Gas Distribution Operations
Revenues from the positive effects of a rate change implemented
in Montana in May 1996 and reduced operations expense from lower
payroll and benefit-related costs did not fully offset reduced
natural gas sales caused by 15 percent warmer weather than 1996.
The pass-through of higher average gas costs more than offset the
revenue decline resulting from the reduced sales. Increased
transportation volumes, primarily to large industrial customers,
were offset by lower average transportation rates. These factors
reduced operating income and earnings. Lower net interest expense
and increased returns on gas storage and prepaid demand balances
partially offset the earnings decline.
Natural Gas Transmission Operations
Increased transportation volumes, higher production from
company-owned wells, and increased natural gas prices and sales
volumes from the energy marketing operations, improved revenues.
The reversal of certain reserves for regulatory contingencies in
1996 of $2.6 million after tax and lower average transportation
rates partially offset the revenue improvement. Higher royalty
expenses and increased taxes other than income added to the
operating income decrease. Earnings improved $8.8 million compared
to 1996, due to the absence of the 1996 $12.9 million after-tax
write-down to the then current market price of the natural gas
available under the repurchase commitment and lower costs in 1997
associated with this natural gas. The 1996 reversal of certain
income tax reserves aggregating $4.8 million partially offset the
1997 earnings improvement.
Construction Materials and Mining Operations
Construction materials revenues improved primarily due to the
acquisition of several construction materials businesses in mid-1996
and in 1997, combined with improved aggregate and ready-mixed
concrete sales volumes, increased construction revenues and higher
asphalt prices. However, lower coal sales due to planned but
extended maintenance at the Coyote Station partially offset the
revenue improvement. Operating costs associated with the
acquisitions, higher construction materials volumes and higher
stripping costs at the coal operations reduced operating income.
These factors, combined with higher interest expense resulting
mainly from increased acquisition-related long-term debt, decreased
earnings from this business unit.
Oil and Natural Gas Production Operations
Slightly higher operating revenues due to higher natural gas
prices, largely offset by lower natural gas production and slightly
lower oil production and decreased oil prices, added to the
operating income improvement. Total operating expenses remained
unchanged as lower volume-related expenses were largely offset by
increased taxes other than income. Overall, earnings increased from
slightly higher operating income and decreased net interest expense
from lower average long-term debt balances. Increased income taxes
from the reversal of certain tax reserves aggregating $1.8 million
in 1996, somewhat offset by higher tax credits in 1997, partially
offset the earnings improvement.
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.
Regulated Operations --
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the Company and its regulated operations 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, wholesale and retail competition (including but not
limited to electric retail wheeling and transmission costs),
availability of economic supplies of natural gas, and present or
prospective natural gas distribution or transmission competition
(including but not limited to prices of alternate fuels and system
deliverability costs).
Nonregulated Operations --
Certain important factors which could cause actual results or
outcomes for the Company and all or certain of its nonregulated
operations to differ materially from those discussed in forward-
looking statements include the level of governmental expenditures on
public projects and project schedules, changes in anticipated
tourism levels, competition from other suppliers, 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.
Factors Common to Regulated and Nonregulated Operations --
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, 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.
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
includes 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's year 2000 plan is based upon a six-phase
approach involving awareness, inventory, assessment, remediation,
testing and implementation.
State of Readiness --
The Company is conducting a corporate-wide awareness program,
compiling an inventory of IT and non-IT systems, and assigning
priorities to such systems. As of December 31, 1998, the awareness
and inventory phases, including assigning priorities to IT and non-
IT systems, have been substantially completed.
The assessment phase involves the review of each inventory item
for year 2000 compliance and efforts to obtain representations and
assurances from third parties, including suppliers, vendors and
major customers, that such entities are year 2000 compliant. As of
December 31, 1998, based on contacts with and representations
obtained from third parties to date, the Company is not aware of any
material third party year 2000 problems. The Company will continue
to contact third parties seeking written verification of year 2000
readiness. Thus, the Company is presently unable to determine the
potential adverse consequences, if any, that could result from each
such entities' failure to effectively address the year 2000 issue.
