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, 1997
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 58501
Bismarck, North Dakota (Zip Code)
(Address of principal executive offices)
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 27, 1998: $901,622,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 27, 1998: 29,143,332 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 25 through 51 of the Annual Report to Stockholders for 1997,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 9, 1998, 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
Williston Basin Interstate Pipeline Company
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, Bismarck, North Dakota
58501, telephone (701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), the public
utility division of the Company, provides electric and/or natural
gas and propane distribution service at retail to 256 communities
in North Dakota, eastern Montana, northern and western South Dakota
and northern Wyoming, and owns and operates electric power
generation and transmission facilities.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns Williston Basin Interstate
Pipeline Company (Williston Basin), Knife River Corporation (Knife
River), the Fidelity Oil Group (Fidelity Oil) and Utility Services,
Inc. (Utility Services).
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 and, through its wholly owned subsidiary,
Prairielands Energy Marketing, Inc. (Prairielands), seeks new
energy markets while continuing to expand present markets for
natural gas and propane.
Knife River, through its wholly owned subsidiary, KRC
Holdings, Inc. (KRC Holdings) and its subsidiaries, surface mines
and markets aggregates and related construction materials in
Alaska, California, Hawaii and Oregon. In addition, Knife River
surface mines and markets low sulfur lignite coal at mines located
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 through investments with several oil and natural gas
producers.
Utility Services, through its wholly owned subsidiaries,
International Line Builders, Inc. and High Line Equipment, Inc.,
both acquired on July 1, 1997, installs and repairs electric
transmission and distribution power lines in the western United
States and Hawaii and provides related supplies and equipment.
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, 1997, the Company had 2,218 full-time
employees with 84 employed at MDU Resources Group, Inc., including
Fidelity Oil, 1,011 at Montana-Dakota, 292 at Williston Basin,
including Prairielands, 522 at Knife River's construction materials
operations, 147 at Knife River's coal operations and 162 at Utility
Services. Approximately 501 and 83 of the Montana-Dakota and
Williston Basin employees, respectively, are represented by the
International Brotherhood of Electrical Workers (IBEW). Labor
contracts with such employees are in effect through May 1999, for
both Montana-Dakota and Williston Basin. Knife River has a labor
contract through August 1998, with the United Mine Workers of
America, which represents its coal operation's hourly workforce
aggregating 90 employees. In addition, Knife River has 14 labor
contracts which represent 243 of its construction materials
employees. Utility Services has 2 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 49 in the
Company's Annual Report to Stockholders for 1997 (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 113,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as of
December 31, 1997. 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. As of
December 31, 1997, Montana-Dakota's net electric plant investment
approximated $283.9 million.
All of Montana-Dakota's electric properties, with certain
exceptions, are subject to the lien of the Indenture of Mortgage
dated May 1, 1939, as supplemented, amended and restated, from the
Company to The Bank of New York and 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 1997 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 421,060 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:
1997 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 507,714
Heskett Steam 86,000 102,000 369,791
Williston Combustion
Turbine 7,800 8,900 (62)**
South Dakota --
Big Stone* Steam 94,111 101,460 741,280
Montana --
Lewis & Clark Steam 44,000 49,150 184,408
Glendive Combustion
Turbine 34,780 31,200 13,484
Miles City Combustion
Turbine 23,150 21,600 10,155
393,488 421,060 1,826,770
* 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, 1993, through December 31,
1997, 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,
1997 1996 1995 1994 1993
Average cost of
coal per
million Btu $.95 $.93 $.94 $.97 $.96
Average cost of
coal per ton $14.22 $13.64 $12.90 $12.88 $12.78
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. Due to a cooler than normal
summer, the 1997 summer peak was only 404,566 kW. The 1997 summer
peak, assuming normal weather, was previously forecasted to have
been approximately 416,600 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 2003 will approximate 1.3 percent annually. Montana-
Dakota's latest forecast indicates that its kilowatt-hour (kWh)
sales growth rate, on a normalized basis, through 2003 will
approximate 1.0 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. Due to a
peak shaving load management system, Montana-Dakota estimates this
annual peak will not be exceeded through 1999.
The Sheridan System is supplied through an interconnection with
Black Hills Power and Light Company under a ten-year power supply
contract 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 its final rules (Order No. 888
and 889) 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 December 1996, Montana-Dakota
filed a Request for Waiver of the requirements of FERC Order No.
889 as it relates to the Standards of Conduct. The Standards of
Conduct require companies to physically separate their transmission
operations/reliability functions from their marketing/merchant
functions. On May 29, 1997, Montana-Dakota's request was granted.
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.
Three of the four states which regulate the Company's electric
operations continue to evaluate and/or implement utility
regulations with respect to retail competition (retail wheeling).
Additionally, federal legislation addressing this issue has been
introduced. In April 1997, the Montana legislature passed an
electric industry restructuring bill. 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; however, the WPSC is continuing to evaluate the
economic impact of retail wheeling on the State of Wyoming. The
SDPUC has not initiated any proceedings to date concerning retail
competition or electric industry restructuring.
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 as well as
changes in load management costs. In Montana (22 percent of
electric revenues), such cost changes are includible in general
rate filings.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1997 actual and 1998 through 2000 anticipated net capital
expenditures applicable to Montana-Dakota's electric operations:
Actual Estimated
1997 1998 1999 2000
Production $ 4.7 $ 5.8 $ 5.5 $ 5.9
Transmission 2.6 2.8 2.7 2.9
Distribution, General
and Common 11.4 9.0 8.2 8.2
$18.7 $17.6 $16.4 $17.0
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 U.S. 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, with the exception
of the Big Stone Station, are within the limitations set by the United
States Environmental Protection Agency (EPA). The co-owners of the
Big Stone Station have determined the modifications necessary at the
Big Stone Station. Montana-Dakota believes that the cost of such
modifications will not have a material effect on its results of
operations.
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 1997 and does not expect to incur any significant
capital expenditures related to environmental compliance through 2000.
Retail Natural Gas and Propane Distribution
General --
Montana-Dakota sells natural gas and propane at retail, serving
over 200,000 residential, commercial and industrial customers located
in 141 communities and adjacent rural areas as of December 31, 1997,
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,
1997, Montana-Dakota's net natural gas and propane distribution plant
investment approximated $79.5 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
1997 natural gas and propane utility operating revenues by
jurisdiction is as follows: North Dakota -- 43 percent; Montana --
29 percent; South Dakota -- 21 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 and natural gas transportation volumes during the last
five years:
Years Ended December 31,
1997 1996 1995 1994 1993
Mdk (thousands of decatherms)
Sales:
Residential 20,126 22,682 20,135 19,039 19,565
Commercial 13,799 15,325 13,509 12,403 11,196
Industrial 395 276 295 398 386
Total 34,320 38,283 33,939 31,840 31,147
Transportation:
Commercial 1,612 1,677 1,742 2,011 3,461
Industrial 8,455 7,746 9,349 7,267 9,243
Total 10,067 9,423 11,091 9,278 12,704
Total Throughput 44,387 47,706 45,030 41,118 43,851
The restructuring of the natural gas industry, as described under
"Natural Gas Transmission Operations and Property (Williston Basin)",
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 all of its system requirements directly
from producers, processors and marketers. Such natural gas is
supplied under firm contracts, specifying market-based pricing, and
is transported under firm transportation agreements by Williston Basin
and Northern Gas Company and, with respect to Montana-Dakota's north-
central South Dakota and south-central North Dakota markets, by South
Dakota Intrastate Pipeline Company and Northern Border Pipeline
Company, respectively. 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.
Capital Requirements --
Montana-Dakota's net capital expenditures aggregated $7.7 million
for natural gas and propane distribution facilities in 1997 and are
anticipated to be approximately $7.7 million, $8.8 million and $7.5
million in 1998, 1999 and 2000, respectively.
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 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 (WILLISTON BASIN)
General --
Williston Basin owns and operates over 3,600 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 or used by
Williston Basin for its operating needs. Williston Basin has
interconnections with seven pipelines in Wyoming, Montana and North
Dakota which provide for supply and market access.
Prairielands, a subsidiary of Williston Basin, seeks new energy
markets while continuing to expand present markets for natural gas.
Its activities include buying and selling natural gas and arranging
transportation services to end users, pipelines and local
distribution companies. In addition, Prairielands operates two
retail propane operations in north central and southeastern North
Dakota.
At December 31, 1997, the net natural gas transmission plant
investment, inclusive of its transmission, storage, gathering,
production, marketing and propane facilities, was approximately
$167.5 million.
Under the Natural Gas Act (NGA), as amended, Williston Basin is
subject to the jurisdiction of the FERC regarding certificate, rate
and accounting matters applicable to natural gas purchases, sales,
transportation, gathering and related storage operations.
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 1997,
represented 87 percent of Williston Basin's currently subscribed
firm transportation capacity. In November 1996, Montana-Dakota
executed a new firm transportation agreement with Williston Basin
for a term of five years which began in July 1997. In addition, in
July 1995, Montana-Dakota entered 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 1995 through 1997, 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
2,000 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 1997, 1996 and 1995 is as follows:
1997 1996 1995
Production (MMcf) 7,215 6,324 5,184
Average sales price $1.30 $1.11 $.91
Production costs, including taxes $.46 $.43 $.30
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, 1997, are as follows:
Gross Net
Productive Wells 533 483
Developed Acreage (000's) 234 213
Undeveloped Acreage (000's) 45 40
The following table shows the results of natural gas development
wells drilled and tested during 1997, 1996 and 1995:
1997 1996 1995
Productive 20 32 17
Dry Holes --- --- ---
Total 20 32 17
At December 31, 1997, there were no wells in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 127.3 Bcf at December 31, 1997.
These amounts are supported by a report dated January 12, 1998,
prepared by Ralph E. Davis Associates, Inc., an independent firm of
petroleum and natural gas engineers.
Since 1993, Williston Basin has 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,
1997 production levels reached 6.9 MMdk, up 79 percent from 1993.
The production increases from these reserves are expected to provide
additional natural gas supplies for Prairielands 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.
On June 26, 1997, the Federal District Court issued its order
awarding Moncrief damages of approximately $15.6 million. On July
25, 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. On
August 25, 1997, Moncrief filed a notice of appeal with the United
States Court of Appeals for the Tenth Circuit related to the Federal
District Court's orders. On September 2, 1997, Williston Basin and
the Company filed a notice of cross-appeal.
Williston Basin believes that it is entitled to recover from
ratepayers virtually all of the costs ultimately incurred as a
result of these orders 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 recently provided alleged damages under differing
theories ranging 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 on November 6, 1997. Williston Basin and the Company
are awaiting a decision from the North Dakota District Court.
In a related matter, on March 14, 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 specified.
In Williston Basin's opinion, the claims of Apache and Snyder
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 ratepayers.
Regulatory Matters and Revenues Subject to Refund --
Williston Basin has pending with the FERC two general natural
gas rate change applications implemented in 1992 and 1996. On
October 20, 1997, Williston Basin appealed to the U.S. District
Court of Appeals for the D.C. Circuit certain issues decided by the
FERC in prior orders concerning the 1992 proceeding. On December
10, 1997, the FERC issued an order accepting, subject to certain
conditions, Williston Basin's July 25, 1997 compliance filing. On
December 22, 1997, Williston Basin submitted a compliance filing
pursuant to the FERC's December 10, 1997 order. On December 31,
1997, Williston Basin refunded $33.8 million to its customers,
including $30.8 million to Montana-Dakota, in addition to the $6.1
million interim refund that it had previously made in November 1996.
All such amounts had been previously reserved. Williston Basin is
awaiting an order from the FERC on its December 22, 1997 compliance
filing.
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, in December 1995, Williston
Basin filed revised base rates with the FERC resulting in an
increase of $8.9 million or 19.1 percent over the currently
effective rates. Williston Basin began collecting such increase
effective January 1, 1996, subject to refund and is awaiting a final
order from the FERC.
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 available under a repurchase commitment with Frontier
Gas Storage Company, as described in Note 3 of Notes to Consolidated
Financial Statements. As a part of the corporate realignment
effected January 1, 1985, the Company agreed, pursuant to the
settlement approved by the FERC, to remove from rates the financing
costs associated with this natural gas.
In January 1986, because of the uncertainty as to when a sale
would be made, Williston Basin began charging the financing costs
associated with this repurchase commitment to operations as
incurred. Such costs, consisting principally of interest and
related financing fees, approximated $5.7 million and $6.0 million
in 1996 and 1995, respectively. The costs incurred in 1997 were not
material and are included in "Other income -- net" on the
Consolidated Statements of Income.
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 costs to the
Frontier gas were appropriate. Williston Basin is awaiting a final
order from the FERC as to the appropriate costs to be allocated.
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, 1997 and 1996, natural gas held under a repurchase commitment
of $14.6 million and $37.2 million, respectively, is included in the
Company's Consolidated Balance Sheets under "Deferred charges and
other assets". The recognition of the then current market value of
this natural gas facilitated the sale by Williston Basin of 28.1
MMdk from the date of this write-down through December 31, 1997, and
should allow Williston Basin to market the remaining 14.9 MMdk on
a sustained basis enabling Williston Basin to liquidate this asset
over approximately the next three to four years.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1997 actual and 1998 through 2000 anticipated net capital
expenditures, excluding potential acquisitions, applicable to
Williston Basin's consolidated operations:
Actual Estimated
1997 1998 1999 2000
Production and Gathering $ 4.8 $11.4 $14.2 $12.3
Underground Storage .3 .4 .3 .8
Transmission 3.6 3.2 11.4 4.6
General and Other 1.5 6.2 1.3 1.4
Energy Marketing .2 .3 .2 1.3
$10.4 $21.5 $27.4 $20.4
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 the Anchorage, Alaska area,
north and north-central California, southern Oregon and the
Hawaiian Islands. 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 Alaskan, northern California and Oregon
operations produce and sell asphalt for various commercial and
roadway applications. Although not common to all locations, other
products include the manufacture and/or sale of cement, various
finished concrete products and other building materials and related
construction services.
On February 14, 1997, Baldwin Contracting Company, Inc.
(Baldwin), a subsidiary of KRC Holdings, purchased the physical
assets of Orland Asphalt located in Orland, California, including
a hot-mix plant and aggregate reserves. Orland Asphalt was
combined with and operates as part of Baldwin.
On July 31, 1997, Knife River purchased the 50 percent interest
in Hawaiian Cement, that it did not previously own, from Adelaide
Brighton Cement (Hawaii), Inc. of Adelaide, Australia. The
Company's initial 50 percent partnership interest in Hawaiian
Cement was acquired in September 1995.
On March 5, 1998, the Company acquired Morse Bros., Inc. and
S2 - F Corp., privately-held construction materials companies
located in Oregon's Willamette Valley. See Item 7 -- "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" for more information regarding these acquisitions.
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.
For information regarding sales volumes and revenues for the
construction materials operations for 1995 through 1997, 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 these products are subject to, 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. 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 1997, 1996 and 1995, 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 2.6 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,
1997 1996 1995 1994 1993
(In thousands)
Tons sold:
Montana-Dakota generating stations 530 528 453 691 624
Jointly-owned generating stations --
Montana-Dakota's share 434 565 883 1,049 1,034
Others 1,303 1,695 2,767 3,358 3,299
Industrial and other sales 108 111 115 108 109
Total 2,375 2,899 4,218 5,206 5,066
Revenues $27,906 $32,696 $39,956 $45,634 $44,230
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 1995 through 1997.
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 1997, Knife River supplied
approximately 180,000 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 electrical 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 of 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
January 1996, the Company and Knife River filed separate motions
with the State District Court to dismiss or stay, pending
arbitration. In May 1996, the State District Court granted the
Company's and Knife River's motions and 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 order dated April 25, 1997, 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, of approximately $50 million or more. 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.
By letter dated May 14, 1997, Knife River requested permission to
move for summary judgment which permission was granted by the
arbitration panel over objections of the Co-owners. Knife River
filed its summary judgment motion on July 21, 1997, which motion was
denied on October 29, 1997. 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.
Knife River does not anticipate any significant growth in its
lignite coal operations in the near future due to competition from
coal and other alternate fuel sources. Limited growth opportunities
may be available to Knife River's lignite coal operations through
the continued evaluation and pursuit of niche markets such as
agricultural products processing facilities.
Consolidated Construction Materials and Mining Operations:
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1997 actual net capital expenditures, including those expended for
the acquisitions of Orland Asphalt and the 50 percent interest in
Hawaiian Cement that Knife River did not previously own, and 1998
through 2000 anticipated net capital expenditures, excluding
potential acquisitions, applicable to Knife River's consolidated
construction materials and mining operations:
Actual Estimated
1997 1998 1999 2000
Construction Materials $38.0 $22.8 $10.2 $ 7.1
Coal 2.6 5.0 1.4 3.0
$40.6 $27.8 $11.6 $10.1
Environmental Matters --
Knife River's construction materials and mining operations are
subject to regulation customary for surface mining operations,
including federal, state and local environmental and reclamation
regulations. Except as may be found with regard to the issue
described below, Knife River believes it is in substantial
compliance with those regulations.
In September 1995, Unitek Environmental Services, Inc. and
Unitek Solvent Services, Inc. (Unitek) filed a complaint against
Hawaiian Cement in the U.S. District Court for the District of
Hawaii (District Court) alleging that dust emissions from Hawaiian
Cement's cement manufacturing plant at Kapolei, Hawaii (Plant)
violated the Hawaii State Implementation Plan (SIP) of the Clean Air
Act, constituted a continual nuisance and trespass on the
plaintiff's property, and that Hawaiian Cement's conduct warranted
the award of punitive damages. Hawaiian Cement is a Hawaiian
general partnership whose general partners are now Knife River
Hawaii, Inc. and Knife River Dakota, Inc., indirect wholly owned
subsidiaries of the Company. Knife River Dakota, Inc. purchased its
partnership interest from Adelaide Brighton Cement (Hawaii), Inc.
on July 31, 1997. Unitek sought civil penalties under the Clean Air
Act (as described below), and up to $20 million in damages for
various claims (as described above).
In August 1996, the District Court issued an order granting
Plaintiffs' motion for partial summary judgment relating to the
Clean Air Act, indicating that it would issue an injunction shortly.
The issue of civil penalties under the Clean Air Act was reserved
for further hearing at a later date, and Unitek's claims for damages
were not addressed by the District Court at such time.
In September 1996, Unitek and Hawaiian Cement reached a
settlement which resolved all claims except as to Clean Air Act
penalties. Based on a joint petition filed by Unitek and Hawaiian
Cement, the District Court stayed the proceeding and the issuance
of an injunction while the parties continued to negotiate the
remaining Clean Air Act claims.
In May 1996, the EPA issued a Notice of Violation (NOV) to
Hawaiian Cement. The NOV stated that dust emissions from the Plant
violated the SIP. Under the Clean Air Act, the EPA has the
authority to issue an order requiring compliance with the SIP, issue
an administrative order requiring the payment of penalties of up to
$25,000 per day per violation (not to exceed $200,000), or bring a
civil action for penalties of not more than $25,000 per day per
violation and/or bring a civil action for injunctive relief.
On April 7, 1997, a settlement resolving the remaining Clean Air
Act claims and the EPA's NOV issued in May 1996, was reached by
Hawaiian Cement, the EPA and Unitek.
On February 11, 1998, the District Court approved the April 1997
settlement. The costs relating to both the September 1996 and April
1997 settlements were not material and did not affect the Company's
results of operations since reserves had previously been provided.
Reserve Information --
As of December 31, 1997, the combined construction materials
operations had under ownership or lease approximately 169 million
tons of recoverable aggregate reserves.
As of December 31, 1997, Knife River had under ownership or
lease, reserves of approximately 227 million tons of recoverable
lignite coal, 87 million tons of which are at present mining
locations. Such reserve estimates were prepared by Weir
International Mining Consultants, independent mining engineers and
geologists, in a report dated May 9, 1994, and have been adjusted
for 1994 through 1997 production. Knife River estimates that
approximately 64 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 1997, 1996 and
1995, are as follows:
1997 1996 1995
Oil:
Production (000's of barrels) 2,088 2,149 1,973
Average sales price $17.50 $17.91 $15.07
Natural Gas:
Production (MMcf) 13,192 14,067 12,319
Average sales price $2.41 $2.09 $1.51
Production costs, including taxes,
per net equivalent barrel $3.65 $3.31 $3.18
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, 1997, are as follows:
Gross Net
Productive Wells:
Oil 2,279 138
Natural Gas 462 26
Total 2,741 164
Developed Acreage (000's) 614 56
Undeveloped Acreage (000's) 1,085 83
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1997, 1996 and 1995:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1997 1 2 3 3 1 4 7
1996 1 2 3 4 --- 4 7
1995 3 2 5 8 1 9 14
At December 31, 1997, there were six gross wells in the process
of drilling, four of which were exploratory wells and two of which
were development wells.
