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, 1996
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)
400 North Fourth Street 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 21, 1997: $629,122,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 21, 1997: 28,596,475 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 23 through 49 of the Annual Report to Stockholders for 1996,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 3, 1997, incorporated in Part III,
Items 10, 11, 12 and 13 of this Report.
<PAGE>
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 Coal Mining Company --
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 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<PAGE>
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 that are identified by the use of 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 400
North Fourth Street, 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) and the Fidelity Oil Group (Fidelity Oil).
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, effective
January 1, 1997, 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 Oregon, California, Alaska and Hawaii. In
addition, Knife River surface mines and markets low sulfur
lignite coal at mines located in Montana and North Dakota.
Effective February 7, 1997, Knife River Coal Mining Company
changed its name to Knife River Corporation.
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.
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, 1996, the Company had 1,867 full-time
employees with 82 employed at MDU Resources Group, Inc., including
Fidelity Oil, 1,041 at Montana-Dakota, 289 at Williston Basin,
including Prairielands, 303 at Knife River's construction materials
operations and 152 at Knife River's coal operations. Approximately
511 and 89 of the Montana-Dakota and Williston Basin employees,
respectively, are represented by the International Brotherhood of
Electrical Workers (IBEW). Montana-Dakota's labor contract expired
on December 31, 1996, and Montana-Dakota is presently involved in
labor negotiations with the IBEW. Employees subject to the
collective bargaining agreement voluntarily continue to work under
the terms and conditions of the expired contract. Discussions were
held with the IBEW, but no agreement was reached. Current
negotiations are being held through the help of federal mediation.
Montana-Dakota believes these negotiations will not result in a
work stoppage or have any material financial effect on its results
of operations. Williston Basin's labor contract with the IBEW also
expired on December 31, 1996. Negotiations with the IBEW have been
concluded and Williston Basin's newly negotiated agreement through
May 1999 was ratified by the affected IBEW membership effective
February 3, 1997. However, the new labor agreement has not been
fully executed. 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 94
employees. In addition, Knife River has 11 labor contracts which
represent 109 of its construction materials 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".
Any reference to the Company's Consolidated Financial
Statements and Notes thereto shall be to the Consolidated Financial
Statements and Notes thereto contained on pages 23 through 47 in
the Company's Annual Report to Stockholders for 1996 (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
nearly 113,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as of
December 31, 1996. 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, 1996, Montana-Dakota's net electric plant investment
approximated $281.4 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 1996 electric utility
operating revenues by jurisdiction is as follows: North Dakota --
60 percent; Montana -- 23 percent; South Dakota -- 8 percent and
Wyoming -- 9 percent.
System Supply and System Demand --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and major
communities -- western North Dakota, including Bismarck, Dickinson
and Williston; eastern Montana, including Glendive and Miles City;
and northern South Dakota, including Mobridge. The interconnected
system consists of seven on-line electric generating stations which
have an aggregate turbine nameplate rating attributable to Montana-
Dakota's interest of 393,488 Kilowatts (kW) and a total summer net
capability of 415,408 kW. Montana-Dakota's four principal
generating stations are steam-turbine generating units using coal
for fuel. The nameplate rating for Montana-Dakota's ownership
interest in these four stations(including interests in the Big
Stone Station and the Coyote Station aggregating 22.7 percent and
25.0 percent, respectively) is 327,758 kW. The balance of Montana-
Dakota's interconnected system electric generating capability is
supplied by three combustion turbine peaking stations.
Additionally, Montana-Dakota has contracted to purchase through
October 31, 2006, up to 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:
1996 Net
Generation
Nameplate Summer (kilowatt-
Generating Rating Capability hours in
Station Type (kW) (kW) thousands)
North Dakota --
Coyote* Steam 103,647 106,750 681,712
Heskett Steam 86,000 102,000 367,126
Williston Combustion
Turbine 7,800 8,900 88
South Dakota --
Big Stone* Steam 94,111 99,558 563,862
Montana --
Lewis & Clark Steam 44,000 45,200 194,266
Glendive Combustion
Turbine 34,780 31,600 14,598
Miles City Combustion
Turbine 23,150 21,400 8,017
393,488 415,408 1,829,669
* Reflects Montana-Dakota's ownership interest.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. See "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, 1992, through December 31,
1996, 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,
1996 1995 1994 1993 1992
Average cost of
coal per
million Btu $.93 $.94 $.97 $.96 $.97
Average cost of
coal per ton $13.64 $12.90 $12.88 $12.78 $12.79
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 1996 summer peak was only 393,300 kW. The summer peak,
assuming normal weather, was previously forecasted to have been
approximately 410,700 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
2001 will approximate 1.4 percent annually. Montana-Dakota's
latest forecast indicates that its kilowatt-hour (kWh) sales growth
rate, on a normalized basis, through 2001 will approximate
.8 percent annually. Montana-Dakota currently estimates that it
has adequate capacity available through existing generating
stations and long-term firm purchase contracts through the year
1999.
Montana-Dakota has major interconnections with its neighboring
utilities, all of which are Mid-Continent Area Power Pool (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 was supplied through an interconnection
with Pacific Power & Light Company under a supply contract through
December 31, 1996. Beginning January 1, 1997, Black Hills Power
and Light began supplying the electric power and energy for
Montana-Dakota's electric service requirements for its Sheridan
System 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. The National Energy Policy Act
of 1992 (NEPA) encourages competition by facilitating the creation
of non-regulated generators. As a result of competition in
electric generation, wholesale power markets have become
increasingly competitive. Under NEPA, the FERC may order access to
utility transmission systems by third-party energy producers on a
case-by-case basis and may order electric utilities to enlarge
their transmission systems to transport (wheel) power for such
third parties, subject to certain conditions. To date, no third
party producers are connected to Montana-Dakota's system.
On April 24, 1996, the FERC issued its final rule (Order No.
888) on wholesale electric transmission open access and recovery of
stranded costs. On July 8, 1996, Montana-Dakota filed proposed
tariffs with the FERC in compliance with Order 888. Under the
proposed tariffs, which became effective on July 9, 1996, eligible
transmission service customers can choose to purchase transmission
services from a variety of options ranging from full use of the
transmission network on a firm long-term basis to a fully
interruptible service available on an hourly basis. The proposed
tariffs also include a full range of ancillary services necessary
to support the transmission of energy while maintaining reliable
operation of Montana-Dakota's transmission system. Montana-Dakota
is awaiting final approval of the proposed tariffs by the FERC.
In a related matter, on March 29, 1996, the Mid-Continent Area
Power Pool (MAPP), of which Montana-Dakota is a member, filed a
restated operating agreement with the FERC to provide for wholesale
open access transmission on its members' systems on a non-
discriminatory basis. The FERC approved MAPP's restated agreement,
excluding MAPP's market-based rate proposal, effective November 1,
1996. The FERC has requested additional information from the MAPP
on its market-based rate proposal before it will take further
action.
On December 18, 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. The Request for
Waiver is based on criteria established by the FERC, exempting
small public utilities as defined by the United States Small
Business Administration.