As of December 31, 1998, the assessment phase, as it relates to the
Company's review of its inventory items, has been substantially
completed.
The remediation, testing and implementation phases of the
Company's year 2000 plan are currently in various stages of
completion. The remediation phase includes replacements,
modifications and/or upgrades necessary for year 2000 compliance
that were identified in the assessment phase. As of December 31,
1998, the remediation phase at the oil and natural gas production
business is substantially complete; at the electric, natural gas
distribution and natural gas transmission businesses the remediation
phase is more than 75 percent complete; and at the construction
materials and mining business it is approximately 35 percent
complete. The testing phase involves testing systems to confirm
year 2000 readiness. As of December 31, 1998, the testing phase at
the oil and natural gas production business is substantially
complete; at the electric and natural gas distribution businesses
the testing phase is over 50 percent complete; at the natural gas
transmission business it is over 10 percent complete; and at the
construction materials and mining business it is approximately 20
percent complete. The implementation phase is the process of moving
a remediated item into production status. As of December 31, 1998,
the implementation phase at the oil and natural gas production business
is substantially complete; at the electric and natural gas
distribution businesses the implementation phase is more than 80
percent complete; at the natural gas transmission business it is
more than 65 percent complete; and at the construction materials and
mining business it is approximately 35 percent complete. The
Company has established a target date of October 1, 1999, to
complete the remediation, testing and implementation phases.
Costs --
The estimated total incremental cost to the Company of the year
2000 issue is approximately $1 million to $3 million during the 1998
through 2000 time periods. As of December 31, 1998, the Company has
incurred incremental costs of less than $300,000. These costs are
being funded through cash flows from operations. The Company's
current estimate of costs of the year 2000 issue is based on the
facts and circumstances existing at this time, which were derived
utilizing numerous assumptions of future events.
Risks --
The failure to correct a material year 2000 problem, including
failures on the part of third parties, could result in a temporary
interruption in, or failure of, certain critical business
operations, including electric distribution, generation and
transmission; natural gas distribution, transmission, storage and
gathering; energy marketing; mining and marketing of coal,
aggregates and related construction materials; oil and natural gas
exploration, production, and development; and utility line
construction and repair services. Although the Company believes
the project will be completed by October 1, 1999, unforeseen and
other factors could cause delays in the project, the results of
which could have a material effect on the results of operations and
the Company's ability to conduct its business.
Contingency Planning --
Due to the general uncertainty inherent in the year 2000 issue,
including the uncertainty of the year 2000 readiness of third
parties, the Company is developing contingency plans for its
mission-critical operations. As of December 31, 1998, the utility
division, which includes electric generation and transmission and
electric and natural gas distribution, has prepared preliminary
contingency plans in accordance with guidelines and schedules set
forth by the North American Electric Reliability Council working in
conjunction with the Mid-Continent Area Power Pool, the utility's
regional reliability council. Such plans are in addition to
existing business recovery and emergency plans established to
restore electric and natural gas service following an interruption
caused by weather or equipment failure. The natural gas
transmission business has adopted the guidelines used at the utility
and has materially completed plans for its administrative and
accounting systems. The contingency plans for its other business
operations are in the development stage. The oil and natural gas
production and the construction materials and mining businesses are
in various stages of their contingency planning efforts. Contingency
plans will continue to be developed and finalized and the Company
anticipates having all such contingency plans in place by October 1,
1999.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133). For
further information on SFAS No. 133, see Note 1 of Notes to
Consolidated Financial Statements.