Capital Requirements --
The following summary (in millions of dollars) reflects net
capital expenditures, including those not subject to amortization,
related to oil and natural gas activities for the years 1997, 1996
and 1995:
1997 1996 1995
Acquisitions $ --- $23.2 $ 9.1
Exploration 13.4 8.1 7.7
Development 15.4 15.9 22.2
$28.8 $47.2 $39.0
Fidelity Oil's net capital expenditures are anticipated to be
approximately $50 million for 1998 and $60 million for both 1999 and
2000.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 14.9 million barrels and 57.6
Bcf, respectively, at December 31, 1997. Of these amounts, 10.2
million barrels and 2.8 Bcf, as supported by a report dated January
12, 1998, prepared by Ralph E. Davis Associates, Inc., an
independent firm of petroleum and natural gas engineers, were
related to its properties located in southeastern Montana and
southcentral Alabama.
For additional information related to Fidelity Oil's oil and
natural gas interests, see Note 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 Moncrief.
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 and Snyder. In a related matter, Williston
Basin has been named in a suit filed by nine other producers related
to a natural gas purchase contract.
The above legal actions are described under Items 1 and 2 --
"Business and Properties -- Natural Gas Transmission Operations and
Property (Williston Basin)." The Company's assessment of the
proceedings are included in the respective 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. The suit has been stayed by the State District Court
pending arbitration. Such suit was filed by the Co-owners of the
Coyote Station.
Hawaiian Cement has been named as a defendant in a legal action
primarily related to dust emissions from Hawaiian Cement's cement
manufacturing plant at Kapolei, Hawaii. Such suit was filed by
Unitek. In addition, the EPA has issued a NOV to Hawaiian Cement.
On February 11, 1998, the District Court approved the April 1997
settlement which was reached by Hawaiian Cement, the EPA and Unitek.
The above legal actions are described under Items 1 and 2 --
"Business and Properties -- Construction Materials and Mining
Operations and Property (Knife River)." The Company's assessment
of the proceedings is included in the respective descriptions 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 1997.
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 1997 and 1996 and dividends
declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
1997
First Quarter $23.00 $21.00 $ .2775
Second Quarter 25.25 21.38 .2775
Third Quarter 27.69 22.25 .2875
Fourth Quarter 33.50 26.63 .2875
$1.1300
1996
First Quarter $23.00 $19.88 $ .2725
Second Quarter 23.50 20.13 .2725
Third Quarter 22.38 20.75 .2775
Fourth Quarter 23.38 21.25 .2775
$1.1000
As of December 31, 1997, the Company's common stock was held by
approximately 13,600 stockholders of record.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 50 and 51
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 Williston
Basin's storage, transportation, gathering and natural gas production
operations, and the energy marketing operations of its subsidiary,
Prairielands. 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 (in millions of dollars) summarizes the
contribution to consolidated earnings by each of the Company's
businesses.
Years ended December 31,
Business 1997 1996 1995
Electric $ 13.4 $ 11.4 $ 12.0
Natural gas distribution 4.5 4.9 1.6
Natural gas transmission 11.3 2.5 8.4
Construction materials and
mining 10.1 11.5 10.8
Oil and natural gas production 14.5 14.4 8.0
Earnings on common stock $ 53.8 $ 44.7 $ 40.8
Earnings per common share -- basic $ 1.86 $ 1.57 $ 1.43
Earnings per common share -- diluted $ 1.86 $ 1.57 $ 1.43
Return on average common equity 14.6% 13.0% 12.3%
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 13 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.
1996 compared to 1995
Consolidated earnings for 1996 were up $3.9 million when
compared to 1995 including the effect of the $3.7 million net charge,
previously described. The increase was the result of higher earnings
at the oil and natural gas production, natural gas distribution and
construction materials and mining businesses. Decreased earnings at
the electric and natural gas transmission businesses somewhat offset
the earnings improvement.
________________________________
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 (in millions, where applicable) are key
financial and operating statistics for each of the Company's business
units.
Electric Operations
Years ended December 31,
1997* 1996 1995
Operating revenues:
Retail sales $ 130.3 $ 128.8 $ 124.4
Sales for resale and other 11.3 10.0 10.2
Utility services 22.8 --- ---
164.4 138.8 134.6
Operating expenses:
Fuel and purchased power 45.6 44.0 41.8
Operation and maintenance 60.1 41.4 40.1
Depreciation, depletion and
amortization 17.8 17.1 16.3
Taxes, other than income 7.8 6.8 6.5
131.3 109.3 104.7
Operating income $ 33.1 $ 29.5 $ 29.9
Retail sales (kWh) 2,041.2 2,067.9 1,993.7
Sales for resale (kWh) 361.9 374.6 408.0
Cost of fuel and purchased
power per kWh $ .018 $ .017 $ .016
* Includes International Line Builders, Inc. and High Line Equipment, Inc.
which were acquired on July 1, 1997.
Natural Gas Distribution Operations
Years ended December 31,
1997 1996 1995
Operating revenues:
Sales $ 153.6 $ 151.5 $ 146.8
Transportation and other 3.4 3.5 3.7
157.0 155.0 150.5
Operating expenses:
Purchased natural gas sold 107.2 102.7 102.6
Operation and maintenance 28.5 30.0 30.4
Depreciation, depletion and
amortization 7.0 6.9 6.7
Taxes, other than income 3.9 3.9 3.9
146.6 143.5 143.6
Operating income $ 10.4 $ 11.5 $ 6.9
Volumes (dk):
Sales 34.3 38.3 33.9
Transportation 10.1 9.4 11.1
Total throughput 44.4 47.7 45.0
Degree days (% of normal) 99.3% 116.2% 101.6%
Average cost of natural gas,
including transportation,
per dk $ 3.12 $ 2.67 $ 3.02
Natural Gas Transmission Operations
Years ended December 31,
1997* 1996 1995
Operating revenues:
Transportation $ 51.4** $ 60.4** $ 54.1**
Storage 10.9 10.7 12.6
Natural gas production and
other 4.5 7.5 5.2
Energy marketing 26.6 --- ---
93.4 78.6 71.9
Operating expenses:
Purchased gas sold 17.9 --- ---
Operation and maintenance 35.5** 37.2** 35.7**
Depreciation, depletion and
amortization 5.5 6.7 7.0
Taxes, other than income 5.3 4.5 3.8
64.2 48.4 46.5
Operating income $ 29.2 $ 30.2 $ 25.4
Volumes (dk):
Transportation --
Montana-Dakota 35.5 43.4 35.4
Other 50.0 38.8 32.6
85.5 82.2 68.0
Produced (000's of dk) 6,949 6,073 4,981
* Effective January 1, 1997, Prairielands became a wholly owned subsidiary of
Williston Basin. Consolidated financial results are presented for 1997.
In 1996 and 1995, Prairielands' financial results were included with the
natural gas distribution business.
** Includes amortization and
related recovery of deferred
natural gas contract buy-out/
buy-down and gas supply
realignment costs $ 5.5 $ 10.6 $ 11.4
Construction Materials and Mining Operations***
Years ended December 31,
1997 1996 1995
Operating revenues:
Construction materials $ 146.2 $ 99.5 $ 73.1
Coal 27.9 32.7 39.9
174.1 132.2 113.0
Operating expenses:
Operation and maintenance 145.6 105.8 87.8
Depreciation, depletion and
amortization 11.0 7.0 6.2
Taxes, other than income 2.9 3.3 4.5
159.5 116.1 98.5
Operating income $ 14.6 $ 16.1 $ 14.5
Sales (000's):
Aggregates (tons) 5,113 3,374 2,904
Asphalt (tons) 758 694 373
Ready-mixed concrete
(cubic yards) 516 340 307
Coal (tons) 2,375 2,899 4,218
*** Prior to August 1, 1997, financial results did not include 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,
1997 1996 1995
Operating revenues:
Oil $ 36.6 $ 39.0 $ 30.1
Natural gas 31.8 29.3 18.7
68.4 68.3 48.8
Operating expenses:
Operation and maintenance 15.8 15.6 13.7
Depreciation, depletion and
amortization 24.4 25.0 18.6
Taxes, other than income 3.9 3.5 2.6
44.1 44.1 34.9
Operating income $ 24.3 $ 24.2 $ 13.9
Production (000's):
Oil (barrels) 2,088 2,149 1,973
Natural gas (Mcf) 13,192 14,067 12,319
Average sales price:
Oil (per barrel) $ 17.50 $ 17.91 $ 15.07
Natural gas (per Mcf) 2.41 2.09 1.51
Amounts presented in the above 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 Williston Basin's
natural gas transmission business. 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, $58.2 million, $53.8 million and $4.4
million, respectively, for 1996, and $54.6 million, $49.2 million
and $5.4 million, respectively, for 1995.
1997 compared to 1996
Electric Operations
Operating income at the electric business increased primarily
due to increased retail sales and sales for resale revenues. Retail
sales revenue increased due to increased rates in Wyoming reflecting
recovery of costs associated with the new power supply contract with
Black Hills Power and Light Company beginning January 1, 1997.
Higher average realized rates in the remaining service territory and
decreased net refunding due to timing of fuel costs to customers
also added to the retail sales revenue improvement. Decreased
weather-related sales primarily to residential customers in the
fourth quarter somewhat offset the increase in retail sales revenue.
Sales for resale revenue increased due to higher average realized
rates caused by favorable market conditions in the third and fourth
quarters. Increases in utility services revenue and related
increases in operation and maintenance expense, depreciation,
depletion, and amortization and taxes other than income resulted
from International Line Builders, Inc. and High Line Equipment,
Inc., which were acquired on July 1, 1997. Exclusive of the above-
mentioned acquisitions, operation expenses decreased due to lower
payroll and benefit-related expenses, which also added to the
operating income improvement. Increased maintenance expense
partially offset the increase in operating income. Power generation
maintenance expense increased due to $1.9 million in costs resulting
from a ten-week maintenance outage at the Coyote Station in 1997;
this was somewhat offset by 1996 costs resulting from maintenance
work at both the Lewis and Clark Station and the Big Stone Station.
Higher transmission and distribution maintenance expense, due to the
repair of damages associated with the April 1997 blizzard, also
added to the increase in maintenance expense. Increased fuel and
purchased power costs, largely resulting from increased purchase
power demand charges and changes in generation mix, partially offset
the operating income increase. The increase in demand charges is
related to the power supply contract with Black Hills Power and
Light Company.
Earnings for the electric business improved due to the operating
income increase but were slightly offset by increased interest
expense due to higher average short-term debt balances. Earnings
attributable to the electric services companies acquired on July 1,
1997, were $947,000.
Natural Gas Distribution Operations
Operating income decreased at the natural gas distribution
business as a result of reduced sales of 3.9 million decatherms, the
result of 15% warmer weather. The pass through of higher average
gas costs more than offset the revenue decline that resulted from
the reduced sales volumes. A general rate increase placed into
effect in Montana in May 1996, which added to the revenue
improvement, partially offset the operating income decline.
Decreased operations expense due to lower payroll and benefit-
related costs also partially offset the decrease in operating
income. The effects of higher volumes transported, primarily to
large industrial customers, were offset by lower average
transportation rates.
Natural gas distribution earnings declined largely due to the
decrease in operating income. Decreased net interest expense and
increased return on gas in storage and prepaid demand balances
(included in Other income -- net) slightly offset the earnings
decline. The decrease in net interest expense resulted from reduced
carrying costs on natural gas costs refundable through rate
adjustments due to lower refundable balances.
Natural Gas Transmission Operations
Operating income at the natural gas transmission business
decreased primarily due to a decline in transportation revenues.
Transportation revenues were lower due to the reversal of certain
reserves for regulatory contingencies which added $4.2 million ($2.6
million after tax) to revenue in 1996. In addition, reduced
recovery of deferred natural gas contract buy-out/buy-down and gas
supply realignment costs and lower average transportation rates
contributed to the decrease in transportation revenue.
Transportation revenues also decreased due to additional reserved
revenues provided, with a corresponding reduction in depreciation
expense, as a result of FERC orders relating to a 1992 general rate
proceeding. Increased volumes transported to off-system markets,
due to sales of natural gas held under the repurchase commitment,
were partially offset by lower on-system transportation, somewhat
reducing the transportation revenue decline. Sales of natural gas
held under the repurchase commitment were 17.9 MMdk, primarily
volumes sold to off-system markets and volumes sold in place. Taxes
other than income increased due primarily to increased property and
production taxes which also contributed to the operating income
decline. Natural gas production revenues for 1997, excluding the
effect of intercompany eliminations of $5.6 million, improved as a
result of both higher volumes produced and increased prices which
partially offset the decrease in operating income. The increases in
energy marketing revenue, purchased gas sold and the related
increase in operation and maintenance expense resulted from
Prairielands becoming a wholly owned subsidiary effective January 1,
1997. Operation expenses, excluding Prairielands, decreased due to
reduced amortization of deferred natural gas contract buy-out/buy-
down and gas supply realignment costs offset in part by higher
royalties due to both a royalty settlement with the United States
Minerals Management Service and increased production and prices.
Earnings for this business increased due to the September 1996
$21.1 million ($12.9 million after tax) write-down of the natural
gas available under the repurchase commitment to the then current
market price. Gains realized on the sale of natural gas held under
the repurchase commitment and decreased carrying costs on this gas
stemming from lower average borrowings also added to the earnings
increase. Increased income taxes due to the reversal of certain
income tax reserves aggregating $4.8 million in September 1996 and
decreased operating income both partially offset the earnings
improvement.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $3.3 million
due to higher revenues primarily resulting from the acquisitions of
Baldwin in April 1996, Medford Ready Mix, Inc. (Medford) in June
1996, Orland Asphalt in February 1997, and the 50% interest in
Hawaiian Cement that Knife River did not previously own in July
1997. Revenues at other construction materials operations increased
as a result of higher aggregate and ready-mixed concrete sales
volumes, increased construction revenues, and higher asphalt prices.
The increase in operation and maintenance and depreciation expenses
was largely due to expenses associated with such acquisitions.
Operation and maintenance expenses also increased at the other
construction materials operations due to higher aggregate and ready-
mixed concrete volumes sold.
Coal Operations --
Operating income for the coal operations decreased $4.8 million,
largely due to decreased revenues resulting from lower sales of
524,000 tons to the Coyote Station, the result of the ten-week
maintenance outage. Higher average sales prices at the Beulah Mine
partially offset the reduced coal revenues. Increased operation and
maintenance expense due to higher stripping costs at the Beulah
Mine, partially offset by lower volume-related costs and decreased
taxes other than income, also added to the operating income decline.
Consolidated --
Earnings declined due to decreased operating income at the coal
business and decreased Other income -- net. The decrease in Other
income -- net was due to the purchase of the 50% interest in
Hawaiian Cement that Knife River did not previously own. Prior to
August 1997, Knife River's original 50 percent ownership interest in
Hawaiian Cement was accounted for under the equity method. However,
on July 31, 1997, Knife River acquired the 50 percent interest in
Hawaiian Cement that it did not previously own and Knife River in
August 1997 began consolidating Hawaiian Cement into its financial
statements. In addition, higher interest expense resulting mainly
from increased long-term debt due to the aforementioned acquisitions
also added to the decrease in earnings. Increased construction
materials operating income and gains realized from the sale of
equipment, partially offset the earnings decline.
Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production business
at Fidelity Oil increased slightly as a result of higher natural gas
revenues. The increase in natural gas revenue resulted from a $4.6
million improvement due to higher average prices somewhat offset by
a $2.1 million decrease due to lower production. Decreased oil
revenue largely offset the natural gas revenue increase. The
decline in oil revenue was due to a $1.3 million decrease resulting
from lower average oil prices and a $1.1 million decline due to
lower production. Decreased depreciation, depletion and
amortization, largely the result of lower production, also added to
the increase in operating income. Increased taxes other than income
partially offset the increase in operating income.
Earnings for this business unit increased due to the operating
income improvement and decreased interest expense due to lower
average long-term debt balances. Increased income taxes somewhat
offset the earnings improvement. The increase in income taxes
resulted from the reversal of certain tax reserves aggregating $1.8
million in September 1996 somewhat offset by higher tax credits in
1997.
1996 compared to 1995
Electric Operations
Operating income at the electric business decreased primarily
due to increased fuel and purchased power costs, resulting primarily
from both higher purchased power demand charges and increased net
sales. The increase in demand charges, related to a participation
power contract, was the result of the pass-through of periodic
maintenance costs as well as the purchase of an additional five
megawatts of capacity beginning in May 1996, which brought the total
level of capacity available under this contract to 66 megawatts.
Also contributing to the operating income decline were higher
operation expenses, primarily resulting from higher transmission and
payroll-related costs due to establishing certain contingency
reserves, and higher depreciation expense, due to an increase in
average depreciable plant. Increased revenues, primarily higher
retail sales due to increased weather-related demand from
residential and commercial customers in the first and fourth
quarters of 1996, largely offset the operating income decline.
Lower sales for resale volumes due to line capacity restrictions
within the regional power pool were more than offset by higher
average realized rates also partially offsetting the operating
revenue increase.
Earnings for the electric business decreased due to the
operating income decline, and decreased service and repair income
and lower investment income, both included in Other income -- net.
Natural Gas Distribution Operations
Operating income at the natural gas distribution business
improved largely as a result of increased sales revenue. The sales
revenue improvement resulted primarily from a 3.6 million decatherm
increase in volumes sold due to 14% colder weather and increased
sales resulting from the addition of over 3,600 customers. Also
contributing to the sales revenue improvement were the effects of a
general rate increase placed into effect in Montana in May 1996.
However, the pass-through of lower average natural gas costs
partially offset the sales revenue improvement. Decreased
operations expense due to lower payroll-related costs also added to
the operating income improvement. Lower transportation revenues,
primarily decreased volumes transported to large industrial
customers, somewhat offset the operating income improvement.
Industrial transportation declined due to lower volumes transported
to two agricultural processing facilities, one of which closed in
September 1995, and one of which experienced lower production, and
to a cement manufacturing facility due to its use of an alternate
fuel.
Natural gas distribution earnings increased due to the operating
income improvement, decreased interest expense and higher service
and repair income. The decline in interest expense resulted from
lower average long-term debt and natural gas costs refundable
through rate adjustment balances.
Natural Gas Transmission Operations
Operating income at the natural gas transmission business
increased primarily due to an improvement in transportation revenues
resulting from increased transportation of natural gas held under
the repurchase commitment, increased volumes transported to storage
and the reversal of certain reserves for regulatory contingencies of
$3.9 million ($2.4 million after tax). The benefits derived from a
favorable rate change implemented in January 1996, also added to the
revenue improvement. The nonrecurring effect of a favorable FERC
order received in April 1995, on a rehearing request relating to a
1989 general rate proceeding partially offset the transportation
revenue improvement. The order allowed for the one-time billing of
customers for approximately $2.7 million ($1.7 million after tax) to
recover a portion of the amount previously refunded in July 1994.
In addition, reduced recovery of deferred natural gas contract buy-
out/buy-down and gas supply realignment costs partially offset the
increase in transportation revenue. An increase in natural gas
production revenue, due to both higher volumes and prices, also
contributed to the operating income improvement. Decreased storage
revenues, due primarily to the implementation of lower rates in
January 1996, partially offset the increase in operating income.
Operation expenses increased primarily due to higher payroll-related
costs and production royalties but were slightly offset by reduced
amortization of deferred natural gas contract buy-out/buy-down
costs.