Three of the four state public service commissions which
regulate the Company's electric operations continue to evaluate
utility regulations with respect to retail competition (retail
wheeling). Additionally, federal legislation addressing this issue
has been introduced. The MPSC, NDPSC and WPSC have initiated
discussions with jurisdictional utilities on the effects retail
wheeling would have on the industry and its customers. The MPSC
has adopted a set of principles to guide restructuring in that
state. These principles are similar to those recently adopted by
the National Association of Regulatory Utility Commissioners
(NARUC). The NARUC's general principle is that customers should
have access to adequate, safe, reliable and efficient services at
fair and reasonable prices at the lowest long-term cost to society,
and structural changes in the industry should be encouraged when
they result in improved economic efficiency and serve the broader
public interest. The NDPSC recently asked for comments from
jurisdictional utilities on the applicability of the NARUC's
principles, the effects of wholesale competition, and the effects
of mergers and acquisitions on the industry. The NDPSC held an
informal hearing and panel discussion in December 1996, regarding
these matters. Further discussions will be held on the issues
surrounding retail wheeling. The WPSC will continue its study of
retail wheeling during 1997, with a comprehensive review of the
whole issue and its likely economic impact on the State of Wyoming.
The SDPUC has not initiated any proceedings to date.
Although Montana-Dakota is unable to predict the outcome of
such regulatory proceedings or legislation or the extent of such
competition, 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 demand and load management costs. In Montana
(23 percent of electric revenues), such cost changes are includible
in general rate filings.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1996 actual and 1997 through 1999 anticipated net capital
expenditures applicable to Montana-Dakota's electric operations:
Actual Estimated
1996 1997 1998 1999
Production $ 4.9 $ 5.2 $ 8.1 $ 9.4
Transmission 2.1 2.5 2.8 3.2
Distribution, General
and Common 11.1 10.0 7.5 7.5
$18.1 $17.7 $18.4 $20.1
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).
Montana-Dakota is currently unable to determine what modifications
may be necessary or the costs associated with any changes which may
be required at the Big Stone Station.
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 1996 and does not expect to incur any
significant capital expenditures related to environmental
facilities during 1997 through 1999.
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 142 communities and adjacent rural areas as of
December 31, 1996, and provides natural gas transportation services
to certain customers on its system. These services are provided
through a distribution system aggregating over 4,100 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, 1996, Montana-Dakota's
net natural gas and propane distribution plant investment
approximated $78.5 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 1996 natural gas and propane utility operating
revenues by jurisdiction is as follows: North Dakota -- 44
percent; Montana -- 29 percent; South Dakota -- 21 percent and
Wyoming -- 6 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 weather patterns.
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,
1996 1995 1994 1993 1992
Mdk (thousands of decatherms)
Sales:
Residential 22,682 20,135 19,039 19,565 17,141
Commercial 15,325 13,509 12,403 11,196 9,256
Industrial 276 295 398 386 284
Total Sales 38,283 33,939 31,840 31,147 26,681
Transportation:
Commercial 1,677 1,742 2,011 3,461 3,450
Industrial 7,746 9,349 7,267 9,243 10,292
Total Transporta-
tion 9,423 11,091 9,278 12,704 13,742
Total Throughput 47,706 45,030 41,118 43,851 40,423
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 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.
In June 1995, Montana-Dakota filed a general natural gas rate
increase application with the MPSC requesting an increase of $2.1
million or 4.4 percent. On April 17, 1996, the MPSC issued an
order in this proceeding authorizing additional annual revenues of
$1.0 million, or 49 percent of the original amount requested. The
rate increase became effective May 1, 1996.
Capital Requirements --
Montana-Dakota's net capital expenditures aggregated $5.7
million for natural gas and propane distribution facilities in 1996
and are anticipated to be approximately $8.4 million, $7.8 million
and $8.1 million in 1997, 1998 and 1999, 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 with regard to the issue described 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 23 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. At December 31, 1996, the net natural
gas transmission plant investment was approximately $159.0 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 1996,
represented 91 percent of Williston Basin's currently subscribed
firm transportation capacity. On November 7, 1996, Montana-Dakota
executed a new firm transportation agreement with Williston Basin
for a term of five years beginning in July 1997. Montana-Dakota's
current firm transportation agreements will expire at that time.
In addition, Montana-Dakota has contracted 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 1994 through 1996, 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 1996, 1995 and 1994 is as follows:
1996 1995 1994
Production (MMcf) 6,324 5,184 4,932
Average sales price $1.11 $0.91 $1.37
Production costs, including taxes $0.43 $0.30 $0.47
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, 1996, are as follows:
Gross Net
Productive Wells 532 479
Developed Acreage (000's) 233 210
Undeveloped Acreage (000's) 49 44
The following table shows the results of natural gas development
wells drilled and tested during 1996, 1995 and 1994:
1996 1995 1994
Productive 32 17 13
Dry Holes --- --- ---
Total 32 17 13
At December 31, 1996, there was 1 well in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 133.4 Bcf at December 31, 1996.
These amounts are supported by a report dated January 31, 1997,
prepared by Ralph E. Davis Associates, Inc., an independent firm of
petroleum and natural gas engineers.
For additional information related to Williston Basin's natural
gas interests, see Note 19 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 totalled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
On August 16, 1996, the Federal District Court issued its
decision finding that Moncrief is entitled to damages for the
difference between the price Moncrief would have received under the
geographic favored-nations price clause of the contract for the
period from August 13, 1993, through July 7, 1996, and the actual
price received for the gas. The favored-nations price is the
highest price paid from time to time under contracts in the same
geographic region for natural gas of similar quantity and quality.
The Federal District Court reopened the record until October 15,
1996, to receive additional briefs and exhibits on this issue.
On October 15, 1996, Moncrief submitted its brief claiming
damages ranging as high as $22 million under the geographic favored-
nations price theory. Williston Basin, in its brief, contended that
Moncrief waived its claim for a favored-nations price under an
agreement with Williston Basin, and Moncrief's damage claims were
calculated utilizing non-comparable contracts. Williston Basin's
exhibits show Moncrief's damages should be limited to approximately
$800,000 under the geographic favored-nations price theory.
A hearing on all pending matters is currently scheduled for
April 3, 1997. Williston Basin plans to file for recovery from
ratepayers of amounts which may be ultimately due to Moncrief, if
any.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota District Court,
Northwest Judicial District, against Williston Basin and the
Company. Apache and Snyder are oil and natural gas producers who
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. Williston Basin, the
Company and Koch have settled their disputes. Apache and Snyder
have recently provided alleged damages under differing theories
ranging up to $8.2 million without interest. A motion to intervene
in the case by several other producers, all of whom had contracts
with Koch but not with Williston Basin, was denied on December 13,
1996. Trial on this matter is scheduled for September 8, 1997.
The claims of Apache and Snyder, in Williston Basin's opinion,
are without merit and overstated. If any amounts are ultimately
found to be due Apache and Snyder, Williston Basin plans to file for
recovery from ratepayers.