Liquidity and Capital Commitments
The Company's capital expenditures (in millions of dollars) for
1996 through 1998 and as anticipated for 1999 through 2001 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*
1996 1997 1998 Capital Expenditures: 1999 2000 2001
$ 18.7 $ 28.0 $ 31.3 Electric $ 19.0 $ 15.3 $ 21.7
6.3 8.8 8.3 Natural gas distribution 11.1 7.0 8.3
10.9 13.2 23.7 Natural gas transmission 30.2 19.5 14.4
Construction materials
25.0 41.5 172.1 and mining 43.8 31.4 22.3
Oil and natural gas
51.8 30.6 94.5 production 55.5 52.0 102.0
112.7 122.1 329.9 159.6 125.2 168.7
Net proceeds from sale or
(11.8) (4.5) (4.3) disposition of property (6.4) (1.5) (1.7)
100.9 117.6 325.6 Net capital expenditures 153.2 123.7 167.0
Retirement of long-term
43.4 48.0 113.7 debt and preferred stock 3.3 12.5 100.4
$144.3 $165.6 $439.3 $156.5 $136.2 $267.4
* The anticipated 1999 through 2001 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 1998 and 1997, related to acquisitions,
in the above table include the following noncash transactions:
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 addition, natural gas transmission capital
expenditures for 1996 include $800,000 for Prairielands Energy
Marketing, Inc., which were not reflected in investing activities in
the Consolidated Statements of Cash Flows as Prairielands Energy
Marketing, Inc. was not considered a major business segment.
The 1998 electric and natural gas distribution capital
expenditures, including those for 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.
Electric and natural gas distribution capital expenditures for the
years 1999 through 2001, excluding those for potential acquisitions,
include those for system upgrades, routine replacements, service
extensions and routine equipment maintenance and replacements. It
is anticipated that all of the funds required for capital
expenditures and retirements of long-term debt and preferred stock
for the years 1999 through 2001 will be met from various sources.
These sources include internally generated funds, the Company's $40
million revolving credit and term loan agreement, existing short-
term lines of credit aggregating $50 million, a commercial paper
credit facility at Centennial, as described below, and through the
issuance of long-term debt, the amount and timing of which will
depend upon needs, internal cash generation and market conditions.
At December 31, 1998, $40 million under the revolving credit and
term loan agreement and $15 million of commercial paper supported by
the short-term lines of credit were outstanding. In May 1998, the
Company redeemed $20 million of its 9 1/8 percent Series first
mortgage bonds, due May 15, 2006. In September 1998, the Company
issued $15 million of its 5.83 percent Secured Medium-Term Notes due
October 1, 2008.
Capital expenditures in 1998 for the natural gas transmission
business, including those expended for acquisitions, and long-term
debt retirements were met through internally generated funds and the
issuance of the Company's equity securities. Natural gas
transmission capital expenditures for the years 1999 through 2001,
excluding potential acquisitions, include those for pipeline
expansion projects, routine system improvements and continued
development of natural gas reserves. Capital expenditures and long-
term debt retirements for the years 1999 through 2001 are expected
to be met with a combination of internally generated funds, a
commercial paper credit facility at Centennial, as described below,
and through the issuance of long-term debt, the amount and timing of
which will depend upon needs, internal cash generation and market
conditions.
The construction materials and mining 1998 capital expenditures,
including acquisitions, and long-term debt retirements were met
through funds generated from internal sources, a revolving credit
agreement, the issuance of long-term debt and the Company's equity
securities. Construction materials and mining capital expenditures
for the years 1999 through 2001, excluding potential acquisitions,
include routine equipment rebuilding and replacement and the
building of construction materials handling and transportation
facilities. It is anticipated that funds generated from internal
sources, a commercial paper credit facility at Centennial, as
described below, lines of credit aggregating $10 million, $5.2
million of which was outstanding at December 31, 1998, and the
issuance of long-term debt and the Company's equity securities will
meet the needs of this segment for 1999 through 2001. In October
1998, $55 million of notes were privately placed with the proceeds
used to replace other long-term debt.