Earnings for this business decreased due to the write-down to
the then current market price of the natural gas available under the
repurchase commitment. The effect of the write-down, which was
$21.1 million, or $12.9 million after tax, was significantly offset
by the reversal of certain income tax reserves aggregating $4.8
million. Decreased interest income, largely related to $583,000
(after tax) of interest on the previously discussed 1995 refund
recovery combined with higher company production refunds (both
included in Other income -- net), also added to the earnings
decline. Increased net interest expense ($366,000 after tax),
largely resulting from higher average reserved revenue balances
partially offset by decreased long-term debt expense due to lower
average borrowings, further reduced earnings. The earnings decrease
was somewhat offset by the increase in operating income.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $3.3 million
due to higher revenues. The revenue improvement is largely due to
revenues realized as a result of the Baldwin and Medford
acquisitions. Revenues at most other construction materials
operations decreased as a result of lower aggregate and asphalt
sales due to lower demand, and lower construction sales due to the
nature of work being performed this year as compared to last year,
offset in part by increased building materials sales and aggregate
and ready-mixed concrete prices. Operation and maintenance expenses
increased due to the above acquisitions but were somewhat offset by
a reduction at other construction materials operations resulting
from lower volumes sold and less work involving the use of
subcontractors.
Coal Operations --
Operating income for coal operations decreased $1.7 million
primarily due to decreased revenues, largely the result of the
expiration of the coal contract with the Big Stone Station in August
1995, and the resulting closure of the Gascoyne Mine. Higher
average sales prices due to price increases at the Beulah Mine
partially offset the decreased coal revenues. Decreased operation
and maintenance expenses, depreciation expense and taxes other than
income, largely due to the mine closure, partially offset the
decline in operating income.
Consolidated --
Earnings increased due to the increase in construction materials
operating income and income from a 50 percent interest in Hawaiian
Cement acquired in September 1995 of $1.7 million as compared to
$1.0 million in 1995 (included in Other income -- net). Higher
interest expense ($1.4 million after tax), resulting mainly from
increased long-term debt due to the acquisition of Hawaiian Cement,
Baldwin and Medford, and the decline in coal operating income
somewhat offset the increase in earnings.
Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production business
increased primarily as a result of higher oil and natural gas
revenues. Higher oil revenue resulted from a $5.6 million increase
due to higher average prices and a $3.2 million increase due to
improved production. The increase in natural gas revenue was due to
a $7.0 million increase arising from higher prices and a $3.6
million improvement resulting from higher production. Increased
operation and maintenance expenses, largely due to higher
production, and higher taxes other than income, primarily the result
of higher prices, both partially offset the operating income
improvement. Also reducing operating income was increased
depreciation, depletion and amortization expense resulting from
increased average rates and higher production. Depreciation,
depletion and amortization rates increased in part due to the
accrual of estimated future well abandonment costs ($515,000 after
tax).
Earnings for this business unit increased due to the operating
income improvement and lower income taxes due to the reversal of
certain tax reserves aggregating $1.8 million. Increased interest
expense ($815,000 after tax), resulting mainly from higher average
borrowings, and lower tax benefits somewhat 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, weather conditions, 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).
Non-Regulated Operations --
Certain important factors which could cause actual results or
outcomes for the Company and all or certain of its non-regulated
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 Non-Regulated 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 compliance with the year 2000 issue as discussed
later.
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. The Company has recently completed an assessment
of its operations to determine the costs expected to be incurred
specifically related to modifications necessary for year 2000
compatibility. While the Company will continue to evaluate the
potential effects of the year 2000 issue, based on its recent
assessment, the Company believes that these costs will not be
material to its results of operations. The Company's operations
with respect to the year 2000 issue may also be affected by other
entities with which the Company transacts business. The Company is
currently unable to determine the potential adverse consequences, if
any, that could result from such entities' failure to effectively
address this issue.
Liquidity and Capital Commitments
The Company's net capital expenditures (in millions of dollars)
for 1995 through 1997 and as anticipated for 1998 through 2000 are
summarized in the following table, which also includes the Company's
capital needs for the retirement of maturing long-term securities.
Actual Estimated*
1995 1996 1997 Capital Expenditures -- 1998 1999 2000
Montana-Dakota:
$ 19.7 $ 18.7 $ 18.4 Electric $ 17.0 $ 15.9 $ 17.0
8.9 6.3 8.8 Natural Gas Distribution 7.9 9.4 7.5
28.6 25.0 27.2 24.9 25.3 24.5
12.3 10.9 11.4 Williston Basin 21.4 26.9 20.0
36.8 25.0 41.5 Knife River 27.8 11.6 10.1
39.9 51.8 30.6 Fidelity 50.0 62.0 62.0
--- --- 11.4 Other 2.8 1.1 1.1
117.6 112.7 122.1 126.9 126.9 117.7
Net proceeds from sale or
(2.8) (11.8) (4.5) disposition of property .5 (1.5) (1.6)
114.8 100.9 117.6 Net capital expenditures 127.4 125.4 116.1
Retirement of Long-term
Debt/Preferred Stock --
10.4 35.4 42.4 Montana-Dakota 5.4 5.4 5.4
10.1 8.0 .5 Williston Basin .5 .5 .8
--- --- --- Knife River 1.3 1.3 36.8
--- --- 4.8 Fidelity --- 7.9 10.8
--- --- .3 Other .7 .2 .1
20.5 43.4 48.0 7.9 15.3 53.9
$135.3 $144.3 $165.6 Total $135.3 $140.7 $170.0
* The anticipated 1998 through 2000 net capital expenditures reflected in the
above table do not include potential acquisitions. To the extent that
acquisitions occur, such acquisitions would be financed with existing credit
facilities and the issuance of long-term debt and the Company's equity
securities.
In reconciling total net capital expenditures to investing
activities per the Consolidated Statements of Cash Flows, the net
capital expenditures for Prairielands of $800,000 and $2.6 million
in 1996 and 1995, respectively, included with Williston Basin above
and not considered a major business segment, are not reflected in
investing activities in the Consolidated Statements of Cash Flows.
In addition, the total 1997 net capital expenditures, related to
acquisitions, in the above table include assumed debt and the
issuance of the Company's equity securities, which were $9.9 million
in total.
In 1997 Montana-Dakota provided all the funds needed for its net
capital expenditures and securities retirements, excluding the $20
million discussed below, from internal sources. Net capital
expenditures for the years 1998 through 2000 include those for
system upgrades, routine replacements and service extensions.
Montana-Dakota expects to provide all of the funds required for
these net capital expenditures and securities retirements for the
years 1998 through 2000 from internal sources, through the use of
the Company's $40 million revolving credit and term loan agreement,
$18 million of which was outstanding at December 31, 1997, and
through the issuance of long-term debt, the amount and timing of
which will depend upon the Company's needs, internal cash generation
and market conditions. In October 1997, the Company redeemed $20
million of its 9 1/8% Series first mortgage bonds, due October 1,
2016. The funds required to retire the 9 1/8% Series first mortgage
bonds were provided by the issuance of $30 million in Secured
Medium-Term Notes on September 30, 1997. In addition, in November
1997, the Company redeemed $5 million of its 9 1/8% Series first
mortgage bonds, due May 15, 2006. On December 19, 1997, amounts
available under the revolving credit and term loan agreement
increased from $30 million to $40 million.
Williston Basin's 1997 net capital expenditures and securities
retirements were met through internally generated funds. Williston
Basin's net capital expenditures for the years 1998 through 2000,
excluding potential acquisitions, include those for pipeline
expansion projects, routine system improvements and continued
development of natural gas reserves. These expenditures are
expected to be met with a combination of internally generated funds,
short-term lines of credit aggregating $40.6 million, $350,000 of
which was outstanding at December 31, 1997, and through the issuance
of long-term debt, the amount and timing of which will depend upon
Williston Basin's needs, internal cash generation and market
conditions.
Knife River's 1997 net capital expenditures including the
acquisitions of Orland Asphalt and the 50 percent interest in
Hawaiian Cement that it did not previously own were met through
funds generated from internal sources and a revolving credit
agreement. Knife River's 1998 through 2000 net capital
expenditures, excluding potential acquisitions, include routine
equipment rebuilding and replacement and the construction of
aggregate materials handling facilities. It is anticipated that
funds generated from internal sources, short-term lines of credit
aggregating $26 million, $2 million of which was outstanding at
December 31, 1997, a revolving credit agreement of $85 million, $33
million of which was outstanding at December 31, 1997, and the
issuance of long-term debt and the Company's equity securities will
meet the needs of this business unit for 1998 through 2000. In June
1997, amounts available under the revolving credit agreement were
increased from $55 million to $85 million. In addition, in July
1997, amounts available under the short-term lines of credit
increased from $11 million to $26 million. In November 1997, Knife
River privately placed $35 million of notes with the proceeds used
to replace other long-term debt.
Fidelity Oil's 1997 net capital expenditures related to its oil
and natural gas acquisition, development and exploration program
were met through funds generated from internal sources. Fidelity's
borrowing base, which is based on total proved reserves, is
currently $65 million. This consists of $20 million of issued
notes, $10 million in an uncommitted note shelf facility, and a $35
million revolving line of credit, $13 million of which was
outstanding at December 31, 1997. It is anticipated that Fidelity's
1998 through 2000 net capital expenditures and debt retirements will
be met from internal sources and existing long-term credit
facilities. Fidelity's net capital expenditures for 1998 through
2000 will be used to further enhance production and reserve growth.
Other corporate 1997 net capital expenditures, largely those
expended for the acquisitions of International Line Builders, Inc.
and High Line Equipment, Inc., were met through short-term lines of
credit and the issuance of long-term debt and the Company's equity
securities. It is anticipated that 1998 through 2000 other net
capital expenditures, excluding potential acquisitions, used for
routine equipment maintenance and replacements will be met from
internal sources and existing short-term lines of credit aggregating
$3.8 million, $997,000 of which was outstanding at December 31,
1997.
The Company utilizes its short-term lines of credit aggregating
$50 million, none of which was outstanding on December 31, 1997, and
its $40 million revolving credit and term loan agreement, $18
million of which was outstanding at December 31, 1997, as previously
described, to meet its short-term financing needs and to take
advantage of market conditions when timing the placement of long-
term or permanent financing. On July 31, 1997, amounts available
under the short-term lines of credit were increased from $40 million
to $50 million.
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, 1997, the Company could have issued approximately
$259 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 3.4 and 2.7 times for 1997 and 1996, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 6.0 times in 1997 compared to 5.4 times in 1996. Common
stockholders' equity as a percent of total capitalization was 55
percent and 54 percent at December 31, 1997 and 1996, respectively.
Recent Development
On March 5, 1998, the Company acquired Morse Bros., Inc. (MBI),
and S2 - F Corp. (S2-F), privately-held construction materials
companies located in Oregon's Willamette Valley. The purchase
consideration for such companies consisted of approximately $96
million of the Company's common stock and cash, the assumption of
certain liabilities and an adjustment based on working capital. The
common stock of the Company, issued in exchange for all of the
issued and outstanding stock of MBI and S2-F was unregistered and is
subject to certain restrictions. The acquisition will be accounted
for under the purchase method of accounting. Under this method, the
consideration for the stock of MBI and S2-F will be allocated to the
underlying assets acquired and liabilities assumed, based on their
estimated fair market values. The Company anticipates that the
effect of such acquisitions will be accretive to earnings.
Financial statements of the acquired companies and proforma
financial statements have not been presented as such information is
not required in accordance with the rules and regulations of the
Securities and Exchange Commission.
MBI, the largest construction materials supplier in Oregon,
sells aggregate, ready-mixed concrete, asphaltic concrete, prestress
concrete and construction services in the Willamette Valley from
Portland to Eugene. The products of MBI are used in the
construction of streets, roads, and highways and in both building
and bridge structures. Assets owned by MBI include aggregate
reserves and construction materials plant and equipment. S2-F sells
aggregate and construction services and their properties consist
primarily of construction and aggregate mining equipment and leased
aggregate reserves. In 1997, MBI and S2-F had combined net sales of
$107 million and have approximately 370 million tons of aggregate
reserves, of which 270 million tons are permitted. It is the intent
of the Company that MBI and S2-F continue their operations and
businesses.
Effects of Inflation
Inflation did not have a significant effect on the Company's
operations in 1997, 1996 or 1995.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required for fiscal 1997 because the Company's market
capitalization was less than $2.5 billion as of January 28, 1997.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 25 through 49 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 2 through 6 and 12 and 13 of the
Company's Proxy Statement dated March 9, 1998 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 7 through 12 of the Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 14 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, 1997 *
Consolidated Balance Sheets at December 31,
1997 and 1996 *
Consolidated Statements of Common Stockholders'
Equity for each of the three years in the
period ended December 31, 1997 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1997 *
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 1997 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 1997 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 **
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 3, 1988, between the Company
and Norwest Bank Minnesota, N.A.,
Rights Agent, filed as Exhibit 4(c)
in Registration No. 33-66682 *
+ 10(a) Executive Incentive Compensation Plan,
filed as Exhibit 10 (a) to Form 10-K
for the year ended December 31, 1996, in
File No. 1-3480 *
+ 10(b) 1992 Key Employee Stock Option Plan,
filed as Exhibit 10(f) in Registration
No. 33-66682 *
+ 10(c) Restricted Stock Bonus Plan, filed as
Exhibit 10(b) in Registration No. 33-66682 *
+ 10(d) Supplemental Income Security Plan, filed
as Exhibit 10 (d) to Form 10-K for the
year ended December 31, 1996, in
File No. 1-3480 *
+ 10(e) Directors' Compensation Policy, filed as
Exhibit 10(d) in Registration No. 33-66682 *
+ 10(f) Deferred Compensation Plan for Directors,
filed as Exhibit 10(e) in Registration
No. 33-66682 *
+ 10(g) Non-Employee Director Stock Compensation
Plan, filed as Exhibit 10(g) to Form 10-K
for the year ended December 31, 1995, in
File No. 1-3480 *
+ 10(h) Non-Employee Director Long-Term Incentive
Plan, filed as Exhibit 10 (h) to Form 10-Q
for the quarterly period ended June 30, 1997,
in File No. 1-3480 *
+ 10(i) Executive Long-Term Incentive Plan, filed as
Exhibit 10 (i) to Form 10-Q for the quarterly
period ended June 30, 1997, in
File No. 1-3480 *
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1997 **
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.
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 6, 1998 By: /s/ Harold J. Mellen, Jr.
Harold J. Mellen, Jr. (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/ Harold J. Mellen, Jr. Chief Executive March 6, 1998
Harold J. Mellen, Jr. Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief March 6, 1998
Douglas C. Kane (Executive Vice President, Administrative &
Chief Administrative & Corporate Corporate
Development Officer) Development Officer
and Director
/s/ Warren L. Robinson Chief Financial March 6, 1998
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting March 6, 1998
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director March 6, 1998
John A. Schuchart (Chairman of the Board)
/s/ San W. Orr, Jr. Director March 6, 1998
San W. Orr, Jr. (Vice Chairman of the Board)
/s/ Thomas Everist Director March 6, 1998
Thomas Everist
/s/ Richard L. Muus Director March 6, 1998
Richard L. Muus
/s/ Robert L. Nance Director March 6, 1998
Robert L. Nance
/s/ John L. Olson Director March 6, 1998
John L. Olson
/s/ Harry J. Pearce Director March 6, 1998
Harry J. Pearce
/s/ Homer A. Scott, Jr. Director March 6, 1998
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director March 6, 1998
Joseph T. Simmons
/s/ Sister Thomas Welder Director March 6, 1998
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 **
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 3, 1988, between the Company
and Norwest Bank Minnesota, N.A.,
Rights Agent, filed as Exhibit 4(c)
in Registration No. 33-66682 *
+ 10(a) Executive Incentive Compensation Plan,
filed as Exhibit 10 (a) to Form 10-K
for the year ended December 31, 1996, in
File No. 1-3480 *
+ 10(b) 1992 Key Employee Stock Option Plan,
filed as Exhibit 10(f) in Registration
No. 33-66682 *
+ 10(c) Restricted Stock Bonus Plan, filed as
Exhibit 10(b) in Registration No. 33-66682 *
+ 10(d) Supplemental Income Security Plan, filed
as Exhibit 10 (d) to Form 10-K for the
year ended December 31, 1996, in
File No. 1-3480 *
+ 10(e) Directors' Compensation Policy, filed as
Exhibit 10(d) in Registration No. 33-66682 *
+ 10(f) Deferred Compensation Plan for Directors,
filed as Exhibit 10(e) in Registration
No. 33-66682 *
+ 10(g) Non-Employee Director Stock Compensation
Plan, filed as Exhibit 10(g) to Form 10-K
for the year ended December 31, 1995, in
File No. 1-3480 *
+ 10(h) Non-Employee Director Long-Term Incentive
Plan, filed as Exhibit 10 (h) to Form 10-Q
for the quarterly period ended June 30, 1997,
in File No. 1-3480 *
+ 10(i) Executive Long-Term Incentive Plan, filed as
Exhibit 10 (i) to Form 10-Q for the quarterly
period ended June 30, 1997, in
File No. 1-3480 *
12 Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividends **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1997 **
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.
TABLE OF CONTENTS
TO BYLAWS
Amendments
Certificates of Stock
Chairman and Vice Chairman of the Board
Checks
Chief Executive Officer
Chief Operating Officer
Committees
Compensation of Directors
Directors
Directors and Officers Indemnified
Directors Meetings
Dividends
Election of Officers
Execution of Instruments
Execution of Proxies
Fiscal Year
Inspection of Books and Records
Lost Certificates
Notices
Officers
Offices
President
Qualifications
Record Date
Registered Stockholders
Seal
Secretary and Assistant Secretaries
Stockholders Meetings
Transfers of Stock
Treasurer and Assistant Treasurer
Vice Presidents
BYLAWS OF
MDU RESOURCES GROUP, INC.
OFFICES
1.01 Registered Office. The registered office shall be in the City
of Wilmington, County of New Castle, State of Delaware.
1.02 Other Offices. The Corporation may also have offices at such
other places, both within and without the State of Delaware, as the Board
of Directors may from time to time determine or the business of the
Corporation may require.
MEETINGS OF STOCKHOLDERS
2.01 Place of Meetings. All meetings of the stockholders for the
election of Directors shall be held in the City of Bismarck, State of
North Dakota, at such place as may be fixed from time to time by the
Board of Directors, or at such other place, either within or without the
State of Delaware, as shall be designated from time to time by the Board
of Directors and stated in the notice of the meeting. Meetings of
stockholders for any other purpose may be held at such time and place,
within or without the State of Delaware, as shall be stated in the notice
of the meeting or in a duly executed waiver of notice thereof.
2.02 Annual Meetings. Annual meetings of stockholders, commencing
with the year 1973, shall be held on the fourth Tuesday of April in each year,
if not a legal holiday, and if a legal holiday, then on the next secular day
following, at 11:00 A.M., or at such other date and time as shall be
designated from time to time by the Board of Directors and stated in the
notice of the meeting, at which they shall elect by a plurality vote, by
written ballot, a Board of Directors, and transact such other business as
may properly be brought before the meeting.
2.03 Notice of Annual Meeting. Written notice of the annual meeting,
stating the place, date and hour of the meeting, shall be given to each
stockholder entitled to vote at such meeting not less than ten nor more
than sixty days before the date of the meeting.
2.04 Stockholders List. The officer who has charge of the stock
ledger of the Corporation shall prepare and make, at least ten days
before every meeting of stockholders, a complete list of the stockholders
entitled to vote at the meeting, arranged in alphabetical order, and
showing the address of each stockholder and the number of shares
registered in the name of each stockholder. Such list shall be open to
the examination of any stockholder, for any purpose germane to the
meeting, during ordinary business hours, for a period of at least ten
days prior to the meeting, either at a place within the City where the
meeting is to be held, which place shall be specified in the notice of
the meeting, or, if not so specified, at the place where the meeting is
to be held. The list shall also be produced and kept at the time and place
of the meeting during the whole time thereof, and may be inspected by any
stockholder who is present.
2.05 Notice of Special Meeting. Written notice of a special meeting,
stating the place, date and hour of the meeting and the purpose or
purposes for which the meeting is called, shall be given not less than
ten nor more than sixty days before the date of the meeting, to each
stockholder entitled to vote at such meeting.