On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia against
Williston Basin and over 70 other natural gas pipeline companies.
Grynberg, acting on behalf of the United States under the False
Claims Act, is alleging improper measurement of the heating content
or volume of natural gas purchased by the defendants resulting in
the underpayment of royalties to the United States. The United
States government, particularly officials from the Departments of
Justice and Interior, reviewed the complaint and the evidence
presented by Grynberg and declined to intervene in the action,
permitting Grynberg to proceed on his own. Williston Basin believes
Grynberg's claims are without merit and intends to vigorously
contest this suit.
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. In July
1995, the FERC issued an order relating to Williston Basin's 1992
rate change application. In August 1995, Williston Basin filed,
under protest, tariff sheets in compliance with the FERC's order,
with rates which went into effect on September 1, 1995. Williston
Basin requested rehearing of certain issues addressed in the order.
On July 19, 1996, the FERC issued an order granting in part and
denying in part Williston Basin's rehearing request. A hearing was
held on August 29, 1996, and this matter is currently pending before
the FERC. In addition, Williston Basin has appealed certain issues
contained in the FERC's orders to the U.S. Court of Appeals for the
D.C. Circuit (D.C. Circuit Court).
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.
On February 3, 1997, Williston Basin filed briefs with the D.C.
Circuit Court related to its appeal of orders which had been
received from the FERC beginning in May 1993, regarding the
appropriate selling price of certain natural gas in underground
storage which was determined to be excess upon Williston Basin's
implementation of Order 636. The FERC ordered that the gas be
offered for sale to Williston Basin's customers at its original
cost. Williston Basin requested rehearing of this matter on the
grounds that the FERC's order constituted a confiscation of its
assets, which request was subsequently denied by the FERC.
Williston Basin believes that it should be allowed to sell this
natural gas at its fair value and retain any profits resulting from
such sales since its ratepayers had never paid for the natural gas.
Oral arguments on this matter before the D.C. Circuit Court are
scheduled for May 9, 1997.
Reserves have been provided for a portion of the revenues that
have been collected subject to refund with respect to pending
regulatory proceedings and for the recovery of certain producer
settlement buy-out/buy-down costs 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, $6.0 million and
$4.6 million in 1996, 1995 and 1994, respectively.
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. On December 26, 1996, the
D.C. Circuit Court 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.
Beginning in October 1992, as a result of prevailing natural gas
prices, Williston Basin began to sell and transport a portion of the
natural gas held under the repurchase commitment. Through the
second quarter of 1996, 17.8 MMdk of this natural gas had been sold.
However, 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 the
remaining 43.0 MMdk of this gas to its then current market 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. The
recognition of the then current market value of this natural gas
facilitated the sale by Williston Basin of 10.4 MMdk from the date
of the write-down through December 31, 1996, and should allow
Williston Basin to market the remaining 32.5 MMdk on a sustained
basis enabling Williston Basin to liquidate this asset over
approximately the next five years.
Other Information --
In December 1994, the United States Minerals Management Service
(MMS) directed Williston Basin to pay approximately $1.9 million,
plus interest, in claimed royalty underpayments. These royalties
are attributable to natural gas production by Williston Basin from
federal leases in Montana and North Dakota for the period March 1,
1988, through December 31, 1991. This matter is currently on appeal
with the MMS.
In December 1993, Williston Basin received from the Montana
Department of Revenue (MDR) an assessment claiming additional
production taxes due of $3.7 million, plus interest, for 1988
through 1991 production. These claimed taxes result from the MDR's
belief that certain natural gas production during the period at
issue was not properly valued. Williston Basin does not agree with
the MDR and has reached an agreement with the MDR that the appeal
process be held in abeyance pending further review.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1996 actual and 1997 through 1999 anticipated net capital
expenditures applicable to Williston Basin's operations:
Actual Estimated
1996 1997 1998 1999
Production and Gathering $---* $ 4.5 $ 6.7 $13.0
Underground Storage .1 .4 1.0 1.4
Transmission 3.2 5.4 4.2 10.9
General and Other 1.7 2.2** 1.7** 4.7**
$5.0 $12.5 $13.6 $30.0
* Net of $5.1 million in preferred stock and cash received from
the sale of 208 miles of underutilized gathering lines and
related facilities to Interenergy Corporation.
** Includes net capital expenditures for Prairielands.
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 produce and sell construction
aggregates (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.
In April 1996, KRC Holdings 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, road and
highway construction and maintenance.
In June 1996, KRC Holdings purchased the assets of Medford
Ready-Mix Concrete, Inc. (Medford) located in Medford, Oregon. The
acquired company serves the residential and small commercial
construction market with ready-mixed concrete and aggregates.
For information regarding sales volumes and revenues for the
construction materials operations for 1994 through 1996, 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
influences 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 1994, 1995 and 1996, no
single customer accounted for more than 10 percent of annual
construction materials revenues.
Coal Operations:
General --
Knife River is engaged in lignite coal mining operations.
Knife River's surface mining operations are located at Beulah,
North Dakota and Savage, Montana. The average annual production
from the Beulah and Savage mines approximates 2.6 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,
1996 1995 1994 1993 1992
(In thousands)
Tons sold:
Montana-Dakota generating stations 528 453 691 624 521
Jointly-owned generating stations--
Montana-Dakota's share 565 883 1,049 1,034 1,021
Others 1,695 2,767 3,358 3,299 3,259
Industrial and other sales 111 115 108 109 112
Total 2,899 4,218 5,206 5,066 4,913
Revenues $32,696 $39,956 $45,634 $44,230 $43,770
In recent years, in response to competitive pressures from other
mines, Knife River has reduced its coal prices and/or not passed
through cost increases which are 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.
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 Station, against the Company and Knife River. In its
complaint, the Co-owners 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 as 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 are seeking damages in an
unspecified amount. On January 8, 1996, the Company and Knife River
filed separate motions with the State District Court to dismiss or
stay pending arbitration. On May 6, 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.
On September 12, 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. In the alternative, the Co-owners
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, 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. 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
1996 actual, including the amounts related to the acquisition of
Baldwin and Medford, and 1997 (including amounts related to
anticipated acquisitions) through 1999 anticipated net capital
expenditures applicable to Knife River's consolidated construction
materials and mining operations:
Actual Estimated
1996 1997 1998 1999
Construction Materials $22.2 $31.1 $ 9.4 $ 6.6
Coal 1.9 4.3 4.6 4.5
$24.1 $35.4 $14.0 $11.1
Knife River continues to seek additional growth opportunities.
These include investigating 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.
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 United States 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 payment of punitive damages. Hawaiian Cement is a Hawaiian
general partnership whose general partners (with joint and several
liability) are Knife River Hawaii, Inc., an indirect wholly owned
subsidiary of the Company, and Adelaide Brighton Cement (Hawaii),
Inc. Unitek is seeking civil penalties under the Clean Air Act (as
described below), and had sought damages for various claims (as
described above) of up to $20 million in the aggregate.