Capital expenditures in 1998 for the oil and natural gas
production business related to its oil and natural gas acquisition,
development and exploration program were met through funds generated
from internal sources and the issuance of long-term debt and the
Company's equity securities. The capital expenditures for 1999
through 2001 for the oil and natural gas production business will be
used to further enhance production and reserve growth. It is
anticipated that capital expenditures and long-term debt retirements
will be met from internal sources, a $30 million note shelf
facility, $16 million of which was outstanding at December 31, 1998,
a commercial paper credit facility at Centennial, as described
below, and the issuance of the Company's equity securities.
During 1998, Centennial, a direct subsidiary of the Company,
entered into a revolving credit agreement with various banks on
behalf of its subsidiaries that allows for borrowings of up to $200
million. This facility supports the Centennial commercial paper
program. Under the commercial paper program, $82.9 million was
outstanding at December 31, 1998. 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 on
November 29, 2001.
In April 1998, the Company received proceeds of $30.1 million
from a public stock offering. The proceeds from the sale of this
stock were used for refunding of outstanding debt obligations, for
corporate development purposes (including the acquisitions of
businesses and/or business assets), and for other general corporate
purposes.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the Trustee for each
dollar of indebtedness incurred under the Indenture and that annual
earnings (pretax and before interest charges), as defined in the
Indenture, equal at least two times its annualized first mortgage
bond interest costs. Under the more restrictive of the two tests,
as of December 31, 1998, the Company could have issued approximately
$273 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.5 and 3.4 times for 1998 and 1997, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 6.1 times in 1998 compared to 6.0 times in 1997. Common
stockholders' equity as a percent of total capitalization was 56
percent and 55 percent at December 31, 1998 and 1997, respectively.
Effects of Inflation
Inflation did not have a significant effect on the Company's
operations in 1998, 1997 or 1996.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk --
Fidelity Oil has entered into certain price collar agreements to
manage a portion of the market risk associated with fluctuations in
the price of natural gas. The collar agreements call for Fidelity Oil
to receive monthly payments from counterparties when the settlement
price is below the floor price in the collar agreement or make monthly
payments to counterparties when the settlement price is above the
ceiling price in the collar agreement. These payments are based upon
the difference between a fixed and a variable price as specified by
the agreements. The variable price is a quoted natural gas price on
the New York Mercantile Exchange. The following table presents
natural gas collar information for outstanding agreements as of
December 31, 1998. The fair value of these collar agreements 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 these
collar agreements are expected to be generally offset by corresponding
increases and decreases in the value of the underlying commodity
transactions.
Notional Weighted Average
Amount Fixed Price
(MMBtu's) Floor Ceiling Fair Value
(Notional amount and fair value in thousands)
Natural gas collar agreements:
Maturing in 1999 2,920 $2.10 $2.51 $597
These collar agreements are not held for trading purposes. 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 these collar agreements in the event of
nonperformance by counterparties, but does not expect any
counterparties to fail to meet their obligations given their existing
credit ratings.
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 17,000
shares of 5.10% Series preferred stock subject to mandatory redemption
as of December 31, 1998. 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, 1998. Weighted average variable rates are based on
forward rates as of December 31, 1998.
Fair
1999 2000 2001 2002 2003 Thereafter Total Value
(Dollars in millions)
Long-term debt:
Fixed rate $3.2 $12.4 $12.2 $49.4 $6.4 $244.8 $328.4 $343.7
Weighted average
interest rate 8.3% 7.9% 7.4% 7.0% 6.9% 7.3% 7.3% ---
Variable rate --- --- $88.1 --- --- --- $88.1 $91.4
Weighted average
interest rate --- --- 5.1% --- --- --- 5.1% ---
Preferred stock
subject to mandatory
redemption $.1 $.1 $.1 $.1 $.1 $1.2 $1.7 $1.6
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 4 of Notes to Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 25 through 51 of the Annual Report.