2.06 Quorum. The holders of a majority of the stock issued and
outstanding and entitled to vote in person or by proxy, shall constitute
a quorum at all meetings of the stockholders for the transaction of
business, except as provided herein and except as otherwise provided by
statute or by the Certificate of Incorporation. If, however, such quorum
shall not be present or represented at any meeting of the stockholders,
the stockholders entitled to vote thereat, present in person or
represented by proxy, shall have power to adjourn the meeting from time
to time, without notice other than announcement at the meeting, until a
quorum shall be present or represented. At such adjourned meeting at
which a quorum shall be present or represented, any business may be
transacted which might have been transacted at the meeting as originally
notified. If the adjournment is for more than thirty days, or if, after
the adjournment, a new record date is fixed for the adjourned meeting, a
notice of the adjourned meeting shall be given to each stockholder of
record entitled to vote at the meeting.
2.07 Voting Rights. When a quorum is present at any meeting, the
vote of the holders of a majority of the stock having voting power,
present in person or represented by proxy, shall decide any question
brought before such meeting, unless the question is one upon which, by
express provision of the statutes, the Certificate of Incorporation or
these Bylaws, a different vote is required, in which case such express
provision shall govern and control the decision of such question. Unless
otherwise provided in the Certificate of Incorporation, each stockholder
shall, at every meeting of the stockholders, be entitled to one vote in
person or by proxy for each share of the capital stock having voting
power held by such stockholder, but no proxy shall be voted on after
three years from its date, unless the proxy provides for a longer period.
2.08 Notice of Stockholder Nominees. Only persons who are nominated
in accordance with the procedures set forth in this Section 2.08 shall be
eligible for election as Directors. Nominations of persons for election
to the Board of Directors of the Corporation may be made at the annual
meeting of stockholders by or at the direction of the Board of Directors,
or by any stockholder of the Corporation entitled to vote for the
election of Directors at the meeting who complies with the notice
procedures set forth in this Section 2.08. Such nominations, other than
those made by or at the direction of the Board of Directors, shall be made
pursuant to timely notice in writing to the Secretary of the Corporation.
To be timely, a stockholder's notice shall be delivered or mailed
and received at the principal executive offices of the Corporation not
less than 90 days prior to the annual meeting; provided, however, that in
the event that less than 100 days' notice or prior public disclosure of
the date of the meeting is given or made to stockholders by the
Corporation, notice by the stockholder to be timely must be so received
not later than the close of business on the 10th day following the day on
which such notice of the date of the meeting was mailed or such public
disclosure was made by the Corporation. The stockholder's notice shall
set forth (a) as to each person whom the stockholder proposes to nominate
for election or re-election as a Director, (i) the name, age, business
address and residence address of such person, (ii) the principal
occupation or employment of such person, (iii) the class and number of
shares of the Corporation which are beneficially owned by such person,
and (iv) any other information relating to such person that is required
to be disclosed in solicitations of proxies for election of Directors, or
is otherwise required, in each case pursuant to Regulation 14A under the
Securities Exchange Act of 1934, as amended (including without limitation
such person's written consent to being named in the proxy statement as a
nominee and to serving as a Director if elected); and (b) as to the
stockholder giving the notice, (i) the name and address, as they appear
on the Corporation's books, of such stockholder, and (ii) the class and
number of shares of the Corporation which are beneficially owned by such
stockholder.
At the request of the Board of Directors, any person nominated by
the Board of Directors for election as a Director shall furnish to the
Secretary of the Corporation that information required to be set forth in
a stockholder's notice of nomination which pertains to the nominee. No
person shall be eligible for election as a Director of the Corporation
unless nominated in accordance with the procedures set forth in this
Section 2.08.
The Chairman of the meeting shall, if the facts warrant, determine
and declare to the meeting that a nomination was not made in accordance
with the procedures prescribed by the Bylaws, and if the Chairman should
so determine, the Chairman shall so declare to the meeting and the
defective nomination shall be disregarded.
2.09 Notice of Stockholder Business. At an annual meeting of the
stockholders, only such business shall be conducted as shall have been
properly brought before the meeting. To be properly brought before an
annual meeting, business must be (a) specified in the notice of meeting
(or any supplement thereto) given by or at the direction of the Board of
Directors, (b) otherwise properly brought before the meeting or by the
direction of the Board of Directors, or (c) otherwise properly brought
before the meeting by a stockholder.
For business to be properly brought before an annual meeting by a
stockholder, the stockholder must have given timely notice thereof in
writing to the Secretary of the Corporation. To be timely, the
stockholder's notice must be delivered to or mailed and received at the
principal executive offices of the Corporation, not less than 90 days
prior to the meeting; provided, however, that in the event that less than
100 days' notice or prior public disclosure of the date of the meeting is
given or made to stockholders by the Corporation, notice by the
stockholder to be timely must be so received not later than the close of
business on the 10th day following the day on which such notice of the
date of the annual meeting was mailed or such public disclosure was made
by the Corporation. The stockholder's notice to the Secretary shall set
forth as to each matter the stockholder proposes to bring before the
annual meeting (a) a brief description of the business desired to be
brought to the annual meeting and the reasons for conducting business at
the annual meeting, (b) the name and address, as they appear on the
Corporation's books, of the stockholder proposing such business, (c) the
class and number of shares of the Corporation which are beneficially
owned by the stockholder, and (d) any material interest of the
stockholder in such business.
Notwithstanding anything in the Bylaws to the contrary, no business
shall be conducted at any annual meeting except in accordance with the
procedures set forth in this Section 2.09.
The Chairman of the annual meeting shall, if the facts warrant,
determine and declare to the meeting that business was not properly
brought before the meeting and, in accordance with the provisions of this
Section 2.09, and if he should so determine, the Chairman shall so
declare to the meeting and such business not properly brought before the
meeting shall not be transacted.
DIRECTORS
3.01 Authority of Directors. The business of the Corporation shall
be managed by its Board of Directors which may exercise all such powers
of the Corporation and do all such lawful acts and things as are not by
statute or by the Certificate of Incorporation or by these Bylaws
directed or required to be exercised or done by the stockholders.
3.02 Qualifications. No person shall be eligible as a Director of
the Corporation who at the time of his election has passed his seventieth
birthday, provided that this age qualification shall not apply to those
persons who are officers of the Corporation. Except for those persons who
have served as Chief Executive Officer of the Corporation, a person shall
be ineligible as a Director if at the time of his election he is a
retired officer of the Corporation. A person who has served as Chief
Executive Officer of the Corporation shall be ineligible as a Director if
at the time of his election he has been retired as Chief Executive
Officer for more than five years. The Board of Directors may elect from
those persons who have been members of the Board of Directors, Directors
Emeritus.
3.03 Place of Meetings. The Board of Directors of the Corporation
may hold meetings, both regular and special, either within or without
the State of Delaware.
3.04 Annual Meetings. The first meeting of each newly elected Board
of Directors shall be held at such time and place as shall be specified
in a notice given as herein provided for regular meetings of the Board of
Directors, or as shall be specified in a duly executed waiver of notice
thereof.
3.05 Regular Meetings. Regular meetings of the Board of Directors
may be held at the office of the Corporation in Bismarck, North Dakota,
on the second Thursday following the first Monday of February, May,
August and November of each year; provided, however, that if a legal
holiday, then on the next preceding day that is not a legal holiday.
Regular meetings of the Board of Directors may be held at other times and
other places within or without the State of North Dakota on at least five
days' notice to each Director, either personally or by mail, telephone or
telegram.
3.06 Special Meetings. Special meetings of the Board may be called
by the Chairman of the Board, Chief Executive Officer or President on
three days' notice to each Director, either personally or by mail,
telephone or telegram; special meetings shall be called by the Chairman,
Chief Executive Officer, President or Secretary in like manner and on
like notice on the written request of a majority of the Board of
Directors.
3.07 Quorum. At all meetings of the Board, a majority of the
Directors shall constitute a quorum for the transaction of business and
the act of a majority of the Directors present at any such meeting at
which there is a quorum shall be the act of the Board of Directors,
except as may be otherwise specifically provided by statute, the
Certificate of Incorporation or by these Bylaws. If a quorum shall not be
present at any meeting of the Board of Directors, the Directors present
may adjourn the meeting from time to time, without notice other than
announcement at the meeting, until a quorum shall be present.
3.08 Participation of Directors by Conference Telephone. Unless
otherwise restricted by the Certificate of Incorporation or these Bylaws,
any member of the Board, or of any committee designated by the Board, may
participate in any meeting of such Board or committee by means of
conference telephone or similar communication equipment by means of which
all persons participating in the meeting can hear each other.
Participation in any meeting by means of conference telephone or similar
communications equipment shall constitute presence in person at such
meeting.
3.09 Written Action of Directors. Unless otherwise restricted by the
Certificate of Incorporation or these Bylaws, any action required or
permitted to be taken at any meeting of the Board of Directors or of any
committee thereof may be taken without a meeting, if all members of the
Board or committee, as the case may be, consent thereto in writing, and
the writing or writings are filed with the minutes of proceedings of the
Board or committee.
3.10 Committees. The Board of Directors may by resolution passed by
a majority of the whole Board designate one or more committees, each
committee to consist of two or more Directors of the Corporation. The
Board may designate one or more Directors as alternate members of any
committee who may replace any absent or disqualified member at any
meeting of the committee. In the absence or disqualification of a member
of a committee, the member or members thereof present at any meeting and
not disqualified from voting, whether or not he or they constitute a
quorum, may unanimously appoint another member of the Board of Directors
to act at the meeting in the place of any such absent or disqualified
member. The Chairman of the Board shall appoint another member of the
Board of Directors to fill any committee vacancy which may occur. Any
such committee shall have, and may exercise, the power and authority
specifically granted by the Board to the committee, but no such committee
shall have the power or authority to amend the Certificate of
Incorporation, adopt an agreement of merger or consolidation, recommend
to the stockholders the sale, lease or exchange of the Corporation's
property and assets, recommend to the stockholders a dissolution of the
Corporation or a revocation of a dissolution, or amend the Bylaws of the
Corporation. Such committee or committees shall have such name or names
as may be determined from time to time by resolution adopted by the Board
of Directors.
3.11 Reports of Committees. Each committee shall keep regular
minutes of its meetings and report the same to the Board of Directors
when required.
3.12 Compensation of Directors. Unless otherwise restricted by the
Certificate of Incorporation, the Board of Directors shall have the
authority to fix the compensation of Directors. The Directors may be paid
their expenses, if any, of attendance at each meeting of the Board of
Directors and may be paid a fixed sum for attendance at each meeting of
the Board of Directors or a stated salary as Director. No such payment
shall preclude any Director from serving the Corporation in any other
capacity and receiving compensation therefor. Members of special or
standing committees may be allowed compensation for attending committee
meetings.
3.13 Chairman and Vice Chairman of the Board. The Chairman of the
Board of Directors shall be chosen by the Board of Directors at its first
meeting after the annual meeting of the stockholders of the Corporation.
The Chairman shall preside at all meetings of the Board of Directors and
stockholders of the Corporation, and shall, subject to the direction and
control of the Board, be its representative and medium of communication,
and shall perform such duties as may from time to time be assigned to the
Chairman by the Board. The Vice Chairman shall be a Director and shall
preside at all meetings of the stockholders and the Board of Directors in
the absence of the Chairman of the Board.
NOTICES
4.01 Notices. Whenever, under the provisions of the statutes or of
the Certificate of Incorporation or of these Bylaws, notice is required
to be given to any Director or stockholder, it shall not be construed to
mean personal notice, but such notice may be given in writing, by mail,
addressed to such Director or stockholder, at his address as it appears
on the records of the Corporation, with postage thereon prepaid, and such
notice shall be deemed to be given at the time when the same shall be
deposited in the United States mail. Notice to Directors may also be
given by telegram or telephone.
4.02 Waiver. Whenever any notice is required to be given under the
provisions of the statutes or of the Certificate of Incorporation or of
these Bylaws, a waiver thereof in writing, signed by the person or
persons entitled to said notice, whether before or after the time stated
therein, shall be deemed equivalent thereto.
OFFICERS
5.01 Election, Qualifications. The officers of the Corporation shall
be chosen by the Board of Directors at its first meeting after each
annual meeting of stockholders and shall include a President, a Chief
Executive Officer, a Chief Operating Officer, a Vice President, a
Secretary and a Treasurer. The Board of Directors may also choose
additional Vice Presidents, and one or more Assistant Vice Presidents,
Assistant Secretaries and Assistant Treasurers. Any number of offices may
be held by the same person, unless the Certificate of Incorporation or
these Bylaws otherwise provide.
5.02 Additional Officers. The Board of Directors may appoint such
other officers and agents as it shall deem necessary, who shall hold
their offices for such terms and shall exercise such powers and perform
such duties as shall be determined from time to time by the Board.
5.03 Salaries. The salaries of all principal officers of the
Corporation shall be fixed by the Board of Directors.
5.04 Term. The officers of the Corporation shall hold office until
their successors are chosen and qualify. Any officer elected or appointed
by the Board of Directors may be removed at any time by the affirmative
vote of a majority of the Board of Directors. Any vacancy occurring in
any office of the Corporation shall be filled by the Board of Directors.
5.05 Chief Executive Officer. The Chief Executive Officer shall,
subject to the authority of the Board of Directors, determine the general
policies of the Corporation. The Chief Executive Officer shall submit a
report of the operations of the Company for the fiscal year to the
stockholders at their annual meeting and from time to time shall report
to the Board of Directors all matters within his knowledge which the
interests of the Corporation may require be brought to the Board's
notice.
5.06 The President. The President shall have general and active
management of the business of the Corporation and shall see that all
orders and resolutions of the Board of Directors are carried into effect.
5.07 The Chief Operating Officer. The Chief Operating Officer shall
have general management oversight of the subsidiaries and divisions of
the Corporation.
5.08 The Vice Presidents. In the absence of the President or in the
event of his inability or refusal to act, the Vice President (or in the
event there be more than one Vice President, the Vice Presidents in the
order designated, or in the absence of any designation, then in the order
of their election) shall perform the duties of the President, and when so
acting, shall have all the powers of and be subject to all the
restrictions upon the President. The Vice Presidents shall perform such
other duties and have such other powers as the Board of Directors may
from time to time prescribe.
5.09 The Secretary and Assistant Secretaries. The Secretary shall
record all the proceedings of the meetings of the stockholders and
Directors in a book to be kept for that purpose. He shall give, or cause
to be given, notice of all meetings of the stockholders and special
meetings of the Board of Directors, and shall perform such other duties
as may be prescribed by the Board of Directors or Chief Executive
Officer, under whose supervision he shall be. He shall have custody of
the corporate seal of the Corporation and he, or an assistant secretary,
shall have authority to affix the same to any instrument requiring it.
The Board of Directors may give general authority to any other officer to
affix the seal of the Corporation.
The Assistant Secretary, or if there be more than one, the
Assistant Secretaries in the order determined by the Board of Directors
(or if there be no such determination, then in the order of their
election) shall, in the absence of the Secretary or in the event of his
inability or refusal to act, perform the duties and exercise the powers
of the Secretary and shall perform such other duties and have such other
powers as the Board of Directors may from time to time prescribe.
5.10 Treasurer and Assistant Treasurers. The Treasurer shall have
the custody of the corporate funds and securities and shall keep full and
accurate accounts of receipts and disbursements in books belonging to the
Corporation and shall deposit all moneys and other valuable effects in
the name and to the credit of the Corporation in such depositories as may
be designated by the Board of Directors.
He shall disburse the funds of the Corporation as may be ordered
by the Board of Directors, taking proper vouchers for such disbursements,
and shall render to the President and the Board of Directors, at its
regular meetings, or when the Board of Directors so requires, an account
of all his transactions as Treasurer and of the financial condition
of the Corporation.
If required by the Board of Directors, he shall give the
Corporation a bond (which shall be renewed every six years) in such sum
and with such surety or sureties as shall be satisfactory to the Board of
Directors for the faithful performance of the duties of his office and
for the restoration to the Corporation, in case of his death,
resignation, retirement or removal from office, of all books, papers,
vouchers, money and other property of whatever kind in his possession or
under his control belonging to the Corporation.
The Assistant Treasurer, or if there shall be more than one, the
Assistant Treasurers in the order determined by the Board of Directors
(or if there be no such determination, then in the order of their
election), shall, in the absence of the Treasurer or in the event of
his inability or refusal to act, perform the duties and exercise the
powers of the Treasurer and shall perform such other duties and have such
other powers as the Board of Directors may from time to time prescribe.
5.11 Authority and Duties. In addition to the foregoing authority
and duties, all officers of the Corporation shall respectively have such
authority and perform such duties in the management of the business of
the Corporation as may be designated from time to time by the Board of
Directors.
5.12 Execution of Instruments. All deeds, bonds, mortgages, notes,
contracts and other instruments requiring the seal of the Corporation
shall be executed on behalf of the Corporation by the Chief Executive
Officer, President, Chief Operating Officer or a Vice President and
attested by the Secretary or an Assistant Secretary or by the Treasurer
or an Assistant Treasurer, except where the execution and attestation
thereof shall be expressly delegated by the Board of Directors to some
other officer or agent of the Corporation. When authorized by the Board
of Directors, the signature of any officer or agent of the Corporation
may be a facsimile.
5.13 Execution of Proxies. All capital stocks in other corporations
owned by this Corporation shall be voted at the meetings, regular and/or
special, of stockholders of said other corporations by the Chief
Executive Officer, President, or Chief Operating Officer of this
Corporation, or, in the absence of any of them, by a Vice President, and
in the event of the presence of more than one Vice President of this
Corporation, then by a majority of said Vice Presidents present at such
stockholders meetings, and the Chief Executive Officer, President, or
Chief Operating Officer and Secretary of this Corporation are hereby
authorized to execute in the name and under the seal of this Corporation
proxies in such form as may be required by the corporations whose stock
may be owned by this Corporation, naming as the attorney authorized to
act in said proxy such individual or individuals as to said Chief
Executive Officer, President, or Chief Operating Officer and Secretary
shall deem advisable, and the attorney or attorneys so named in said
proxy shall, until the revocation or expiration thereof, vote said stock
at such stockholders meetings only in the event that none of the officers
of this Corporation authorized to execute said proxy shall be present
thereat.
CERTIFICATES OF STOCK
6.01 Certificates. Every holder of stock in the Corporation shall be
entitled to have a certificate signed by, or signed in the name of the
Corporation by, the Chairman or Vice Chairman of the Board of Directors,
or the Chief Executive Officer, President, Chief Operating Officer or a
Vice President and by the Treasurer or an Assistant Treasurer, or the
Secretary or an Assistant Secretary of the Corporation, certifying the
number of shares owned by him in the Corporation.
6.02 Signatures. Any of or all the signatures on the certificates
may be facsimile. In case any officer, transfer agent or registrar who
has signed or whose facsimile signature has been placed upon a
certificate shall have ceased to be such officer, transfer agent or
registrar before such certificate is issued, it may be issued by the
Corporation with the same effect as if he were such officer, transfer
agent or registrar at the date of issue.
6.03 Special Designation on Certificates. If the Corporation shall
be authorized to issue more than one class of stock or more than one
series of any class, the powers, designations, preferences and relative,
participating, optional or other special rights of each class of stock or
series thereof and the qualifications, limitations, or restrictions of
such preferences and/or rights shall be set forth in full or summarized
on the face or back of the certificate which the Corporation shall issue
to represent such class or series of stock, provided, that, except as
otherwise provided in Section 202 of the General Corporation Law of
Delaware in lieu of the foregoing requirements, there may be set forth on
the face or back of the certificate which the Corporation shall issue to
represent such class or series of stock, a statement that the Corporation
will furnish, without charge to each stockholder who so requests, the
powers, designations, preferences and relative, participating, optional
or other special rights of each class of stock or series thereof and the
qualifications, limitations or restrictions of such preferences and/or
rights.
6.04 Lost Certificates. The Board of Directors may direct a new
certificate or certificates to be issued in place of any certificate or
certificates theretofore issued by the Corporation alleged to have been
lost, stolen or destroyed, upon the making of an affidavit of that fact
by the person claiming the certificate of stock to be lost, stolen or
destroyed. When authorizing such issue of a new certificate or
certificates, the Board of Directors may, in its discretion and as a
condition precedent to the issuance thereof, require the owner of such
lost, stolen or destroyed certificate or certificates, or his legal
representative, to advertise the same in such manner as it shall require
and/or to give the Corporation a bond in such sum as it may direct as
indemnity against any claim that may be made against the Corporation with
respect to the certificate alleged to have been lost, stolen or
destroyed.