On August 7, 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.
On September 16, 1996, Unitek and Hawaiian Cement reached a
settlement which resolved all claims relating to the $20 million in
damages that Unitek had previously sought. However, the settlement
did not resolve the matter regarding the civil penalties sought by
Unitek relating to the alleged violations by Hawaiian Cement of the
Clean Air Act nor did it affect the EPA's Notice of Violation (NOV)
as discussed below. 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 continue to negotiate
the remaining Clean Air Act claims.
On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The
NOV states 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. It is also possible
that the EPA could elect to join the suit filed by Unitek.
Depending upon the specific actions that may ultimately be taken by
either the EPA or the District Court, Hawaiian Cement is likely to
have to modify its operations at its cement manufacturing facility.
Hawaiian Cement has met with the EPA and settlement discussions are
currently ongoing.
Although no assurance can be provided, the Company does not
believe that the total cost of any modifications to the facility,
the level of civil penalties which may ultimately be assessed or
settlement costs, will have a material effect on the Company's
results of operations.
Reserve Information --
As of December 31, 1996, the combined construction materials
operations had under ownership approximately 120 million tons of
recoverable aggregate reserves.
As of December 31, 1996, Knife River had under ownership or
lease, reserves of approximately 229 million tons of recoverable
lignite coal, 89 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 1996 production. Knife River estimates that
approximately 67 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 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.
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 1996, 1995 and 1994
are as follows:
1996 1995 1994
Oil:
Production (000's of barrels) 2,149 1,973 1,565
Average sales price $17.91 $15.07 $13.14
Natural Gas:
Production (MMcf) 14,067 12,319 9,228
Average sales price $2.09 $1.51 $1.84
Production costs, including taxes,
per net equivalent barrel $3.31 $3.18 $4.04
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, 1996, are as follows:
Gross Net
Productive Wells:
Oil 2,712 148
Natural Gas 491 28
Total 3,203 176
Developed Acreage (000's) 702 65
Undeveloped Acreage (000's) 947 73
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1996, 1995 and 1994:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1996 1 2 3 4 0 4 7
1995 3 2 5 8 1 9 14
1994 4 3 7 6 1 7 14
At December 31, 1996, there were three development wells and no
exploratory wells in the process of drilling.
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 1996, 1995
and 1994:
1996 1995 1994
Acquisitions $23.2 $ 9.1 $ 3.2
Exploration 8.1 7.7 12.6
Development 15.9 22.2 18.8
Net Capital Expenditures $47.2 $39.0 $34.6
Fidelity Oil's net capital expenditures are anticipated to be
approximately $50 million for both 1997 and 1998 and $55 million for
1999.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 16.1 million barrels and 66.8
Bcf, respectively, at December 31, 1996. Of these amounts, 9.3
million barrels and 2.2 Bcf, as supported by a report dated
January 9, 1997, prepared by Ralph E. Davis Associates, Inc., an
independent firm of petroleum and natural gas engineers, were
related to its properties located in the Cedar Creek Anticline in
southeastern Montana.
For additional information related to Fidelity Oil's oil and
natural gas interests, see Note 19 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.
Also, Williston Basin and over 70 other natural gas pipeline
companies have been named as defendants in a legal action related
to measurement of the heating content or volume of natural gas
purchased by the defendants. Such suit was filed by Grynberg.
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.
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 1996.
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 1996 and 1995 and dividends
declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
1996
First Quarter $23.00 $19.88 $0.2725
Second Quarter 23.50 20.13 0.2725
Third Quarter 22.38 20.75 0.2775
Fourth Quarter 23.38 21.25 0.2775
$1.1000
1995*
First Quarter $18.67 $17.17 $0.2666
Second Quarter 20.00 17.75 0.2666
Third Quarter 21.33 19.08 0.2725
Fourth Quarter 23.08 19.63 0.2725
$1.0782
_______________________
* Adjusted for October 1995 three-for-two common stock split.
As of December 31, 1996, the Company's common stock was held by
over 14,600 stockholders.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 48 and 49
of the Company's Annual Report which is incorporated herein by
reference.<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 1996 1995 1994
Electric $ 11.4 $ 12.0 $ 11.7
Natural gas distribution 4.9 1.6 .3
Natural gas transmission 2.5 8.4 6.1
Construction materials and
mining 11.5 10.8 11.6
Oil and natural gas production 14.4 8.0 9.3
Earnings on common stock $ 44.7 $ 40.8 $ 39.0
Earnings per common share $ 1.57 $ 1.43 $ 1.37
Return on average common equity 13.0% 12.3% 12.1%
Earnings for 1996 increased $3.9 million from the comparable
period a year ago due primarily to higher oil and natural gas
production and prices at the oil and natural gas production
businesses. Increased retail sales at the electric and natural gas
distribution businesses, primarily the result of 14 percent colder
weather than the comparable period a year ago, also added to the
increase in earnings. Increased transportation of natural gas held
under the repurchase commitment and increased volumes transported
to storage, combined with the benefits of a favorable rate change
implemented in January 1996, at the natural gas transmission
business further improved earnings. In addition, earnings from
Baldwin and Hawaiian Cement, businesses acquired in April 1996, and
September 1995, respectively, contributed to the earnings increase.
The write-down to the then current market price of the natural gas
available under the repurchase commitment partially offset the
earnings increase. The write-down, which approximated $21.1
million, or $12.9 million after tax, was significantly offset by
the reversal of certain reserves for tax and other contingencies at
the natural gas transmission and oil and natural gas production
businesses, aggregating $7.4 million and $1.8 million after tax,
respectively. The net effect of these items resulted in a $3.7
million, or 13 cent per common share, net charge to earnings for
the year. Also somewhat offsetting the earnings improvement was
the nonrecurring effect of a favorable FERC order received in April
1995. The order allowed for the one-time billing of customers for
$2.2 million after tax, including interest, to recover a portion of
the amount previously refunded in July 1994. In addition,
increased purchased power demand charges at the electric business
and increased operating costs at the electric, natural gas
transmission and oil and natural gas production businesses
partially offset the earnings improvement. Higher interest expense
at the construction materials and mining and oil and natural gas
production businesses also somewhat offset the earnings increase.
The effects of lower coal sales to the Big Stone Station due to the
expiration of the coal contract in August 1995 and the resulting
closure of the Gascoyne mine also partially offset the earnings
improvement.
Earnings for 1995 increased $1.8 million from the comparable
period a year earlier due primarily to increased retail sales at
the electric business and increased throughput at the natural gas
distribution and natural gas transmission businesses. Increased
oil prices and oil and natural gas production at the oil and
natural gas production business combined with the benefits derived
from favorable rate changes at the natural gas distribution and
transmission businesses also increased earnings. The favorable
rate change at the natural gas transmission business resulted from
the previously described FERC order received in April 1995 on a
rehearing request relating to a 1989 general rate proceeding.