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 16 and 17 of the
Company's Proxy Statement dated March 15, 1999 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 9 through 16 of the Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 18 of the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits.
Index to Financial Statements and Financial Statement
Schedules
Page
1. Financial Statements:
Report of Independent Public Accountants *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 1998 *
Consolidated Balance Sheets at December 31,
1998 and 1997 *
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 1998 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1998 *
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.)
____________________
* The Consolidated Financial Statements listed in the above index
which are included in the Company's Annual Report to Stockholders
for 1998 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 1998 is not to be
deemed filed as part of this report.
3. Exhibits:
3(a) Composite Certificate of Incorporation of
the Company, as amended to date, filed as
Exhibit 3(a) to Form 10-K for the year
ended December 31, 1994, 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 (W. T. Cunningham, 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 **
+ 10(b) Key Employee Stock Option Plan,
as amended to date **
+ 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 **
+ 10(e) Deferred Compensation Plan for Directors,
as amended to date **
+ 10(f) Non-Employee Director Stock Compensation
Plan, as amended to date **
+ 10(g) 1997 Non-Employee Director Long-Term Incentive
Plan, as amended to date **
+ 10(h) 1997 Executive Long-Term Incentive Plan, as
amended to date **
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1998 **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Consent of Independent Public Accountants **
23(b) Consent of Engineer **
23(c) Consent of Engineer **
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 December 1, 1998. Under Item 5--Other
Events, the Company declared a dividend distribution of one
Preference Share Purchase Right on each outstanding share of
MDU Resources' Common Stock pursuant to a newly-adopted rights
agreement. The new agreement replaced the previous rights
agreement.
Form 8-K was filed on January 13, 1999. Under Item 5--Other
Events, the Company announced recent acquisitions. It was also
reported that because of low oil and natural gas prices fourth
quarter earnings would include a non-cash after-tax charge of
approximately $20 million.
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 4, 1999 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 4, 1999
Martin A. White Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief March 4, 1999
Douglas C. Kane (Executive Vice President, Administrative &
Chief Administrative & Corporate Corporate
Development Officer) Development Officer
and Director
/s/ Warren L. Robinson Chief Financial March 4, 1999
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting March 4, 1999
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director March 4, 1999
John A. Schuchart (Chairman of the Board)
Director
San W. Orr, Jr. (Vice Chairman of the Board)
/s/ Thomas Everist Director March 4, 1999
Thomas Everist
Director
Harold J. Mellen, Jr.
/s/ Richard L. Muus Director March 4, 1999
Richard L. Muus
/s/ Robert L. Nance Director March 4, 1999
Robert L. Nance
/s/ John L. Olson Director March 4, 1999
John L. Olson
Director
Harry J. Pearce
/s/ Homer A. Scott, Jr. Director March 4, 1999
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director March 4, 1999
Joseph T. Simmons
/s/ Sister Thomas Welder Director March 4, 1999
Sister Thomas Welder
EXHIBIT INDEX
Exhibit No.
3(a) Composite Certificate of Incorporation
of the Company, as amended to date, filed as
Exhibit 3(a) to Form 10-K for the year ended
December 31, 1994, 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 (W. T. Cunningham, 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 **
+ 10(b) Key Employee Stock Option Plan,
as amended to date **
+ 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 **
+ 10(e) Deferred Compensation Plan for Directors,
as amended to date **
+ 10(f) Non-Employee Director Stock Compensation
Plan, as amended to date **
+ 10(g) 1997 Non-Employee Director Long-Term Incentive
Plan, as amended to date **
+ 10(h) 1997 Executive Long-Term Incentive Plan, as
amended to date **
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial statements
and supplementary data as contained in the
Annual Report to Stockholders for 1998 **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Consent of Independent Public Accountants **
23(b) Consent of Engineer **
23(c) Consent of Engineer **
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.