6.05 Transfers of Stock. Upon surrender to the Corporation or the
transfer agent of the Corporation of a certificate for shares duly
endorsed or accompanied by proper evidence of succession, assignation or
authority to transfer, it shall be the duty of the Corporation to issue a
new certificate to the person entitled thereto, cancel the old
certificate and record the transaction upon its books.
6.06 Record Date. In order that the Corporation may determine the
stockholders entitled to notice of or to vote at any meeting of
stockholders or any adjournment thereof, or to express consent to
corporate action in writing without a meeting, or entitled to
receive payment of any dividend or other distribution or allotment of any
rights, or entitled to exercise any rights in respect of any change,
conversion or exchange of stock or for the purpose of any other lawful
action, the Board of Directors may fix, in advance, a record date, which
shall not be more than sixty days nor less than ten days before the date
of such meeting, nor more than sixty days prior to any other action. A
determination of stockholders of record entitled to notice of or to vote
at a meeting of stockholders shall apply to any adjournment of the
meeting; provided, however, that the Board of Directors may fix a new
record date for the adjourned meeting.
6.07 Registered Stockholders. The Corporation shall be entitled to
recognize the exclusive right of a person registered on its books as the
owner of shares to receive dividends, and to vote as such owner, and to
hold liable for calls and assessments a person registered on its books as
the owner of shares, and shall not be bound to recognize any equitable or
other claim to or interest in such share or shares on the part of any
other person, whether or not it shall have express or other notice
thereof, except as otherwise provided by the laws of Delaware.
GENERAL PROVISIONS
7.01 Dividends. Dividends upon the capital stock of the
Corporation, subject to the provisions of the Certificates of
Incorporation, if any, may be declared by the Board of Directors at any
regular or special meeting, pursuant to law. Dividends may be paid in
cash, in property, or in shares of the capital stock, subject to the
provisions of the Certificates of Incorporation.
Before payment of any dividend, there may be set aside out of
the funds of the Corporation available for dividends such sum or sums as
the Directors from time to time, in their absolute discretion, think
proper as a reserve or reserves to meeting contingencies, or for
equalizing dividends, or for repairing or maintaining any property of the
Corporation, or for such other purpose as the Directors shall think
conducive to the interest of the Corporation, and the Directors may
modify or abolish any such reserve in the manner in which it was created.
7.02 Checks. All checks or demands for money and notes of the
Corporation shall be signed by such officer or officers or such other
person or persons as the Board of Directors may from time to time
designate or as designated by an officer of the company if so authorized
by the Board of Directors.
7.03 Fiscal year. The fiscal year of the Corporation shall be the
calendar year.
7.04 Seal. The corporate seal shall have inscribed thereon the name
of the Corporation, the year of its organization and the words "Corporate
Seal, Delaware." The seal may be used by causing it or a facsimile thereof to
be impressed or affixed or imprinted, or otherwise.
7.05 Inspection of Books and Records. Any stockholder of record, in
person or by attorney or other agent, shall, upon written demand under
oath stating the purpose thereof, have the right, during the usual hours
of business, to inspect for any proper purpose the Corporation's stock
ledger, a list of its stockholders, and its other books and records, and
to make copies or extracts therefrom. A proper purpose shall mean a
purpose reasonably related to such person's interest as a stockholder. In
every instance where an attorney or other agent shall be the person who
seeks the right to inspection, the demand under oath shall be accompanied
by a power of attorney or such other writing which authorizes the
attorney or other agent to so act on behalf of the stockholder. The
demand under oath shall be directed to the Corporation at its registered
office in the State of Delaware or at its principal place of business in
Bismarck, North Dakota.
7.06 Amendments. These Bylaws may be altered, amended or repealed
or new Bylaws may be adopted by the stockholders or by the Board of
Directors, when such power is conferred upon the Board of Directors by
the Certificate of Incorporation, at any regular meeting of the
stockholders or of the Board of Directors or at any special meeting of
the stockholders or of the Board of Directors if notice of such
alteration, amendment, repeal or adoption of new Bylaws be contained in
the notice of such special meeting.
7.07 Indemnification of Officers, Directors, Employees and Agents;
Insurance.
(a) The Corporation shall indemnify any person who was or is a
party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal,
administrative or investigative (other than an action by or in the right
of the Corporation) by reason of the fact that such person is or was a
director, officer, employee or agent of the Corporation, or is or was
serving at the request of the Corporation as a director, officer,
employee or agent of another corporation, partnership, joint venture,
trust or other enterprise, against expenses (including attorneys' fees),
judgments, fines and amounts paid in settlement actually and reasonably
incurred by such person in connection with such action, suit or
proceeding if such person acted in good faith and in a manner such person
reasonably believed to be in or not opposed to the best interests of the
Corporation, and, with respect to any criminal action or proceeding, had
no reasonable cause to believe such person's conduct was unlawful. The
termination of any action, suit or proceeding by judgment, order,
settlement, conviction, or upon a plea of nolo contendere or its
equivalent, shall not, of itself, create a presumption that the person
did not act in good faith and in a manner which such person reasonably
believed to be in or not opposed to the best interest of the Corporation,
and, with respect to any criminal action or proceeding, had reasonable
cause to believe that such person's conduct was unlawful.
(b) The Corporation shall indemnify any person who was or is a
party or is threatened to be made a party to any threatened, pending or
completed action or suit by or in the right of the Corporation to procure
a judgment in its favor by reason of the fact that such person is or was
a director, officer, employee or agent of the Corporation, or is or was
serving at the request of the Corporation as a director, officer,
employee or agent of another corporation, partnership, joint venture,
trust or other enterprise against expenses (including attorneys' fees)
actually and reasonably incurred by such person in connection with the
defense or settlement of such action or suit if such person acted in good
faith and in a manner such person reasonably believed to be in or not
opposed to the best interests of the Corporation and except that no
indemnification shall be made in respect of any claim, issue or matter as
to which such person shall have been adjudged to be liable to the
Corporation, unless and only to the extent that the Court of Chancery or
the court in which such action or suit was brought, shall determine upon
application that, despite the adjudication of liability but in view of
all circumstances of the case, such person is fairly and reasonably
entitled to indemnity for such expenses which the Court of Chancery or
such other court shall deem proper.
(c) To the extent that a present or former director, officer,
employee or agent of a corporation has been successful on the merits or
otherwise in defense of any action, suit or proceeding referred to in
subsections (a) and (b), or in defense of any claim, issue or matter
therein, such person shall be indemnified against expenses (including
attorneys' fees) actually and reasonably incurred by such person in
connection therewith.
(d) Any indemnification under subsections (a) and (b) of this
Section (unless ordered by a court) shall be made by the Corporation only
as authorized in the specific case upon a determination that
indemnification of the present or former director, officer, employee or
agent is proper in the circumstances because such person has met the
applicable standard of conduct as set forth in subsections (a) and (b) of
this Section. Such determination shall be made (1) by a majority vote of
the directors who are not parties to such action, suit or proceeding,
even though less than a quorum, or (2) by a committee of such directors
designated by majority vote of such directors, even though less than a
quorum, or (3) if there are no such directors, or if such directors so
direct, by independent legal counsel in a written opinion, or (4) by the
stockholders.
(e) Expenses (including attorneys' fees) incurred by a present or
former officer or director in defending any civil, criminal,
administrative or investigative action, suit or proceeding shall be paid
by the Corporation in advance of the final disposition of such action,
suit or proceeding upon receipt of an undertaking by or on behalf of the
director or officer to repay such amount if it shall ultimately be
determined that such person is not entitled to be indemnified by the
Corporation as authorized in this Section. Once the Corporation has
received the undertaking, the Corporation shall pay the officer or
director within 30 days of receipt by the Corporation of a written
application from the officer or director for the expenses incurred by
that officer or director. In the event the Corporation fails to pay
within the 30-day period, the applicant shall have the right to sue for
recovery of the expenses contained in the written application and, in
addition, shall recover all attorneys' fees and expenses incurred in the
action to enforce the application and the rights granted in this Section
7.07. Expenses (including attorneys' fees) incurred by other employees
and agents shall be paid upon such terms and conditions, if any, as the
Board of Directors deems appropriate.
(f) The indemnification and advancement of expenses provided by, or
granted pursuant to, the other subsections of this Section shall not be
deemed exclusive of any other rights to which those seeking indemnity or
advancement of expenses may be entitled under any bylaw, agreement, vote
of stockholders or disinterested directors or otherwise, both as to
action in such person's official capacity and as to action in another
capacity while holding such office.
(g) The Corporation may purchase and maintain insurance on behalf
of any person who is or was a director, officer, employee or agent of the
Corporation, or is or was serving at the request of the Corporation as a
director, officer, employee or agent of another corporation, partnership,
joint venture, trust or other enterprise, against any liability asserted
against such person and incurred by such person in any such capacity, or
arising out of such person's status as such, whether or not the
Corporation would have the power to indemnify such person against such
liability under the provisions of this Section.
(h) For the purposes of this Section, references to "the
Corporation" include all constituent corporations absorbed in a
consolidation or merger, as well as the resulting or surviving
corporation, so that any person who is or was a director, officer,
employee or agent of such a constituent corporation or is or was serving
at the request of such constituent corporation as a director, officer,
employee or agent of another corporation, partnership, joint venture,
trust or other enterprise, shall stand in the same position under the
provisions of this Section with respect to the resulting or surviving
corporation as such person would if such person had served the resulting
or surviving corporation in the same capacity.
(i) For purposes of this Section, references to "other enterprises"
shall include employee benefit plans; references to "fines" shall include
any excise taxes assessed on a person with respect to any employee
benefit plan; and references to "serving at the request of the
Corporation" shall include any service as a director, officer, employee
or agent of the Corporation which imposes duties on, or involves services
by, such director, officer, employee or agent with respect to an employee
benefit plan, its participants or beneficiaries; and a person who acted
in good faith and in a manner such person reasonably believed to be in
the interest of the participants and beneficiaries of an employee benefit
plan shall be deemed to have acted in a manner "not opposed to the best
interests of the Corporation" as referred to in this Section.
(j) The indemnification and advancement of expenses provided by, or
granted pursuant to, this Section shall, unless otherwise provided when
authorized or ratified, continue as to a person who has ceased to be a
director, officer, employee or agent and shall inure to the benefit of
the heirs, executors and administrators of such a person.
MDU RESOURCES GROUP, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Years Ended December 31,
1997 1996 1995 1994 1993
(In thousands of dollars)
Earnings Available for
Fixed Charges:
Net Income per
Consolidated
Statements of
Income $ 54,617 $ 45,470 $ 41,633 $ 39,845 $ 38,817*
Income Taxes 30,743 16,087 23,057 18,833 19,982*
85,360 61,557 64,690 58,678 58,799
Rents (a) 1,249 1,031 894 878 871
Interest (b) 33,047 34,101 29,924 29,173 27,928
Total Earnings
Available for
Fixed Charges $119,656 $ 96,689 $ 95,508 $ 88,729 $ 87,598*
Preferred Dividend
Requirements $ 782 $ 787 $ 792 $ 797 $ 802
Ratio of Income
Before Income
Taxes to Net
Income 156% 135% 155% 147% 151%
Preferred Dividend
Factor on Pretax
Basis 1,220 1,062 1,228 1,172 1,211
Fixed Charges (c) 34,296 35,132 30,818 30,051 28,799
Combined Fixed
Charges and
Preferred Stock
Dividends $ 35,516 $ 36,194 $ 32,046 $ 31,223 $ 30,010
Ratio of Earnings
to Fixed Charges 3.49x 2.75x 3.10x 2.95x 3.04x*
Ratio of Earnings
to Combined
Fixed Charges
and Preferred
Stock Dividends 3.37x 2.67x 2.98x 2.84x 2.92x*
* Before cumulative effect of accounting change of $5,521 (net of
income taxes).
(a) Represents portion (33 1/3%) of rents which is estimated to
approximately constitute the return to the lessors on their
investment in leased premises.
(b) Represents interest and amortization of debt discount and expense on
all indebtedness and excludes amortization of gains or losses on
reacquired debt which, under the Uniform System of Accounts, is
classified as a reduction of, or increase in, interest expense in
the Consolidated Statements of Income. Also includes carrying costs
associated with natural gas available under a repurchase agreement
with Frontier Gas Storage Company as more fully described in Notes
to Consolidated Financial Statements.
(c) Represents rents and interest, both as defined above.
MDU RESOURCES GROUP, INC.
1997 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with generally accepted accounting principles as applied to
the company's regulated and non-regulated businesses and necessarily
include some amounts that are based on informed judgments and
estimates of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis,
that transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an
organizational structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Audit Department. In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct. Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions. The company's
Internal Audit Department is charged with the responsibility for
determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Arthur Andersen LLP have full and free access to the
audit committee, without management present, to discuss auditing,
internal accounting control and financial reporting matters.
Arthur Andersen LLP is engaged to express an opinion on the financial
statements. Their audit is conducted in accordance with generally
accepted auditing standards and includes examining, on a test basis,
supporting evidence, assessing the company's accounting principles
used and significant estimates made by management and evaluating the
overall financial statement presentation to the extent necessary to
allow them to report on the fairness, in all material respects, of the
financial condition and operating results of the company.
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1997 1996 1995
(In thousands, except per share amounts)
Operating Revenues
Electric $164,351 $138,761 $134,609
Natural gas 200,789 175,408 167,787
Construction materials and mining 174,147 132,222 113,066
Oil and natural gas production 68,387 68,310 48,784
607,674 514,701 464,246
Operating Expenses
Fuel and purchased power 45,604 43,983 41,769
Purchased natural gas sold 77,082 48,886 53,351
Operation and maintenance 283,894 225,682 202,327
Depreciation, depletion and
amortization 65,767 62,651 54,825
Taxes, other than income 23,766 21,974 21,398
496,113 403,176 373,670
Operating Income
Electric 33,089 29,476 29,898
Natural gas distribution 10,410 11,504 6,917
Natural gas transmission 29,169 30,231 25,427
Construction materials and mining 14,602 16,062 14,463
Oil and natural gas production 24,291 24,252 13,871
111,561 111,525 90,576
Other income -- net 4,008 5,617 4,789
Interest expense 30,209 28,832 24,690
Costs on natural gas
repurchase commitment (Note 3) --- 26,753 5,985
Income before income taxes 85,360 61,557 64,690
Income taxes 30,743 16,087 23,057
Net income 54,617 45,470 41,633
Dividends on preferred stocks 782 787 792
Earnings on common stock $53,835 $44,683 $40,841
Earnings per common share--basic $1.86 $1.57 $1.43
Earnings per common share--diluted $1.86 $1.57 $1.43
Dividends per common share $1.13 $1.10 $1.0782
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1997 1996
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents $ 28,174 $ 47,799
Receivables 80,585 73,187
Inventories 41,322 27,361
Deferred income taxes 17,356 26,011
Prepayments and other current assets 12,479 17,300
179,916 191,658
Investments (Note 15) 18,935 53,501
Property, Plant and Equipment
Electric 566,247 546,477
Natural gas distribution 172,086 164,843
Natural gas transmission 288,709 273,775
Construction materials and mining 243,110 173,663
Oil and natural gas production 240,193 211,555
1,510,345 1,370,313
Less accumulated depreciation,
depletion and amortization 670,809 617,724
839,536 752,589
Deferred charges and other assets 75,505 91,425
$1,113,892 $1,089,173
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Short-term borrowings $ 3,347 $ 3,950
Long-term debt and preferred
stock due within one year 7,902 11,854
Accounts payable 31,571 31,580
Taxes payable 9,057 8,683
Dividends payable 8,574 8,099
Other accrued liabilities,
including reserved revenues 88,563 100,938
149,014 165,104
Long-term debt (Note 11) 298,561 280,666
Deferred credits and other liabilities
Deferred income taxes 119,747 116,208
Other liabilities (Note 3) 143,574 159,721
263,321 275,929
Commitments and contingencies
(Notes 2, 3, 4 and 14)
Stockholders' Equity
Preferred stocks (Note 10) 16,700 16,800
Common stockholders' equity
Common stock (Note 9)
Authorized -- 75,000,000 shares,
$3.33 par value
Outstanding -- 29,143,332 and 28,476,981
shares in 1997 and
1996, respectively 97,047 94,828
Other paid-in capital 76,526 64,305
Retained earnings 212,723 191,541
Total common stockholders' equity 386,296 350,674
Total stockholders' equity 402,996 367,474
$1,113,892 $1,089,173
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
MDU RESOURCES GROUP, INC.
Years ended Other
December 31, Common Stock Paid-In Retained
1997, 1996 and 1995 Shares Amount Capital Earnings Total
(In thousands, except shares)
Balance at
December 31, 1994 18,984,654 $63,219 $95,914 $168,050 $327,183
Net income --- --- --- 41,633 41,633
Dividends on
preferred stocks --- --- --- (792) (792)
Dividends on
common stock --- --- --- (30,707) (30,707)
Three-for-two
common stock
split (Note 9) 9,492,327 31,609 (31,609) --- ---
Balance at
December 31, 1995 28,476,981 94,828 64,305 178,184 337,317
Net income --- --- --- 45,470 45,470
Dividends on
preferred stocks --- --- --- (787) (787)
Dividends on
common stock --- --- --- (31,326) (31,326)
Balance at
December 31, 1996 28,476,981 94,828 64,305 191,541 350,674
Net income --- --- --- 54,617 54,617
Dividends on
preferred stocks --- --- --- (782) (782)
Dividends on
common stock --- --- --- (32,653) (32,653)
Issuance of common
stock:
Acquisitions 225,629 751 3,622 --- 4,373
Other 440,722 1,468 8,599 --- 10,067
Balance at
December 31, 1997 29,143,332 $97,047 $76,526 $212,723 $386,296
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1997 1996 1995
(In thousands)
Operating Activities
Net income $ 54,617 $ 45,470 $ 41,633
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 65,767 62,651 54,825
Deferred income taxes and
investment tax credit -- net 7,152 4,551 7,631
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 3,360 6,580 7,177
Write-down of natural gas
available under repurchase
commitment, net of income
taxes (Note 3) --- 11,364 ---
Changes in current assets and
liabilities:
Receivables 6,951 (9,346) (6,552)
Inventories (4,214) (1,218) 3,141
Other current assets 10,681 4,185 (3,943)
Accounts payable (5,605) 7,584 2,039
Other current liabilities (6,087) (22,434) 17,177
Other noncurrent changes 6,007 (3,149) (1,023)
Net cash provided by operating
activities 138,629 106,238 122,105
Financing Activities
Net change in short-term borrowings (5,919) 3,350 (80)
Issuance of long-term debt 54,064 81,300 36,710
Repayment of long-term debt (47,899) (43,262) (20,433)
Retirement of preferred stocks (100) (100) (100)
Issuance of common stock 10,067 --- ---
Retirement of natural gas
repurchase commitment (52,090) (4,157) (204)
Dividends paid (33,435) (32,113) (31,499)
Net cash provided by (used in)
financing activities (75,312) 5,018 (15,606)
Investing Activities
Capital expenditures including
acquisitions of businesses:
Electric (18,713) (18,674) (19,689)
Natural gas distribution (8,858) (6,255) (8,878)
Natural gas transmission (13,205) (10,127) (9,688)
Construction materials and mining (40,797) (25,063) (36,810)
Oil and natural gas production (30,651) (51,821) (39,917)
(112,224) (111,940) (114,982)
Net proceeds from sale or
disposition of property 4,522 11,803 2,802
Net capital expenditures (107,702) (100,137) (112,180)
Sale of natural gas available
under repurchase commitment 27,008 10,595 163
Investments (2,248) (7,313) 1,726
Net cash used in investing
activities (82,942) (96,855) (110,291)
Increase (decrease) in cash
and cash equivalents (19,625) 14,401 (3,792)
Cash and cash equivalents --
beginning of year 47,799 33,398 37,190
Cash and cash equivalents --
end of year $ 28,174 $ 47,799 $ 33,398
The accompanying notes are an integral part of these consolidated statements.
NOTE 1
Summary of Significant Accounting Policies
Basis of Presentation
The consolidated financial statements of MDU Resources Group, Inc.
(the "company") include the accounts of two regulated businesses --
retail and wholesale sales of electricity and retail sales and/or
transportation of natural gas and propane, and natural gas
transmission and storage -- and two non-regulated businesses --
construction materials and mining operations, and oil and natural gas
production. The statements also include the ownership interests in the
assets, liabilities and expenses of two jointly owned electric
generating stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the company's
non-regulated businesses.