Income from Hawaiian Cement also contributed to the earnings
increase. 1994 earnings included the benefit of a $4.5 million
gain (after tax) realized on the sale of an equity investment in
General Atlantic Resources, Inc. (GARI). Additionally, the effects
of decreased natural gas prices at the natural gas transmission and
oil and natural gas production businesses, lower coal sales to the
Big Stone Station due to the expiration of a coal contract in
August 1995, and increased costs associated with rainy West Coast
weather at the construction materials operations partially offset
the earnings increase.
________________________________
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.
<PAGE>
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.
Montana-Dakota -- Electric Operations
Years ended December 31,
1996 1995 1994
Operating revenues:
Retail sales $128.8 $ 124.4 $ 123.2
Sales for resale and other 10.0 10.2 10.7
138.8 134.6 133.9
Operating expenses:
Fuel and purchased power 44.0 41.8 43.2
Operation and maintenance 41.4 40.1 41.0
Depreciation, depletion and
amortization 17.1 16.3 15.5
Taxes, other than income 6.8 6.5 6.6
109.3 104.7 106.3
Operating income 29.5 29.9 27.6
Retail sales (kWh) 2,067.9 1,993.7 1,955.1
Sales for resale (kWh) 374.6 408.0 444.5
Average cost of fuel and
purchased power per kWh $ .017 $ .016 $ .017
Montana-Dakota -- Natural Gas Distribution Operations
Years ended December 31,
1996 1995 1994
Operating revenues:
Sales $151.5 $ 146.8 $ 151.7
Transportation and other 3.5 3.7 3.6
155.0 150.5 155.3
Operating expenses:
Purchased natural gas sold 102.7 102.6 111.3
Operation and maintenance 30.0 30.4 30.0
Depreciation, depletion and
amortization 6.9 6.7 6.1
Taxes, other than income 3.9 3.9 4.0
143.5 143.6 151.4
Operating income 11.5 6.9 3.9
Volumes (dk):
Sales 38.3 33.9 31.8
Transportation 9.4 11.1 9.3
Total throughput 47.7 45.0 41.1
Degree days (% of normal) 116.2% 101.6% 96.7%
Average cost of natural gas,
including transportation,
per dk $ 2.67 $ 3.02 $ 3.50
Williston Basin -- Natural Gas Transmission Operations
Years ended December 31,
1996 1995 1994
Operating revenues:
Transportation $ 60.4* $ 54.1* $ 52.6*
Storage 10.7 12.6 10.6
Natural gas production and
other 7.5 5.2 7.7
78.6 71.9 70.9
Operating expenses:
Operation and maintenance 37.2* 35.7* 38.8*
Depreciation, depletion and
amortization 6.7 7.0 6.6
Taxes, other than income 4.5 3.8 4.2
48.4 46.5 49.6
Operating income 30.2 25.4 21.3
Volumes (dk):
Transportation--
Montana-Dakota 43.4 35.4 33.0
Other 38.8 32.6 30.9
82.2 68.0 63.9
Produced (Mdk) 6,073 4,981 4,732
* Includes amortization and
related recovery of deferred
natural gas contract buy-out/
buy-down and gas supply
realignment costs $ 10.6 $ 11.4 $ 12.8
Knife River -- Construction Materials and Mining Operations
Years ended December 31,
1996** 1995** 1994
Operating revenues:
Construction materials $ 99.5 $ 73.1 $ 71.0
Coal 32.7 39.9 45.6
132.2 113.0 116.6
Operating expenses:
Operation and maintenance 105.8 87.8 88.2
Depreciation, depletion and
amortization 7.0 6.2 6.4
Taxes, other than income 3.3 4.5 5.4
116.1 98.5 100.0
Operating income 16.1 14.5 16.6
Sales (000's):
Aggregates (tons) 3,374 2,904 2,688
Asphalt (tons) 694 373 391
Ready-mixed concrete
(cubic yards) 340 307 315
Coal (tons) 2,899 4,218 5,206
** Does not include information related to Knife River's 50 percent ownership
interest in Hawaiian Cement which was acquired in September 1995 and is
accounted for under the equity method.
Fidelity Oil -- Oil and Natural Gas Production Operations
Years ended December 31,
1996 1995 1994
Operating revenues:
Oil $ 39.0 $ 30.1 $ 20.9
Natural gas 29.3 18.7 17.1
68.3 48.8 38.0
Operating expenses:
Operation and maintenance 15.6 13.7 12.0
Depreciation, depletion and
amortization 25.0 18.6 13.5
Taxes, other than income 3.5 2.6 3.7
44.1 34.9 29.2
Operating income 24.2 13.9 8.8
Production (000's):
Oil (barrels) 2,149 1,973 1,565
Natural gas (Mcf) 14,067 12,319 9,228
Average sales price:
Oil (per barrel) $17.91 $ 15.07 $ 13.14
Natural gas (per Mcf) 2.09 1.51 1.84
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 $58.2 million, $53.8 million and $4.4
million, respectively, for 1996, $54.6 million, $49.2 million and
$5.4 million, respectively, for 1995, and $65.2 million, $58.5
million and $6.7 million, respectively, for 1994.
1996 compared to 1995
Montana-Dakota -- 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, is 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 brings 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, 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.
Montana-Dakota -- 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 which closed in
September 1995, and one which experienced lower production, and to
a cement manufacturing facility due to its use of 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.
Williston Basin -- 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.
Knife River -- 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 Hawaiian Cement 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.
Fidelity Oil -- 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.
1995 compared to 1994
Montana-Dakota -- Electric Operations
Operating income at the electric business increased primarily
due to higher retail sales revenues and lower fuel and purchased
power costs. Higher average usage by residential and commercial
customers, due to more normal weather, contributed to the revenue
improvement. Reduced demand by oil producers and refiners
contributed to a decline in industrial sales, which somewhat offset
the retail sales revenue improvement. Fuel and purchased power
costs decreased due to changes in generation mix between lower and
higher cost generating stations. This decrease was partially
offset by higher purchased power demand charges. The increase in
demand charges, related to a participation power contract, is the
result of the purchase of an additional five megawatts of capacity
beginning in May 1995, offset in part by the pass-through of
periodic maintenance costs during 1994. Decreased maintenance
expenses at the Coyote Station, due to less scheduled downtime,
partially offset by increased turbine, generator and boiler
maintenance at the Heskett Station, also improved operating income.
Increased depreciation expense, due to higher average depreciable
plant, and lower sales for resale due to a surplus of low-cost
hydroelectric energy available from the Western Area Power
Administration during August through November 1995 partially offset
the increase in operating income.
Earnings for the electric business improved due to the
operating income increase, partially offset by higher income taxes.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income increased at the natural gas distribution
business due to the effect of $2.3 million in general rate
increases and improved sales. The sales improvement resulted from
the addition of over 5,100 customers and more normal weather than
1994. The pass-through of lower average natural gas costs and the
effects of a Wyoming Supreme Court order granting recovery in 1994
of a prior refund made by Montana-Dakota reduced revenues. The
effect of higher volumes transported were largely offset by lower
average transportation rates. Higher operation expenses, due
primarily to higher payroll-related costs somewhat offset by lower
sales expenses, partially offset the operating income improvement.
Increased depreciation expense, due to higher average depreciable
plant, also partially offset the increase in operating income.
Natural gas distribution earnings increased due to the
improvement in operating income. A decreased return realized on
net storage gas inventory and deferred demand costs partially
offset the earnings increase. This return decline of approximately
$619,000 (after tax) results from decreases in the net book balance
on which the natural gas distribution business is allowed to earn
a return.
Williston Basin -- Natural Gas Transmission Operations
Natural gas transmission operating income increased primarily
due to an increase in transportation and storage revenues. The
transportation revenue increase resulted primarily from the
benefits of the favorable FERC order received in April 1995 on a
rehearing request relating to a 1989 general rate proceeding as
previously discussed. In addition, higher demand revenues
associated with the storage enhancement project completed in late
1994, and increased volumes transported to storage, somewhat offset
by decreased transportation of natural gas held under the
repurchase commitment and reduced recovery of deferred natural gas
contract buy-out/buy-down and gas supply realignment costs, added
to the transportation revenue improvement. Lower operation and
maintenance expenses, primarily lower production royalty expenses
and reduced amortization of deferred natural gas contract buy-
out/buy-down and gas supply realignment costs, and lower taxes
other than income, largely lower production taxes, further
contributed to the increase in operating income. A decline in
natural gas production revenue, primarily due to a 54 cent per
decatherm decline in realized natural gas prices, somewhat reduced
by increased volumes produced, partially offset the increase in
operating income. Increased depreciation expense, resulting from
higher average depreciable plant, also somewhat reduced the
operating income improvement.
Earnings for this business improved due primarily to the
increase in operating income, higher interest income, lower company
production refunds (included in Other income -- net) and lower
interest expense. Higher interest income of $583,000 (after tax)
is related to the previously described refund recovery. The
decline in interest expense aggregating $623,000 (after tax) is
primarily due to long-term debt retirements and lower interest
rates. Increased carrying costs on the natural gas repurchase
commitment, due to higher average interest rates, partially offset
the earnings increase.
Knife River -- Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income declined $636,000
primarily due to higher operation expenses. Operation expenses
increased due primarily to additional work required to be
subcontracted, due to unusually wet weather, and increased sales
volumes. Increased revenues due to higher aggregate sales volumes,
increased cement sales volumes at higher prices, increased soil
remediation volumes, higher ready-mixed concrete prices, higher
construction and aggregate delivery revenues and increased steel
fabrication sales volumes, partially offset the operating income
decline. Lower asphalt sales, due to increased competition, lower
ready-mixed concrete sales and lower average soil remediation
prices partially offset the revenue improvement.
Coal Operations --
Operating income for the coal operations decreased $1.5 million
primarily due to decreased coal revenues, primarily the result of
lower sales to the Big Stone Station due to the expiration of the
coal contract in August 1995 and the resulting closure of the
Gascoyne Mine. Decreased operation expenses, resulting primarily
from lower sales volumes and lower depreciation expense and lower
taxes other than income, both due primarily to the closure of the
Gascoyne Mine, partially offset the decline in operating income.
Consolidated --
Earnings decreased due to the decline in coal and construction
materials operating income and increased interest expense, due to
increased long-term debt borrowings. Income from the 50 percent
interest in Hawaiian Cement acquired in September 1995 and gains
from the sale of equipment relating to the Gascoyne Mine closure,
partially offset the decline in earnings. These items are
reflected in Other income -- net.
Fidelity Oil -- Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production
business increased primarily as a result of higher oil revenues,
$5.4 million of which was due to increased production, and $3.8
million of which stemmed from higher average oil prices. Also,
increased natural gas revenue, $5.7 million of which was due to
higher natural gas volumes produced partially offset by a $4.1
million revenue decrease resulting from lower natural gas prices,
contributed to the operating income improvement. Also adding to
operating income was decreased production taxes, stemming largely
from the timing of payments in 1995 as compared to 1994.
Operation expenses increased, as a result of higher production but
were somewhat offset by lower average production costs, partially
offsetting the operating income improvement. Also reducing
operating income was increased depreciation, depletion and
amortization expense largely due to higher production.
Earnings for this business declined due to the 1994 realization
of a $4.5 million gain (after tax) related to the sale of an equity
investment in GARI. The increase in operating income partially
offset the earnings decrease.
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 impact 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.
New Accounting Standard
In October 1996, the American Institute of Certified Public
Accountants issued Statement of Position 96-1, "Environmental
Remediation Liabilities" (SOP 96-1). SOP 96-1 provides
authoritative guidance for the recognition, measurement, display
and disclosure of environmental remediation liabilities in
financial statements. The Company will adopt SOP 96-1 on
January 1, 1997, and the adoption is not expected to have a
material effect on the Company's financial position or results of
operations.
Liquidity and Capital Commitments
The Company's net capital expenditures (in millions of dollars)
for 1994 through 1996 and as anticipated for 1997 through 1999 are
summarized in the following table, which also includes the
Company's capital needs for the retirement of maturing long-term
securities.
Actual Estimated
1994 1995 1996 Capital Expenditures-- 1997 1998 1999
Montana-Dakota:
$ 14.2 $19.7 $18.7 Electric $17.0 $17.8 $20.1
13.2 8.9 6.3 Natural Gas Distribution 9.5 8.1 8.1
27.4 28.6 25.0 26.5 25.9 28.2
14.4 9.7 10.1 Williston Basin* 12.6 13.3 29.3
3.6 36.8 25.0 Knife River 35.4 13.9 11.1
38.6 39.9 51.8 Fidelity 55.0 55.0 60.0
1.0 2.6 .8 Prairielands * * *
85.0 117.6 112.7 129.5 108.1 128.6
Net proceeds from sale or
(3.6) (2.8) (11.8) disposition of property (5.5) (4.4) (4.3)
81.4 114.8 100.9 Net capital expenditures 124.0 103.7 124.3
Retirement of Long-term
Debt/Preferred Stock--
28.3 10.4 35.4 Montana-Dakota 11.4 6.4 6.4
7.5 10.0 7.5 Williston Basin .5 .4 .5
--- --- --- Fidelity --- 7.7 8.3
--- .1 .5 Prairielands * * *
35.8 20.5 43.4 11.9 14.5 15.2
$117.2 $135.3 $144.3 Total $135.9 $118.2 $139.5
* Effective January 1, 1997, information related to Prairielands is
included with Williston Basin.
In reconciling net capital expenditures to investing activities
per the Consolidated Statements of Cash Flows, the net capital
expenditures for Prairielands, which is not considered a major
business segment, are not reflected in investing activities in the
Consolidated Statements of Cash Flows for 1994, 1995 and 1996. In
addition, the 1994 capital expenditures for Montana-Dakota's
natural gas distribution business are reflected net of $5.8 million
of storage gas purchased from Williston Basin while the 1994
Williston Basin amount is reflected in the table above net of the
sale of storage gas of $8.3 million.