The company's regulated businesses account for certain income and
expense items under the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Regulation" (SFAS No. 71). SFAS No. 71 allows these businesses to
defer as regulatory assets or liabilities certain items that would
have otherwise been reflected as expense or income, respectively,
based on the expected regulatory treatment in future rates. The
expected recovery or flowback of these deferred items are generally
based on specific ratemaking decisions or precedent for each item.
Regulatory assets and liabilities are being amortized consistently
with the regulatory treatment established by the FERC and the
applicable state public service commissions. See Note 6 for more
information regarding the nature and amounts of these regulatory
deferrals.
In accordance with the provisions of SFAS No. 71, intercompany coal
sales, which are made at prices approximately the same as those
charged to others, and the related utility fuel purchases are not
eliminated. All other significant intercompany balances and
transactions have been eliminated.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when
first placed in service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost and cost of removal, less salvage, is charged to accumulated
depreciation. With respect to the retirement or disposal of all other
assets, except for oil and natural gas production properties as
described below, the resulting gains or losses are recognized as a
component of income. The company is permitted to capitalize an
allowance for funds used during construction (AFUDC) on regulated
construction projects and to include such amounts in rate base when
the related facilities are placed in service. In addition, the
company capitalizes interest, when applicable, on certain construction
projects associated with its other operations. The amounts of AFUDC
and interest capitalized were not material in 1997, 1996 and 1995.
Property, plant and equipment are depreciated on a straight-line basis
over the average useful lives of the assets, except for oil and
natural gas production properties as described below.
Oil and Natural Gas
The company uses the full-cost method of accounting for its oil and
natural gas production activities. Under this method, all costs
incurred in the acquisition, exploration and development of oil and
natural gas properties are capitalized and amortized on the units of
production method based on total proved reserves. Cost centers for
amortization purposes are determined on a country-by-country basis.
Capitalized costs are subject to a "ceiling test" that limits such
costs to the aggregate of the present value of future net revenues of
proved reserves and the lower of cost or fair value of unproved
properties. Any conveyances of properties, including gains or losses
on abandonments of properties, are treated as adjustments to the cost
of the properties with no gain or loss realized.
Natural Gas in Underground Storage and Available Under Repurchase
Commitment
Natural gas in underground storage is carried at cost using the
last-in, first-out (LIFO) method. That portion of the cost of natural
gas in underground storage expected to be used within one year is
included in inventories.
Natural gas available under a repurchase commitment with Frontier Gas
Storage Company (Frontier) is carried at Frontier's cost of purchased
natural gas, less an allowance to reflect changed market conditions
and is reflected on the company's Consolidated Balance Sheets in
"Deferred charges and other assets". See Note 3 for discussion on the
write-down which occurred in 1996 of the natural gas available under
the repurchase commitment with Frontier.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventories held for resale.
These inventories are stated at the lower of average cost or market.
Revenue Recognition
The company recognizes utility revenue each month based on the
services provided to all utility customers during the month. For its
construction business, the company recognizes revenue on the
percentage of completion method.
Natural Gas Costs Recoverable Through Rate Adjustments
Under the terms of certain orders of the applicable state public
service commissions, the company is deferring natural gas commodity,
transportation and storage costs which are greater or less than
amounts presently being recovered through its existing rate schedules.
Such orders generally provide that these amounts are recoverable or
refundable through rate adjustments within 24 months from the time
such costs are paid.
Income Taxes
The company provides deferred federal and state income taxes on all
temporary differences. Excess deferred income tax balances associated
with Montana-Dakota's and Williston Basin's rate-regulated activities
resulting from the company's adoption of SFAS No. 109, "Accounting for
Income Taxes", have been recorded as a regulatory liability and are
included in "Other liabilities" in the company's Consolidated Balance
Sheets. This regulatory liability is expected to be reflected as a
reduction in future rates charged customers in accordance with
applicable regulatory procedures.
The company uses the deferral method of accounting for investment tax
credits and amortizes the credits on electric and natural gas
distribution plant over various periods which conform to the
ratemaking treatment prescribed by the applicable state public service
commissions.
Earnings per Common Share
In 1997, the company adopted SFAS No. 128, "Earnings Per Share". The
adoption of this pronouncement did not affect previously reported
earnings per common share.
Basic earnings per common share were computed by dividing earnings on
common stock by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share were
computed by dividing earnings on common stock by the total of the
weighted average number of shares of common stock outstanding during
the year, plus the effect of outstanding stock options.
The weighted average common shares outstanding used for basic earnings
per common share (in thousands) were 28,877 in 1997 and 28,477 in both
1996 and 1995. The number of common shares used for diluted earnings
per common share (in thousands) were 28,985 in 1997, 28,549 in 1996
and 28,526 in 1995.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the company to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Estimates are used for such
items as plant depreciable lives, tax provisions, uncollectible
accounts, environmental and other loss contingencies, unbilled
revenues and actuarially determined benefit costs. As better
information becomes available, or actual amounts are determinable, the
recorded estimates are revised. Consequently, operating results can
be affected by revisions to prior accounting estimates.
Cash Flow Information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Interest, net of amount capitalized $25,626 $25,449 $24,436
Income taxes $18,171 $28,163 $18,330
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents. The
company's Consolidated Statements of Cash Flows include the effects
from acquisitions.
Reclassifications
Certain reclassifications have been made in the financial statements
for prior years to conform to the current presentation. Such
reclassifications had no effect on net income or common stockholders'
equity as previously reported.
NOTE 2
Regulatory Matters and Revenues Subject to Refund
General Rate Proceedings
Williston Basin has pending with the FERC a general natural gas rate
change application implemented in 1992. On October 20, 1997,
Williston Basin appealed to the U.S. District 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 December 10, 1997,
the FERC issued an order accepting, subject to certain conditions,
Williston Basin's July 25, 1997 compliance filing. On December 22,
1997, Williston Basin submitted a compliance filing pursuant to the
FERC's December 10, 1997 order. On December 31, 1997, Williston Basin
refunded $33.8 million to its customers, including $30.8 million to
Montana-Dakota, in addition to the $6.1 million interim refund that it
had previously made in November 1996. All such amounts had been
previously reserved. Williston Basin is awaiting an order from the
FERC on its December 22, 1997 compliance filing.
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.
NOTE 3
Natural Gas Repurchase Commitment
The company has offered for sale since 1984 the inventoried natural
gas owned by Frontier, a special purpose, non-affiliated 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, 1997, borrowings
totaled $32.0 million at a weighted average interest rate of
6.63 percent. At December 31, 1997 and 1996, the natural gas
repurchase commitment of $30.4 million and $66.3 million,
respectively, is reflected on the company's Consolidated Balance
Sheets under "Other liabilities" and $1.6 million and $17.7 million,
respectively, is reflected under "Other accrued liabilities". 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 costs to the Frontier gas were
appropriate. Williston Basin is awaiting a final order from the FERC
as to the appropriate costs to be allocated.
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, 1997 and 1996, natural gas held under the
repurchase commitment of $14.6 million and $37.2 million,
respectively, is included in the company's Consolidated Balance Sheets
under "Deferred charges and other assets". The recognition of the
then current market value of this natural gas facilitated the sale by
Williston Basin of 28.1 MMdk from the date of this write-down through
December 31, 1997, and should allow Williston Basin to market the
remaining 14.9 MMdk on a sustained basis enabling Williston Basin to
liquidate this asset over approximately the next three to four years.
NOTE 4
Commitments and Contingencies
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.
On June 26, 1997, the Federal District Court issued its order awarding
Moncrief damages of approximately $15.6 million. On July 25, 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. On August 25, 1997,
Moncrief filed a notice of appeal with the United States Court of
Appeals for the Tenth Circuit related to the Federal District Court's
orders. On September 2, 1997, Williston Basin and the company filed a
notice of cross-appeal.
Williston Basin believes that it is entitled to recover from
ratepayers virtually all of the costs ultimately incurred as a result
of these orders 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 recently
provided alleged damages under differing theories ranging 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 on November 6, 1997.
Williston Basin and the company are awaiting a decision from the North
Dakota District Court.
In a related matter, on March 14, 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 specified.
In Williston Basin's opinion, the claims of Apache and Snyder 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
ratepayers.
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 electrical
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 of 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 January 1996, the company and Knife River
filed separate motions with the State District Court to dismiss or
stay, pending arbitration. In May 1996, the State District Court
granted the company's and Knife River's motions and 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 order
dated April 25, 1997, 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, of approximately $50 million
or more. 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. By letter dated May 14, 1997, Knife River
requested permission to move for summary judgment which permission was
granted by the arbitration panel over objections of the Co-owners.
Knife River filed its summary judgment motion on July 21, 1997, which
motion was denied on October 29, 1997. 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.
For a description of litigation filed by Unitek Environmental
Services, Inc. and Unitek Solvent Services, Inc. against Hawaiian
Cement, see Environmental Matters.
The company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that there is no
pending legal proceeding against or involving the company, except
those discussed above, for which the outcome is likely to have a
material adverse effect upon the company's financial position or
results of operations.
Environmental Matters
Montana-Dakota and Williston Basin discovered polychlorinated
biphenyls (PCBs) in portions of their natural gas systems and informed
the U.S. Environmental Protection Agency (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
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.
In September 1995, Unitek Environmental Services, Inc. and Unitek
Solvent Services, Inc. (Unitek) filed a complaint against Hawaiian
Cement in the U.S. District Court for the District of Hawaii (District
Court) alleging that dust emissions from Hawaiian Cement's cement
manufacturing plant at Kapolei, Hawaii (Plant) violated the Hawaii
State Implementation Plan (SIP) of the U.S. Clean Air Act (Clean Air
Act), constituted a continual nuisance and trespass on the plaintiff's
property, and that Hawaiian Cement's conduct warranted the award of
punitive damages. Hawaiian Cement is a Hawaiian general partnership
whose general partners are now Knife River Hawaii, Inc. and Knife
River Dakota, Inc., indirect wholly owned subsidiaries of the company.
Knife River Dakota, Inc. purchased its partnership interest from
Adelaide Brighton Cement (Hawaii), Inc. on July 31, 1997. Unitek
sought civil penalties under the Clean Air Act (as described below),
and up to $20 million in damages for various claims (as described
above).
In August 1996, the District Court issued an order granting
Plaintiffs' motion for partial summary judgment relating to the Clean
Air Act, indicating that it would issue an injunction shortly. The
issue of civil penalties under the Clean Air Act was reserved for
further hearing at a later date, and Unitek's claims for damages were
not addressed by the District Court at such time.
In September 1996, Unitek and Hawaiian Cement reached a settlement
which resolved all claims except as to Clean Air Act penalties. Based
on a joint petition filed by Unitek and Hawaiian Cement, the District
Court stayed the proceeding and the issuance of an injunction while
the parties continued to negotiate the remaining Clean Air Act claims.
In May 1996, the EPA issued a Notice of Violation (NOV) to Hawaiian
Cement. The NOV stated that dust emissions from the Plant violated
the SIP. Under the Clean Air Act, the EPA has the authority to issue
an order requiring compliance with the SIP, issue an administrative
order requiring the payment of penalties of up to $25,000 per day per
violation (not to exceed $200,000), or bring a civil action for
penalties of not more than $25,000 per day per violation and/or bring
a civil action for injunctive relief.
On April 7, 1997, a settlement resolving the remaining Clean Air Act
claims and the EPA's NOV issued in May 1996, was reached by Hawaiian
Cement, the EPA and Unitek. This settlement is subject to public
comment and the approval of the District Court.
If the District Court approves the April 1997 settlement, the total
costs relating to both the September 1996 and April 1997 settlements
are not expected to have a material effect on the company's results of
operations.
Electric Purchased Power Commitments
Montana-Dakota has contracted to purchase through October 31, 2006,
66,400 kW of participation power from Basin Electric Power
Cooperative. In addition, Montana-Dakota, under a power supply
contract through December 31, 2006, is purchasing up to 55,000 kW of
capacity from Black Hills Power and Light Company.
NOTE 5
Natural Gas in Underground Storage
Natural gas in underground storage included in natural gas
transmission and natural gas distribution property, plant and
equipment amounted to approximately $43.1 million at December 31,
1997, and $42.3 million at December 31, 1996. In addition,
$11.4 million and $7.2 million at December 31, 1997 and 1996,
respectively, of natural gas in underground storage is included in
inventories.
NOTE 6
Regulatory Assets and Liabilities
The following table summarizes the individual components of
unamortized regulatory assets and liabilities included in the
accompanying Consolidated Balance Sheets as of December 31:
1997 1996
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ --- $ 4,960
Long-term debt refinancing costs 11,466 13,520
Postretirement benefit costs 2,940 3,849
Plant costs 3,173 3,341
Other 10,899 7,890
Total regulatory assets 28,478 33,560
Regulatory liabilities:
Reserves for regulatory matters 39,193 59,277
Natural gas costs refundable
through rate adjustments 21,721 1,499
Taxes refundable to customers 13,933 12,868
Plant decommissioning costs 5,843 5,301
Other 1,393 2,433
Total regulatory liabilities 82,083 81,378
Net regulatory position $(53,605) $(47,818)
As of December 31, 1997, substantially all of the company's regulatory
assets are being reflected in rates charged to customers and are being
recovered over the next 1 to 19 years.
If for any reason, the company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 7
Financial Instruments
Derivatives
The company, in connection with the operations of Montana-Dakota,
Williston Basin and Fidelity Oil, has entered into certain price swap
and collar agreements (hedge agreements) to manage a portion of the
market risk associated with fluctuations in the price of oil and
natural gas. These hedge agreements are not held for trading
purposes. The hedge agreements call for the company to receive
monthly payments from or make payments to counterparties based upon
the difference between a fixed and a variable price as specified by
the hedge agreements. The variable price is either an oil price
quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural
gas price on the NYMEX or Colorado Interstate Gas Index. The company
believes that there is a high degree of correlation because the timing
of purchases and production and the hedge agreements are closely
matched, and hedge prices are established in the areas of the
company's operations. Amounts payable or receivable on hedge
agreements are matched and reported in operating revenues on the
Consolidated Statements of Income as a component of the related
commodity transaction at the time of settlement with the counterparty.
The amounts payable or receivable are offset by corresponding
increases and decreases in the value of the underlying commodity
transactions.
Williston Basin and Knife River have entered into interest rate
swap agreements to manage a portion of their interest rate exposure on
the natural gas repurchase commitment and long-term debt,
respectively. These interest rate swap agreements are not held for
trading purposes. The interest rate swap agreements call for the
company to receive quarterly payments from or make payments to
counterparties based upon the difference between fixed and variable
rates as specified by the interest rate swap agreements. The variable
prices are based on the three-month floating London Interbank Offered
Rate. Settlement amounts payable or receivable under these interest
rate swap agreements are recorded in "Interest expense" for Knife
River and "Costs on natural gas repurchase commitment" for Williston
Basin on the Consolidated Statements of Income in the accounting
period they are incurred. The amounts payable or receivable are
offset by interest on the related debt instruments.
The company's policy prohibits the use of derivative instruments for
trading purposes and the company has procedures in place to monitor
their use. The company is exposed to credit-related losses in the
event of nonperformance by counterparties to these financial
instruments, but does not expect any counterparties to fail to meet
their obligations given their existing credit ratings.
The following table summarizes the company's hedging activity:
Years ended December 31, 1997 1996 1995
(Notional amounts in thousands)
Oil swap/collar agreements:*
Range of fixed prices
per barrel $19.77-$21.36 $18.74-$19.07 $17.75-$20.75
Notional amount
(in barrels) 730 635 260
Natural gas swap/collar agreements:*
Range of fixed prices
per MMBtu $1.30-$2.395 $1.40-$2.05 $1.70-$1.85
Notional amount
(in MMBtu's) 8,039 5,331 644
Natural gas collar agreement:**
Fixed price per MMBtu --- $1.22-$1.52 $1.22-$1.52
Notional amount (in MMBtu's) --- 910 2,750
Interest rate swap agreements:**
Range of fixed
interest rates 5.50%-6.50% 5.50%-6.50% 5.97%
Notional amount (in dollars) $30,000 $30,000 $20,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The following table summarizes swap agreements outstanding at
December 31, 1997 (notional amounts in thousands):
Notional
Fixed Price Amount
Year (Per barrel) (In barrels)
Oil swap agreements* 1998 $20.92 219
Range of Notional
Fixed Prices Amount
Year (Per MMBtu) (In MMBtu's)
Natural gas swap agreements* 1998 $2.10-$2.67 4,370
Notional
Range of Fixed Amount
Year Interest Rates (In dollars)
Interest rate swap agreements** 1998 5.50%-6.50% $10,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The fair value of these derivative financial instruments reflects the
estimated amounts that the company would receive or pay to terminate
the contracts at the reporting date, thereby taking into account the
current favorable or unfavorable position on open contracts. The
favorable or unfavorable position is currently not recorded on the
company's financial statements. Favorable and unfavorable positions
related to oil and natural gas hedge agreements will be offset by
corresponding increases and decreases in the value of the underlying
commodity transactions. Favorable and unfavorable positions on
interest rate swap agreements will be offset by interest on the
related debt instruments. The company's net favorable position on all
swap and collar agreements outstanding at December 31, 1997, was
$1.2 million. In the event a hedge agreement does not qualify for
hedge accounting or when the underlying commodity transaction or
related debt instrument matures, is sold, is extinguished, or is
terminated, the current favorable or unfavorable position on the open
contract would be included in results of operations. The company's
policy requires approval to terminate a hedge agreement prior to its
original maturity. In the event a hedge agreement is terminated, the
realized gain or loss at the time of termination would be deferred
until the underlying commodity transaction or related debt instrument
is sold or matures and would be offset by corresponding increases or
decreases in the value of the underlying commodity transaction or
interest on the related debt instrument.
Fair Value of Other Financial Instruments
The estimated fair value of the company's long-term debt and preferred
stocks are based on quoted market prices of the same or similar
issues. The estimated fair value of the company's long-term debt and
preferred stocks at December 31 are as follows:
1997 1996
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $306,363 $319,367 $292,420 $298,592
Preferred stocks $ 16,800 $ 12,103 $ 16,900 $ 10,762
The fair value of other financial instruments for which estimated fair
values have not been presented is not materially different than the
related book value.
NOTE 8
Short-term Borrowings
The company and its subsidiaries had unsecured short-term lines of
credit from a number of banks totaling $120.4 million at December 31,
1997. These line of credit agreements provide for bank borrowings
against the lines and/or support for commercial paper issues. The
agreements provide for commitment fees at varying rates. Amounts
outstanding under the lines of credit were $3.3 million at
December 31, 1997, and $4.0 million at December 31, 1996. The
weighted average interest rate for borrowings outstanding at
December 31, 1997 and 1996, was 8.50 percent and 7.25 percent,
respectively. The unused portions of the lines of credit are subject
to withdrawal based on the occurrence of certain events.
NOTE 9
Common Stock
In August 1995, the company's Board of Directors approved a three-for-
two common stock split to be effected in the form of a 50 percent
common stock dividend. The additional shares of common stock were
distributed on October 13, 1995, to common stockholders of record on
September 27, 1995.
The company's Automatic Dividend Reinvestment and Stock Purchase Plan
(DRIP) provides participants in the DRIP the opportunity to invest all
or a portion of their cash dividends in shares of the company's common
stock and/or to make optional cash payments of up to $5,000 per month
for the same purpose. Holders of all classes of the company's capital
stock and other investors who are domiciled in the states of North
Dakota, South Dakota, Montana or Wyoming, are eligible to participate
in the DRIP. The company's Tax Deferred Compensation Savings Plans
(K-Plans) pursuant to Section 401(k) of the Internal Revenue Code are
funded with the company's common stock. Since January 1, 1989, the
DRIP and K-Plans have been funded by the purchase of shares of common
stock on the open market except for a portion of 1997, where shares of
authorized but unissued common stock were used to fund the DRIP and
K-Plans. At December 31, 1997, there were 5,547,331 shares of common
stock reserved for issuance under the DRIP and K-Plans.
In November 1988, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) on each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-hundred and fiftieth of a share of Series
A preference stock, without par value, at an exercise price of $33.33
per one one-hundred and fiftieth, subject to certain adjustments. The
rights are currently not exercisable and will be exercisable only if a
person or group (acquiring person) either acquires ownership of 20
percent or more of the company's common stock or commences a tender or
exchange offer that would result in ownership of 30 percent or more.