In 1996 Montana-Dakota provided all the funds needed for its
net capital expenditures and securities retirements, excluding the
$25 million discussed below, from internal sources. Montana-Dakota
expects to provide all of the funds required for its net capital
expenditures and securities retirements for the years 1997 through
1999 from internal sources, through the use of its $30 million
revolving credit and term loan agreement, $30 million of which was
outstanding at December 31, 1996, 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 June 1996, the Company redeemed $25 million of its 9 1/8% Series
first mortgage bonds, due May 15, 2006. The funds required to
retire the 9 1/8% Series first mortgage bonds were provided by
Williston Basin's repayment of $27.5 million of intercompany debt
payable to the Company.
Williston Basin's 1996 net capital expenditures and securities
retirements were met through internally generated funds and the
issuance of long-term debt as discussed below. Williston Basin
expects to meet its net capital expenditures for the years 1997
through 1999 with a combination of internally generated funds,
short-term lines of credit aggregating $40.4 million, $2 million of
which was outstanding at December 31, 1996, 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. In May 1996, Williston Basin privately placed
$20 million of notes with the proceeds and cash on hand used to
repay the $27.5 million of intercompany debt payable to the
Company. In addition, in November 1996, Williston Basin privately
placed $15 million of notes with the proceeds used to replace other
maturing long-term debt.
Knife River's 1996 net capital expenditures including the
acquisitions of Baldwin and Medford, were met through funds on
hand, funds generated from internal sources, short-term lines of
credit and a revolving credit agreement. It is anticipated that
funds generated from internal sources, short-term lines of credit
aggregating $11 million, none of which was outstanding at December
31, 1996, a revolving credit agreement of $55 million, $47 million
of which was outstanding at December 31, 1996, and the issuance of
long-term debt and the Company's equity securities will meet the
needs of this business unit for 1997 through 1999. In April 1996,
amounts available under the revolving credit agreement were
increased from $40 million to $55 million. Also in April 1996,
amounts available under the short-term lines of credit were
increased from $6 million to $8 million and in August 1996, were
further increased from $8 to $11 million.
Fidelity Oil's 1996 net capital expenditures related to its oil
and natural gas acquisition, development and exploration program
were met through funds generated from internal sources and long-
term credit facilities. Fidelity's borrowing base, based on proven
and producing reserves, is currently $65 million, which consists of
$23 million of issued notes, $7 million in an uncommitted note
shelf facility, and a $35 million revolving line of credit, $14.8
million of which was outstanding at December 31, 1996. In April
1996, the borrowing base was increased from $55 million to $65
million and concurrently the amount available under the revolving
line of credit was increased from $25 million to $35 million. It
is anticipated that Fidelity's 1997 through 1999 net capital
expenditures and debt retirements will be met from internal sources
and existing long-term credit facilities.
The Company utilizes its short-term lines of credit aggregating
$40 million, $2 million of which was outstanding on December 31,
1996, and its $30 million revolving credit and term loan agreement,
all of which is outstanding at December 31, 1996, to meet its
short-term financing needs and to take advantage of market
conditions when timing the placement of long-term or permanent
financing.
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, 1996, the Company could have issued
approximately $247 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.7 and 3.0 times for 1996 and 1995, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 5.4 times in 1996 compared to 3.9 times in 1995. Common
stockholders' investment as a percent of total capitalization was
54% and 57% at December 31, 1996 and 1995, respectively.
Effects of Inflation
The Company's consolidated financial statements reflect
historical costs, thus combining the impact of dollars spent at
various times. Such dollars have been affected by inflation, which
generally erodes the purchasing power of monetary assets and
increases operating costs. During times of chronic inflation, the
loss of purchasing power and increased operating costs could
potentially result in inadequate returns to stockholders primarily
because of the lag in rate relief granted by regulatory agencies.
Further, because the ratemaking process restricts the amount of
depreciation expense to historical costs, cash flows from the
recovery of such depreciation are inadequate to replace utility
plant.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 23 through 47 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 1 through 5 and 18 and 19 of the
Company's Proxy Statement dated March 3, 1997 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 13 through 18 of the Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 19 of the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.<PAGE>
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, 1996 *
Consolidated Balance Sheets at December 31,
1996, 1995 and 1994 *
Consolidated Statements of Capitalization at
December 31, 1996, 1995 and 1994 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1996 *
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 1996 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 1996 is not to be
deemed filed as part of this report.<PAGE>
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 **
+ 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, as
amended to date **
+ 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 *
12 Computation of Ratio of Earnings to Fixed
Charges **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1996 **
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.<PAGE>
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: February 28, 1997 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 February 28, 1997
Harold J. Mellen, Jr. Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief Operating February 28, 1997
Douglas C. Kane (Executive Vice President Officer and
and Chief Operating Officer) Director
/s/ Warren L. Robinson Chief Financial February 28, 1997
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 28, 1997
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director February 28, 1997
John A. Schuchart (Chairman of the Board)
/s/ San W. Orr, Jr. Director February 28, 1997
San W. Orr, Jr. (Vice Chairman of the Board)
/s/ Thomas Everist Director February 28, 1997
Thomas Everist
/s/ Richard L. Muus Director February 28, 1997
Richard L. Muus
/s/ Robert L. Nance Director February 28, 1997
Robert L. Nance
/s/ John L. Olson Director February 28, 1997
John L. Olson
/s/ Homer A. Scott, Jr. Director February 28, 1997
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director February 28, 1997
Joseph T. Simmons
/s/ Sister Thomas Welder Director February 28, 1997
Sister Thomas Welder<PAGE>
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 executive 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 he 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 him in connection with such action, suit
or proceeding if he acted in good faith and in a manner he
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 his 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 he 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 his 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 he 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 him in connection with the
defense or settlement of such action or suit if he acted in good
faith and in a manner he 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 ofall the 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 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, he shall be indemnified against expenses
(including attorneys' fees) actually and reasonably incurred by
him in connection therewith.
(d) Any indemnification under the foregoing provisions
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 director, officer,
employee or agent is proper in the circumstances because he has
met the applicable standard of conduct as set forth in
subsections (a) and (b) of this Section. Such determination
shall be made (i) by a majority vote of the directors who are not
parties to such action, suit or proceeding, even though less than
a quorum, or (ii) if there are no such directors, or if such
directors so direct, by independent legal counsel in a written
opinion, or (iii) by the stockholders.
(e) Expenses (including attorneys' fees) incurred by an
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 he 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 his
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 him
and incurred by him in any such capacity, or arising out of his
status as such, whether or not the Corporation would have the
power to indemnify him 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 he would if he 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 he 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.
EXECUTIVE INCENTIVE COMPENSATION PLAN
____________________________________________________________
I. PURPOSE
The purpose of the Executive Incentive Compensation Plan
(the "Plan") is to provide an incentive for key executives of MDU
Resources Group, Inc. (the "Company") to focus their efforts on
the achievement of challenging and demanding corporate
objectives. The Plan is designed to reward successful corporate
performance as measured against specified performance goals as
well as exceptional individual performance. When corporate
performance reaches or exceeds the performance targets and
individual performance is exemplary, incentive compensation
awards, in conjunction with salaries, will provide a level of
compensation which recognizes the skills and efforts of the key
executives.