In the event the company is acquired in a merger or other business
combination transaction or 50 percent or more of its consolidated
assets or earnings power are sold, each right entitles the holder to
receive, upon the exercise thereof at the then current exercise price
of the right multiplied by the number of one one-hundredths of a
Series A preference share for which a right is then exercisable, in
accordance with the terms of the Rights Agreement, such number of
shares of common stock of the acquiring person having a market value
of twice the then current exercise price of the right. The rights,
which expire in November 1998, are redeemable in whole, but not in
part, for a price of $.01333 per right, at the company's option at any
time until any acquiring person has acquired 20 percent or more of the
company's common stock. Preference share purchase rights have been
appropriately adjusted to reflect the effects of the common stock
split discussed above.
NOTE 10
Preferred Stocks
Preferred stocks at December 31 are as follows:
1997 1996
(In thousands)
Authorized:
Preferred --
500,000 shares, cumulative,
par value $100, issuable in series
Preferred stock A --
1,000,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Preference --
500,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Outstanding:
Subject to mandatory redemption requirements --
Preferred --
5.10% Series -- 18,000 shares in 1997
(19,000 shares in 1996) $ 1,800 $ 1,900
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000
15,000 15,000
Total preferred stocks 16,800 16,900
Less current maturities and
sinking fund requirements 100 100
Net preferred stocks $16,700 $16,800
The preferred stocks outstanding are subject to redemption, in whole
or in part, at the option of the company with certain limitations on
30 days notice on any quarterly dividend date.
The company is obligated to make annual sinking fund contributions to
retire the 5.10% Series preferred stock. The redemption prices and
sinking fund requirements, where applicable, are summarized below:
Redemption Sinking Fund
Series Price (a) Shares Price (a)
Preferred stocks:
4.50% $105.00 (b) --- ---
4.70% $102.00 (b) --- ---
5.10% $102.00 1,000 (c) $100.00
(a) Plus accrued dividends.
(b) These series are redeemable at the sole discretion of the company.
(c) Annually on December 1, if tendered.
In the event of a voluntary or involuntary liquidation, all preferred
stock series holders are entitled to $100 per share, plus accrued
dividends.
The aggregate annual sinking fund amount applicable to preferred stock
subject to mandatory redemption requirements for each of the five
years following December 31, 1997, is $100,000.
NOTE 11
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1997 1996
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 20,000 $ 25,000
9 1/8% Series, paid in 1997 --- 20,000
Pollution Control Refunding Revenue
Bonds, Series 1992 --
Mercer County, North Dakota,
6.65%, due June 1, 2022 15,000 15,000
Morton County, North Dakota,
6.65%, due June 1, 2022 2,600 2,600
Richland County, Montana,
6.65%, due June 1, 2022 3,250 3,250
Secured Medium-Term Notes,
Series A --
7.20%, paid in 1997 --- 5,000
6.52%, due October 1, 2004 15,000 ---
8.25%, due April 1, 2007 30,000 30,000
6.71%, due October 1, 2009 15,000 ---
8.60%, due April 1, 2012 35,000 35,000
Total first mortgage bonds
and notes 135,850 135,850
Pollution control lease and
note obligation, 6.20%, due
March 1, 2004 3,700 4,000
Senior notes:
8.43%, due December 31, 2000 12,000 15,000
8.70%, due March 31, 2002 6,500 ---
7.35%, due July 31, 2002 5,000 5,000
7.51%, due October 9, 2003 3,000 3,000
6.86%, due October 30, 2004 12,500 ---
7.45%, due May 31, 2006 20,000 20,000
7.60%, due November 3, 2008 15,000 15,000
7.10%, due October 30, 2009 12,500 ---
7.28%, due October 30, 2012 10,000 ---
Revolving lines of credit:
8.50%, expires December 31, 2002 18,000 30,000
Other revolving lines of credit at
rates ranging from 6.34% to
7.25%, expiring on dates
ranging from May 30, 2000, through
October 6, 2001 46,000 61,800
Term credit facilities:
7.70%, due December 1, 2003 1,331 1,556
7.90%, due September 24, 2002 1,764 ---
Other term credit facilities at
rates ranging from 7.24% to 11.25%,
due on dates ranging from February 21,
1999, through April 4, 2002 3,303 1,308
Other (85) (94)
Total long-term debt 306,363 292,420
Less current maturities and sinking
fund requirements 7,802 11,754
Net long-term debt $298,561 $280,666
Under the revolving lines of credit, the company and its subsidiaries
have $160 million available, $64 million of which was outstanding at
December 31, 1997. The amounts of scheduled long-term debt maturities
and sinking fund requirements for the five years following
December 31, 1997, aggregate $7.8 million in 1998; $15.2 million in
1999; $53.8 million in 2000; $14.2 million in 2001 and $33.3 million
in 2002. Substantially all of the company's electric and natural gas
distribution properties, with certain exceptions, are subject to the
lien of its Indenture of Mortgage. Under the terms and conditions of
such Indenture, the company could have issued approximately
$259 million of additional first mortgage bonds at December 31, 1997.
Certain of the company's other debt instruments contain restrictive
covenants all of which the company is in compliance with at December
31, 1997.
NOTE 12
Income Taxes
Income tax expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Current:
Federal $15,427 $12,617 $20,259
State 2,362 3,272 3,801
Foreign 60 60 369
17,849 15,949 24,429
Deferred:
Investment tax credit -- net (1,150) (1,099) (1,028)
Income taxes --
Federal 11,844 1,139 (564)
State 2,200 120 220
Foreign --- (22) ---
12,894 138 (1,372)
Total income tax expense $30,743 $16,087 $23,057
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at
December 31 are as follows:
1997 1996
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 32,789 $ 38,404
Natural gas available under
repurchase commitment 4,821 10,521
Accrued pension costs 8,445 7,814
Deferred investment tax credits 2,714 3,160
Accrued land reclamation 3,184 3,604
Other 12,851 13,499
Total deferred tax assets 64,804 77,002
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 123,629 121,763
Basis differences on oil and
natural gas producing properties 30,726 30,361
Natural gas contract settlement and
restructuring costs --- 1,926
Long-term debt refinancing costs 4,672 4,688
Other 8,168 8,461
Total deferred tax liabilities 167,195 167,199
Net deferred income tax liability $(102,391) $(90,197)
The following table reconciles the change in the net deferred income
tax liability from December 31, 1996, to December 31, 1997, to the
deferred income tax expense included in the Consolidated Statements of
Income:
1997
(In thousands)
Net change in deferred income tax
liability from the preceding table $12,194
Change in tax effects of income tax-related
regulatory assets and liabilities 1,741
Deferred taxes associated with acquisitions 109
Deferred income tax expense for the period $14,044
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for this difference are as follows:
1997 1996 1995
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $29,876 35.0 $21,545 35.0 $22,642 35.0
Increases (reductions)
resulting from:
Depletion allowance (828) (1.0) (1,070) (1.7) (1,346) (2.1)
State income
taxes -- net of
federal income tax
benefit 3,473 4.1 2,770 4.5 2,492 3.9
Investment tax credit
amortization (1,150) (1.4) (1,099) (1.8) (1,028) (1.6)
Tax reserve adjustment --- --- (6,600) (10.7) --- ---
Other items (628) (.7) 541 .8 297 .4
Actual taxes $30,743 36.0 $16,087 26.1 $23,057 35.6
In 1996, the company reached a settlement with the Internal Revenue
Service concerning notices of deficiency issued in connection with
disputed items for the 1983 through 1988 tax years and, in 1997,
reached a similar settlement for the tax years 1989 through 1991. In
1996, the company reflected the effects of the 1996 settlement and the
1997 anticipated settlement and, in addition, reversed reserves which
had previously been provided and were deemed to be no longer required.
NOTE 13
Business Segment Data
The company's operations are conducted through five business segments.
The electric, natural gas distribution, natural gas transmission,
construction materials and mining, and oil and natural gas production
businesses are substantially all located within the United States. A
description of these segments and their primary operations is
presented on the inside front cover of this Annual Report to
Stockholders and Item 1 of the Annual Report on Form 10-K.
Segment operating information at December 31, 1997, 1996 and 1995, is
presented in the Consolidated Statements of Income. Depreciation,
depletion and amortization by segment is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Electric $17,771 $ 17,053 $ 16,361
Natural gas distribution 7,013 6,880 6,719
Natural gas transmission 5,550 6,748 6,940
Construction materials
and mining 10,999 6,974 6,199
Oil and natural gas production 24,434 24,996 18,606
Total depreciation, depletion
and amortization $65,767 $ 62,651 $ 54,825
Segment investment information included in the accompanying
Consolidated Balance Sheets at December 31 is as follows:
1997 1996
(In thousands)
Identifiable assets:
Electric (a) $ 326,615 $ 313,815
Natural gas distribution (a) 128,517 120,645
Natural gas transmission (a) 227,030 276,843
Construction materials
and mining 235,221 171,283
Oil and natural gas
production 162,785 161,647
Total identifiable assets 1,080,168 1,044,233
Corporate assets (b) 33,724 44,940
Total consolidated assets $1,113,892 $1,089,173
(a) Includes, in the case of electric and natural gas distribution
property, allocations of common utility property. Natural gas stored
or available under repurchase commitment, as applicable, is included
in natural gas distribution and transmission identifiable assets.
(b) Corporate assets consist of assets not directly assignable to a
business segment, i.e., cash and cash equivalents, certain accounts
receivable and other miscellaneous current and deferred assets.
Approximately 3 percent of construction materials and mining revenues
in 1997 (4 percent in 1996 and 1995) represent Knife River's direct
sales of lignite coal to the company. The company's share of Knife
River's 1997 sales for use at the Coyote Station, a generating station
jointly owned by the company and other utilities, was approximately
3 percent and 5 percent of construction materials and mining revenues
in 1997 and 1996, respectively. In 1995, the company's share of Knife
River's sales for use at the Coyote Station and the Big Stone Station,
another generating station jointly owned by the company and other
utilities, was 7 percent of construction materials and mining
revenues.
In April 1996, KRC Holdings, Inc. (KRC Holdings), a wholly owned
subsidiary of Knife River, purchased Baldwin Contracting Company, Inc.
(Baldwin) of Chico, California. Baldwin is a major supplier of
aggregate, asphalt and construction services in the northern
Sacramento Valley and adjacent Sierra Nevada Mountains of northern
California. Baldwin also provides a variety of construction services,
primarily earth moving, grading and road and highway construction and
maintenance.
In June 1996, KRC Holdings purchased the assets of Medford Ready-Mix
Concrete, Inc. located in Medford, Oregon. The acquired company
serves the residential and small commercial construction market with
ready-mixed concrete and aggregates.
On February 14, 1997, Baldwin purchased the physical assets of Orland
Asphalt located in Orland, California, including a hot-mix plant and
aggregate reserves. Orland Asphalt was combined with and operates as
part of Baldwin.
On July 1, 1997, the company acquired two electric services companies,
International Line Builders, Inc. and High Line Equipment, Inc., both
located in Portland, Oregon. International Line Builders, Inc.
installs and repairs transmission and distribution power lines in the
western United States and Hawaii and High Line Equipment, Inc.
provides related construction supplies and equipment.
On July 31, 1997, Knife River purchased the 50 percent interest in
Hawaiian Cement, that it did not previously own, from Adelaide
Brighton Cement (Hawaii), Inc. of Adelaide, Australia. The company's
initial 50 percent partnership interest in Hawaiian Cement was
acquired in September 1995. See Note 15 for more discussion on this
partnership investment.
Pro forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not material
to the company's financial position or results of operations.
NOTE 14
Employee Benefit Plans
The company has noncontributory defined benefit pension plans covering
most full-time employees. Pension benefits are based primarily on
employee's years of service and earnings. The company makes annual
contributions to the plans consistent with the funding requirements of
federal law and regulations.
Pension expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Service cost/benefits earned during
the year $ 3,889 $ 3,852 $ 3,538
Interest cost on projected benefit
obligation 11,651 10,823 10,784
Return on plan assets (38,273) (24,972) (37,185)
Net amortization and deferral 23,109 11,494 24,407
Special termination benefit cost --- --- 853
Total pension costs 376 1,197 2,397
Less amounts capitalized 70 131 184
Total pension expense $ 306 $ 1,066 $ 2,213
The funded status of the company's plans at December 31 is summarized
as follows:
1997 1996
(In thousands)
Projected benefit obligation:
Vested $141,951 $122,119
Nonvested 6,204 3,923
Accumulated benefit obligation 148,155 126,042
Provision for future pay increases 30,044 24,787
Projected benefit obligation 178,199 150,829
Plan assets at market value 225,201 185,872
(47,002) (35,043)
Plus:
Unrecognized transition asset 6,333 7,336
Unrecognized net gains and prior service costs 48,788 35,848
Accrued pension costs $ 8,119 $ 8,141
The projected pension benefit obligation was determined using the
following assumptions:
1997 1996
Discount rate 7.00% 7.50%
Assumed compensation increase 4.50% 4.50%
Assumed long-term rate of
return on plan assets 8.00%-8.50% 8.50%
The change in these assumptions had the effect of increasing the
projected benefit obligation at December 31, 1997, by $12 million.
Plan assets consist primarily of debt and equity securities.
In addition to providing pension benefits, the company has a policy of
providing all eligible employees and dependents certain other
postretirement benefits which include health care and life insurance
upon their retirement. The plans underlying these benefits may
require contributions by the employee depending on such employee's age
and years of service at retirement or the date of retirement. The
accounting for the health care plan anticipates future cost-sharing
changes that are consistent with the company's expressed intent to
generally increase retiree contributions each year by the excess of
the expected health care cost trend rate over 6 percent.
Postretirement benefits expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Service cost/benefits earned during
the year $ 1,272 $ 1,333 $ 1,226
Interest cost on accumulated
postretirement benefit obligation 4,691 4,701 4,777
Return on plan assets (5,380) (2,491) (183)
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral 3,527 1,260 (719)
Total postretirement benefits cost 6,568 7,261 7,559
Less amounts capitalized 625 735 442
Total postretirement benefits expense $ 5,943 $ 6,526 $ 7,117
The funded status of the company's plans at December 31 is summarized
as follows:
1997 1996
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $ 44,876 $40,775
Active employees fully eligible for benefits 1,646 ---
Active employees not fully eligible 27,316 24,833
Total 73,838 65,608
Plan assets at market value 30,595 21,712
43,243 43,896
Less:
Unrecognized transition obligation 36,864 39,322
Unrecognized net loss (gain) (2,679) 3,693
Accrued postretirement benefits cost $ 9,058 $ 881
The accumulated postretirement benefit obligation was determined using
the following assumptions:
1997 1996
Discount rate 7.00% 7.50%
Compensation increase as it applies to
life insurance benefits 4.50% 4.50%
Long-term rate of return on plan assets 7.50% 7.50%
Health care cost trend rate 7.00%-9.00% 9.00%
Health care cost trend rate -- ultimate 5.00%-6.00% 6.00%
Year in which ultimate trend rate achieved 1999-2004 1999
The change in these assumptions had the effect of increasing the
accumulated postretirement benefit obligation at December 31, 1997, by
$5 million.
The health plan cost trend rate assumption has a significant effect on
the amounts reported. To illustrate, increasing the assumed health
plan cost trend rates by 1 percent each year would increase the
accumulated postretirement benefit obligation as of December 31, 1997,
by $3.8 million and the aggregate of the service and interest cost
components of postretirement benefits expense by $239,000. Plan
assets consist primarily of certain life insurance products of which
the return depends on the performance of underlying debt and equity
securities. The company's policy with respect to most plans is to
fund the annual expense amount. One subsidiary of KRC Holdings has a
policy to fund postretirement benefits on a cash basis.
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for
defined benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants which is payable to the
company upon the employee's death. The cost of these benefits was
$2.2 million in both 1997 and 1996 and $1.9 million in 1995.
The company has a Key Employee Stock Option Plan (KESOP). The company
accounts for the KESOP in accordance with APB Opinion No. 25 under
which no compensation expense has been recognized. Under the KESOP
the option price equals the market value of the stock on the date of
grant. Options automatically vest after nine years, but the KESOP
provides for accelerated vesting based upon the attainment of certain
performance goals or upon a change in control of the company. The
options expire 10 years after the date of grant. The company also
adopted a Non-Employee Director Option Plan (Director Plan) and an
Executive Long-Term Incentive Plan (Executive Plan) in 1997. Under
the KESOP, Director Plan and Executive Plan, the company is authorized
to grant options for up to 2.6 million shares of common stock and has
granted options on 490,473 shares through December 31, 1997.
Had the company recorded compensation expense for the fair value of
options granted consistent with SFAS No. 123, "Accounting for Stock-
Based Compensation" (SFAS No. 123), net income would have been reduced
on a pro forma basis by $51,400 in 1997 and $48,000 in both 1996 and
1995. On a pro forma basis, there would have been no effect on
reported basic earnings per share for 1997, 1996 and 1995. There
would have been no effect on reported diluted earnings per share in
1997 and 1995, however diluted earnings per share would have been
reduced on a pro forma basis by $.01 in 1996. Since SFAS No. 123 does
not require this accounting to be applied to options granted prior to
January 1, 1995, the resulting pro forma compensation costs may not be
representative of that to be expected in future years.
A summary of the status of the KESOP and Director Plan at December 31,
1997, 1996 and 1995, and changes during the years then ended are as
follows:
1997 1996 1995
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning
of year 423,977 $17.66 468,737 $17.48 192,284 $15.82
Granted 15,000 24.56 --- --- 294,956 18.50
Forfeited (9,067) 17.11 --- --- (2,700) 20.83
Exercised (33,790) 15.75 (44,760) 15.75 (15,803) 15.75
Balance at end
of year 396,120 18.10 423,977 17.66 468,737 17.48
Exercisable at
end of year 74,974 $17.51 93,764 $15.75 138,524 $15.75
Exercise prices on options outstanding at December 31, 1997, range
from $15.75 to $24.56 with a weighted average remaining contractual
life of approximately 7 years.
The weighted average fair value of each option granted in 1997 and
1995 is $3.13 and $2.67, respectively. The fair value of each option
is estimated on the date of grant using the Black-Scholes option
pricing model. The assumptions used to estimate the fair value of
options granted in 1997 and 1995 were a risk-free interest rate of
6.60 percent and 7.80 percent, respectively, an expected dividend
yield of 5.48 percent and 5.80 percent, respectively, an expected life
of 7 years and 10 years, respectively, and expected volatility of
14.51 percent and 15.80 percent, respectively.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. Generally each participant may contribute amounts up to 15
percent of eligible compensation, subject to certain limitations. The
company contributes an amount equal to 50 percent of the participant's
savings contribution up to a maximum of 6 percent of such
participant's contribution. Company contributions were $2.1 million
in 1997 and $1.9 million in both 1996 and 1995.
NOTE 15
Partnership Investment
In September 1995, KRC Holdings through its wholly owned subsidiary,
Knife River Hawaii, Inc., acquired a 50 percent interest in Hawaiian
Cement, which was previously owned by Lone Star Industries, Inc.
Knife River Dakota, Inc., a wholly owned subsidiary of KRC Holdings,
Inc. acquired the remaining 50 percent interest in Hawaiian Cement
from the previous owner, Adelaide Brighton Cement (Hawaii), Inc. of
Adelaide, Australia, on July 31, 1997. Hawaiian Cement is a
partnership headquartered in Honolulu, Hawaii, and is one of the
largest construction materials suppliers in Hawaii, serving four of
the islands. Hawaiian Cement's operations include construction
aggregate mining, ready-mixed concrete and cement manufacturing and
distribution.
In August 1997, the company began consolidating Hawaiian Cement into
its financial statements. Prior to August 1997, the company's net
investment in Hawaiian Cement was not consolidated and was accounted
for by the equity method. The company's original 50 percent
investment is included in "Investments" in the accompanying
Consolidated Balance Sheets at December 31, 1996, while its share of
operating results for the seven months ended July 31, 1997, the year
ended December 31, 1996, and the four months ended December 31, 1995,
is included in "Other income -- net" in the accompanying Consolidated
Statements of Income for the years ended December 31, 1997, 1996 and
1995, respectively. Summarized financial information for Hawaiian
Cement, when accounted for by the equity method, includes: current
assets; net property, plant and equipment; current liabilities; and,
other liabilities, as of December 31, 1996, (in millions) of $17.3,
$52.3, $10.1 and $15.0, respectively. Operating results for the seven
months ended July 31, 1997, for the year ended December 31, 1996, and
for the four months ended December 31, 1995, (in millions) were net
sales of $33.5, $70.1 and $24.4; operating margin of $4.7, $9.9 and
$5.1; and income before income taxes of $2.0, $5.4 and $2.8,
respectively.
NOTE 16
Jointly Owned Facilities
The consolidated financial statements include the company's 22.70
percent and 25 percent ownership interests in the assets, liabilities
and expenses of the Big Stone Station and the Coyote Station,
respectively. Each owner of the Big Stone and Coyote stations is
responsible for financing its investment in the jointly owned
facilities.
The company's share of the Big Stone Station and Coyote Station
operating expenses is reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
1997 1996
(In thousands)
Big Stone Station:
Utility plant in service $ 49,467 $ 48,907
Accumulated depreciation 27,971 26,676
$ 21,496 $ 22,231
Coyote Station:
Utility plant in service $121,604 $122,320
Accumulated depreciation 53,107 52,721
$ 68,497 $ 69,599
NOTE 17
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1997 and 1996:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
1997
Operating revenues $139,811 $125,380 $163,699 $178,784
Operating expenses 109,055 106,932 134,675 145,451
Operating income 30,756 18,448 29,024 33,333
Net income 14,597 8,741 14,195 17,084
Earnings per common share:
Basic .50 .30 .48 .58
Diluted .50 .30 .48 .58
1996
Operating revenues $126,529 $110,213 $133,759 $144,200
Operating expenses 98,447 90,012 103,038 111,679
Operating income 28,082 20,201 30,721 32,521
Net income 13,135 8,600 8,495 15,240
Earnings per common share:
Basic .45 .30 .29 .53
Diluted .45 .30 .29 .53
Certain company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 18
Oil and Natural Gas Activities (Unaudited)
Fidelity Oil is involved in the acquisition, exploration, development
and production of oil and natural gas properties. Fidelity's
operations vary from the acquisition of producing properties with
potential development opportunities to exploration 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.
Williston Basin owns in fee or holds natural gas leases and operating
rights primarily applicable to the shallow rights (above 2,000 feet)
in the Cedar Creek Anticline in southeastern Montana and to all rights
in the Bowdoin area located in north-central Montana.
The following information includes the company's proportionate share
of all its oil and natural gas interests held by both Fidelity Oil and
Williston Basin.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to oil and natural
gas producing activities at December 31:
1997 1996 1995
(In thousands)
Subject to amortization $252,291 $223,409 $173,501
Not subject to amortization 9,408 6,792 8,831
Total capitalized costs 261,699 230,201 182,332
Accumulated depreciation, depletion
and amortization 95,611 71,554 49,498
Net capitalized costs $166,088 $158,647 $132,834
Net capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities are as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Acquisitions $ 59 $23,284 $ 9,159
Exploration 13,344 8,101 7,678
Development 18,874 19,979 24,955
Net capital expenditures $32,277 $51,364 $41,792
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs:
Years ended December 31, 1997 1996 1995
(In thousands)
Revenues* $77,756 $75,335 $53,484
Production costs 23,251 21,296 16,888
Depreciation, depletion and
amortization 24,864 25,629 19,058
Pretax income 29,641 28,410 17,538
Income tax expense 10,968 10,875 6,397
Results of operations for
producing activities $18,673 $17,535 $11,141
* Includes $9.4 million, $7.0 million and $4.7 million of revenues
for 1997, 1996 and 1995, respectively, related to Williston Basin's
natural gas production activities which are included in "Natural gas"
operating revenues in the Consolidated Statements of Income.
The following table summarizes the company's estimated quantities of
proved oil and natural gas reserves at December 31, 1997, 1996 and
1995, and reconciles the changes between these dates. Estimates of
economically recoverable oil and natural gas reserves and future net
revenues therefrom are based upon a number of variable factors and
assumptions. For these reasons, estimates of economically recoverable
reserves and future net revenues may vary from actual results.
1997 1996 1995
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 16,100 200,200 14,200 179,000 12,500 154,200
Production (2,100) (20,400) (2,100) (20,400) (2,000) (17,500)
Extensions and
discoveries 600 12,100 600 27,000 1,800 23,800
Purchases of proved
reserves --- 200 2,900 9,900 1,100 6,700
Sales of reserves
in place (200) (2,300) (700) (3,700) (300) (200)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 500 (4,900) 1,200 8,400 1,100 12,000
Balance at end
of year 14,900 184,900 16,100 200,200 14,200 179,000
Proved developed reserves:
January 1, 1995 12,200 147,200
December 31, 1995 13,600 156,400
December 31, 1996 15,400 168,200
December 31, 1997 14,500 163,800
Virtually all of the company's interests in oil and natural gas
reserves are located in the continental United States. Reserve
interests at December 31, 1997, applicable to the company's $852,000
net investment in oil and natural gas properties located in Canada
comprise approximately 2 percent of the total reserves.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various
oil and natural gas interests at December 31 is as follows:
1997 1996 1995
(In thousands)
Future net cash flows before
income taxes $306,600 $580,300 $267,300
Future income tax expenses 86,600 194,200 76,100
Future net cash flows 220,000 386,100 191,200
10% annual discount for estimated
timing of cash flows 81,000 152,100 70,300
Discounted future net cash flows
relating to proved oil and natural
gas reserves $139,000 $234,000 $120,900
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1997 1996 1995
(In thousands)
Beginning of year $234,000 $120,900 $ 94,900
Net revenues from production (54,500) (54,000) (36,400)
Change in net realization (158,400) 125,800 26,300
Extensions, discoveries and improved
recovery, net of future
production-related costs 19,400 43,500 31,200
Purchases of proved reserves 200 49,600 10,900
Sales of reserves in place (2,800) (6,700) (1,000)
Changes in estimated future
development costs -- net of those
incurred during the year 7,700 (2,400) (8,900)
Accretion of discount 32,800 16,900 12,300
Net change in income taxes 62,100 (69,200) (17,100)
Revisions of previous quantity
estimates (1,300) 8,700 8,900
Other (200) 900 (200)
Net change (95,000) 113,100 26,000
End of year $139,000 $234,000 $120,900
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end oil and
natural gas prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying
statutory tax rates (adjusted for permanent differences and tax
credits) to estimated net future pretax cash flows.
To MDU Resources Group, Inc.
We have audited the accompanying consolidated balance sheets of MDU
Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of
December 31, 1997 and 1996, and the related consolidated statements of
income, common stockholders' equity and cash flows for each of the
three years in the period ended December 31, 1997. These financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of MDU
Resources Group, Inc. and Subsidiaries as of December 31, 1997 and
1996, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 22, 1998
1997 1996 1995
Selected Financial Data
Operating revenues: (000's)
Electric $ 164,351 $ 138,761 $ 134,609
Natural gas 200,789 175,408 167,787
Construction materials and mining 174,147 132,222 113,066
Oil and natural gas production 68,387 68,310 48,784
$ 607,674 $ 514,701 $ 464,246
Operating income: (000's)
Electric $ 33,089 $ 29,476 $ 29,898
Natural gas distribution 10,410 11,504 6,917
Natural gas transmission 29,169 30,231 25,427
Construction materials and mining 14,602 16,062 14,463
Oil and natural gas production 24,291 24,252 13,871
$ 111,561 $ 111,525 $ 90,576
Earnings on common stock: (000's)
Electric $ 13,388 $ 11,436 $ 12,000
Natural gas distribution 4,514 4,892 1,604
Natural gas transmission 11,317 2,459 8,416
Construction materials and mining 10,111 11,521 10,819
Oil and natural gas production 14,505 14,375 8,002
Earnings on common stock
before cumulative effect of
accounting change 53,835 44,683 40,841
Cumulative effect of
accounting change --- --- ---
$ 53,835 $ 44,683 $ 40,841
Earnings per common share before
cumulative effect of accounting
change -- diluted $ 1.86 $ 1.57 $ 1.43
Cumulative effect of
accounting change --- --- ---
$ 1.86 $ 1.57 $ 1.43
Pro forma amounts assuming
retroactive application
of accounting change:
Net income (000's) $ 54,617 $ 45,470 $ 41,633
Earnings per common
share -- diluted $ 1.86 $ 1.57 $ 1.43
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 28,985 28,549 28,526
Dividends per common share $ 1.13 $ 1.10 $ 1.0782
Book value per common share $ 13.26 $ 12.31 $ 11.85
Market price per common
share (year end) $ 31.63 $ 23.00 $ 19.88
Market price ratios:
Dividend payout 61% 70% 76%
Yield 3.6% 4.8% 5.5%
Price/earnings ratio 17.0x 14.6x 13.9x
Market value as a percent
of book value 238.5% 186.8% 167.7%
Profitability Indicators
Return on average common equity 14.6% 13.0% 12.3%
Return on average invested capital 10.3% 9.5% 9.2%
Interest coverage 6.0x 5.4x 3.9x
Fixed charges coverage, including
preferred dividends 3.4x 2.7x 3.0x
General
Total assets (000's) $1,113,892 $1,089,173 $1,056,479
Net long-term debt (000's) $ 298,561 $ 280,666 $ 237,352
Redeemable preferred
stock (000's) $ 1,800 $ 1,900 $ 2,000
Capitalization ratios:
Common stockholders' equity 55% 54% 57%
Preferred stocks 2 3 3
Long-term debt 43 43 40
100% 100% 100%
1994 1993 1992
Selected Financial Data
Operating revenues: (000's)
Electric $ 133,953 $ 131,109 $ 123,908
Natural gas 160,970 178,981 159,438
Construction materials and mining 116,646 90,397 45,032
Oil and natural gas production 37,959 39,125 33,797
$ 449,528 $ 439,612 $ 362,175
Operating income: (000's)
Electric $ 27,596 $ 30,520 $ 30,188
Natural gas distribution 3,948 4,730 4,509
Natural gas transmission 21,281 20,108 21,331
Construction materials and mining 16,593 16,984 11,532
Oil and natural gas production 8,757 11,750 9,499
$ 78,175 $ 84,092 $ 77,059
Earnings on common stock: (000's)
Electric $ 11,719 $ 12,652* $ 13,302
Natural gas distribution 285 1,182* 1,370
Natural gas transmission 6,155 4,713 3,479
Construction materials and mining 11,622 12,359 10,662
Oil and natural gas production 9,267 7,109 5,751
Earnings on common stock
before cumulative effect of
accounting change 39,048 38,015* 34,564
Cumulative effect of
accounting change --- 5,521 ---
$ 39,048 $ 43,536 $ 34,564
Earnings per common share before
cumulative effect of accounting
change -- diluted $ 1.37 $ 1.34* $ 1.21
Cumulative effect of
accounting change --- .19 ---
$ 1.37 $ 1.53 $ 1.21
Pro forma amounts assuming
retroactive application
of accounting change:
Net income (000's) $ 39,845 $ 38,817 $ 35,852
Earnings per common
share -- diluted $ 1.37 $ 1.34 $ 1.23
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 28,509 28,534 28,494
Dividends per common share $ 1.0533 $ 1.0133 $ .9733
Book value per common share $ 11.49 $ 11.17 $ 10.66
Market price per common
share (year end) $ 18.08 $ 21.00 $ 17.58
Market price ratios:
Dividend payout 77% 76%* 80%
Yield 5.9% 5.0% 5.6%
Price/earnings ratio 13.2x 15.8x* 14.5x
Market value as a percent
of book value 157.4% 188.0% 165.0%
Profitability Indicators
Return on average common equity 12.1% 12.3%* 11.6%
Return on average invested capital 9.1% 9.4%* 8.7%
Interest coverage 3.3x 3.4x* 3.3x
Fixed charges coverage, including
preferred dividends 2.8x 2.9x* 2.4x
General
Total assets (000's) $1,004,718 $1,041,051 $1,024,510
Net long-term debt (000's) $ 217,693 $ 231,770 $ 249,845
Redeemable preferred
stock (000's) $ 2,100 $ 2,200 $ 2,300
Capitalization ratios:
Common stockholders' equity 58% 56% 53%
Preferred stocks 3 3 3
Long-term debt 39 41 44
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the
accrual of estimated unbilled revenues.
1997 1996 1995
Electric Operations
Sales to ultimate consumers
(thousand kWh) 2,041,191 2,067,926 1,993,693
Sales for resale (thousand kWh) 361,954 374,535 408,011
Electric system generating and
firm purchase capability --
kW (Interconnected system) 487,500 481,800 472,400
Demand peak --
kW (Interconnected system) 404,600 393,300 412,700
Electricity produced (thousand kWh) 1,826,770 1,829,669 1,718,077
Electricity purchased (thousand kWh) 769,679 809,261 867,524
Cost of fuel and purchased
power per kWh $.018 $.017 $.016
Natural Gas Distribution Operations
Sales (Mdk) 34,320 38,283 33,939
Transportation (Mdk) 10,067 9,423 11,091
Weighted average degree days -- % of
previous year's actual 85% 114% 105%
Natural Gas Transmission Operations
Natural gas transmission:
Sales for resale (Mdk) --- --- ---
Transportation (Mdk) 85,464 82,169 68,015
Produced (Mdk) 6,949 6,073 4,981
Net recoverable reserves (MMcf) 127,300 133,400 113,000
Energy marketing:
Natural gas volumes (Mdk) 14,971 4,670 3,556
Propane (thousand gallons) 10,005 9,689 7,471
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 5,113 3,374 2,904
Asphalt (tons sold) 758 694 373
Ready-mixed concrete
(cubic yards sold) 516 340 307
Recoverable aggregate
reserves (tons) 169,375 119,800 68,000
Coal: (000's)
Sales (tons) 2,375 2,899 4,218
Recoverable reserves (tons) 226,560 228,900 231,900
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 2,088 2,149 1,973
Natural gas (MMcf) 13,192 14,067 12,319
Average sales prices:
Oil (per barrel) $ 17.50 $ 17.91 $ 15.07
Natural gas (per Mcf) $ 2.41 $ 2.09 $ 1.51
Net recoverable reserves:
Oil (000's of barrels) 14,900 16,100 14,200
Natural gas (MMcf) 57,600 66,800 66,000
1994 1993 1992
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,955,136 1,893,713 1,829,933
Sales for resale (thousand kWh) 444,492 510,987 352,550
Electric system generating and
firm purchase capability --
kW (Interconnected system) 470,900 465,200 460,200
Demand peak --
kW (Interconnected system) 369,800 350,300 339,100
Electricity produced (thousand kWh) 1,901,119 1,870,740 1,774,322
Electricity purchased (thousand kWh) 700,912 701,736 593,612
Cost of fuel and purchased
power per kWh $.017 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 31,840 31,147 26,681
Transportation (Mdk) 9,278 12,704 13,742
Weighted average degree days -- % of
previous year's actual 92% 115% 98%
Natural Gas Transmission Operations
Natural gas transmission:
Sales for resale (Mdk) --- 13,201 16,841
Transportation (Mdk) 63,870 59,416 64,498
Produced (Mdk) 4,732 3,876 3,551
Net recoverable reserves (MMcf) 99,300 --- ---
Energy marketing:
Natural gas volumes (Mdk) 7,301 6,827 3,292
Propane (thousand gallons) 6,462 2,210 ---
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,688 2,391 263
Asphalt (tons sold) 391 141 ---
Ready-mixed concrete
(cubic yards sold) 315 157 ---
Recoverable aggregate
reserves (tons) 71,000 74,200 20,600
Coal: (000's)
Sales (tons) 5,206 5,066 4,913
Recoverable reserves (tons) 236,100 230,600 235,700
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,565 1,497 1,531
Natural gas (MMcf) 9,228 8,817 5,024
Average sales prices:
Oil (per barrel) $ 13.14 $ 14.84 $ 16.74
Natural gas (per Mcf) $ 1.84 $ 1.86 $ 1.53
Net recoverable reserves:
Oil (000's of barrels) 12,500 11,200 12,200
Natural gas (MMcf) 54,900 50,300 37,200
SUBSIDIARIES OF MDU RESOURCES GROUP, INC.
March 6, 1998
State or Other
Jurisdiction
in Which
Incorporated
Alaska Basic Industries, Inc. Alaska
Anchorage Sand and Gravel Company, Inc. Alaska
Baldwin Contracting Company, Inc. California
Centennial Energy Holdings, Inc. Delaware
Concrete, Inc. California
Fidelity Oil Co. Delaware
Fidelity Oil Holdings, Inc. Delaware
High Line Equipment, Inc. Delaware
ILB Hawaii, Inc. Hawaii
International Line Builders, Inc. Delaware
Knife River Corporation Delaware
Knife River Dakota, Inc. Delaware
Knife River Hawaii, Inc. Delaware
Knife River Marine, Inc. Delaware
KRC Aggregate, Inc. Delaware
KRC Holdings, Inc. Delaware
LTM, Incorporated Oregon
Medford Ready Mix, Inc. Delaware
Morse Bros., Inc. Oregon
Prairie Propane, Inc. Delaware
Prairielands Energy Marketing, Inc. Delaware
Rogue Aggregates, Inc. Oregon
S2 - F Corp. Oregon
Utility Services, Inc. Delaware
WBI Canadian Pipeline, Ltd. Canada
Williston Basin Interstate Pipeline Company Delaware
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference in this Form 10-K of our report dated
January 22, 1998 included in the MDU Resources Group, Inc. Annual
Report to Stockholders for 1997. We also consent to the
incorporation of our report incorporated by reference in this
Form 10-K into the Company's previously filed Registration
Statements on Form S-3, No. 33-46605 and No. 333-06127, and on
Form S-8, No. 33-54486, No. 33-53896, No. 333-06103, No. 333-06105,
No. 333-27879 and No. 333-27877.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
March 6, 1998
CONSENT OF ENGINEER
We hereby consent to the reference to our reports dated
January 12, 1998, appearing in this Annual Report on Form 10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and No. 333-06127
and on Form S-8, No. 33-54486, No. 33-53896, No. 333-06103,
No. 333-06105, No. 333-27879 and No. 333-27877 of MDU Resources
Group, Inc. and in the related Prospectuses of the reference to
such reports appearing in this Annual Report on Form 10-K.
/s/ RALPH E. DAVIS ASSOCIATES, INC.
RALPH E. DAVIS ASSOCIATES, INC.
Houston, Texas
March 6, 1998
CONSENT OF ENGINEER
We hereby consent to the reference to our report dated
May 9, 1994, appearing in this Annual Report on Form 10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and No. 333-06127,
and on Form S-8, No. 33-54486, No. 33-53896, No. 333-06103,
No. 333-06105, No. 333-27879 and No. 333-27877 of MDU
Resources Group, Inc. and in the related Prospectuses of the
reference to such report appearing in this Annual Report on Form
10-K.
/s/ WEIR INTERNATIONAL MINING CONSULTANTS
WEIR INTERNATIONAL MINING CONSULTANTS
Des Plaines, Illinois
March 6, 1998
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THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
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STATEMENTS OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATMENTS.
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1,700
15,000
<LONG-TERM-DEBT-NET> 298,561
<SHORT-TERM-NOTES> 3,347
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 7,802
100
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 401,086
<TOT-CAPITALIZATION-AND-LIAB> 1,113,892
<GROSS-OPERATING-REVENUE> 607,674
<INCOME-TAX-EXPENSE> 30,743
<OTHER-OPERATING-EXPENSES> 496,113
<TOTAL-OPERATING-EXPENSES> 526,856
<OPERATING-INCOME-LOSS> 80,818
<OTHER-INCOME-NET> 4,008
<INCOME-BEFORE-INTEREST-EXPEN> 84,826
<TOTAL-INTEREST-EXPENSE> 30,209
<NET-INCOME> 54,617
782
<EARNINGS-AVAILABLE-FOR-COMM> 53,835
<COMMON-STOCK-DIVIDENDS> 32,653
<TOTAL-INTEREST-ON-BONDS> 12,462
<CASH-FLOW-OPERATIONS> 138,629
<EPS-PRIMARY> 1.86
<EPS-DILUTED> 1.86
</TABLE>