II. BASIC PLAN CONCEPT
The Plan provides an opportunity to earn annual incentive
compensation based on the achievement of specified annual
performance objectives. A target incentive award for each
individual within the Plan is established based on the
position level and assigned salary grade market value (midpoint).
The target incentive award represents the amount to be paid,
subject to the achievement of the performance objective targets
established each year. Larger incentive awards than target may
be authorized when performance exceeds targets, lesser or no
amounts may be paid when performance is below target.
It is recognized that during a Plan year major unforeseen
changes in economic and environmental conditions or other
significant factors beyond the control of management may
substantially affect the ability of the Plan participants to
achieve the specified performance goals. Therefore, in its
review of corporate performance the Compensation Committee of the
Board of Directors (the "Committee"), in consultation with the
Chief Executive Officer of MDU Resources Group, Inc., may modify
the performance targets. However, it is contemplated that such
target modifications will be necessary only in years of unusually
adverse or favorable external conditions.
III. ADMINISTRATION
The Plan shall be administered by the Committee with the
assistance of the Chief Executive Officer of the MDU Resources
Group, Inc. The Committee shall approve annually, prior to the
beginning of each Plan year, the list of eligible participants,
the Plan's performance targets, and the target incentive award
level for each position within the Plan. The Committee shall
have final discretion to determine actual award payment levels,
method of payment, and whether or not payments shall be made for
any Plan year.
IV. ELIGIBILITY
Executives who are determined by the Committee to have a key
role in both the establishment and achievement of Company
objectives shall be eligible to participate in the Plan.
V. PLAN PERFORMANCE MEASURES
Performance measures shall be established that consider
shareholder and customer interests. These measures shall be
evaluated annually based on achievement of specified goals.
The performance measure reflective of shareholder's
interest will be the percentage attainment of the earnings goal
as specified in the annual operating plan. This measure will be
applied at the corporate level for individuals, such as the Chief
Executive Officer, or at the business unit level for individuals
whose major or sole impact is on business unit results.
Individual performance will be assessed based on the
achievement of annually established individual objectives.
Threshold, target and maximum award levels will be
established annually for each performance measure and business
unit. The Committee will retain the right to make all
interpretations as to the actual attainment of the desired
results and will determine whether any circumstances beyond the
control of management need to be considered.
VI. TARGET INCENTIVE AWARDS
Target incentive awards will be expressed as a percentage of
each participant's assigned salary grade market value (midpoint).
These percentages shall vary by position and reflect larger
reward opportunity for positions having greater effect on the
establishment and accomplishment of the Company's or business
unit's objectives. An exhibit showing the target awards as a
percentage of salary grade market value (midpoint) for eligible
positions will be attached to this Plan at the beginning of each
Plan year.
VII. INCENTIVE FUND DETERMINATION
The target incentive fund is the sum of the individual
target incentive awards for all eligible participants. The
actual incentive fund may be lower, equal to, or greater than the
target fund as determined by the Committee, based on actual
performance as compared with approved performance objectives.
At the close of each Plan year, the Chief Executive
Officer of MDU Resources Group, Inc. will prepare an analysis
showing the Company's and business unit's performance in relation
to each of the performance measures employed. This will be
provided to the Committee for review and comparison to threshold,
target and maximum performance levels. In addition, any
recommendations of the Chief Executive Officer will be presented
at this time. The Committee will then determine the amount of
the target incentive fund earned.
VIII. INDIVIDUAL AWARD DETERMINATION
Each individual participant's award will be based first upon
the level of performance achieved by the Company or business unit
and secondly based upon the individual's performance. The
performance measures applicable for assessing individual
performance will be established at the beginning of each Plan
year. The assessment by the Committee, after consultation with
the Chief Executive Officer, of achievement relative to the
established performance measures, as determined by a percentage
from 0 percent to 150 percent, will be applied to the
Participant's target incentive award which has been first
adjusted for Company or business unit performance.
IX. PAYMENT OF AWARDS
In order to receive an award under the Plan, the Participant
must remain in the employment of the Company or business unit for
the entire Plan year and be an employee on the payment date. An
individual participant who transfers between the Company and
business units may receive a prorated award at the discretion of
the Committee. If employment is terminated prior to the payment
date as a result of death, disability or retirement, or due to
special circumstances as determined by the Committee, payment may
be made after termination. Payments made under this Plan will
not be considered part of compensation for pension purposes.
Payments when made will be in cash, stock, or a combination
thereof as determined appropriate by the Committee. Incentive
awards may be deferred if the appropriate elections have been
executed prior to the end of the Plan year. Deferred amounts
will accrue interest at a rate determined annually by the
Committee.
In the event of a "change in control" (as defined by the
Committee in its Rules and Regulations) then any award deferred
by each Participant shall become immediately payable to the
Participant in cash, together with accrued interest thereon to
the date of payment. In the event the Participant files suit to
collect the participant's deferred award then all of the court
costs, other expenses of litigation, and attorneys' fees shall be
paid by the Company in the event the Participant prevails upon
any of the Participant's claims for payment of a deferred award.
_________________________
Plan adopted November 4, 1982
Plan amended November 6, 1986
Plan amended May 15, 1996, effective January 1, 1996
Plan amended November 13, 1996, effective January 1, 1997<PAGE>
MDU RESOURCES GROUP, INC.
EXECUTIVE INCENTIVE COMPENSATION PLAN
RULES AND REGULATIONS
The Compensation Committee of the Board of Directors of MDU
Resources Group, Inc. (the "Company") adopted Rules and Regulations
for the administration of the Management Incentive Compensation
Plan (the "Plan") on February 9, 1983, following adoption of the
Plan by the Board of Directors of the Company on November 4, l982.
I. DEFINITIONS
The following definitions shall be used for purposes of these Rules
and Regulations and for the purposes of administering the Plan:
1. The "Committee" shall be the Compensation
Committee of the Board of Directors of the
Company.
2. The "Company" shall refer to MDU Resources
Group, Inc. alone and shall not refer to its
utility division or to any of its subsidiary
corporations.
3. "Participants" for any Plan Year shall be those
executives who have been approved by the
Committee as eligible for participation in the
Plan for such Plan Year.
4. "Payment Date" shall be the date set by the
Committee for payment of awards, other than
those awards deferred pursuant to section IX of
the Plan and section VII of these Rules and
Regulations.
5. The "Plan" shall refer to the Executive
Incentive Compensation Plan.
6. The "Plan Year" shall be the calendar year.
7. "Change in control" shall mean the earlier of
the following to occur: (a) the public
announcement by the Company or by any person
(which shall not include the Company, any
subsidiary of the Company or any employee
benefit plan of the Company or of any
subsidiary of the Company) ("Person") that such
Person, who or which, together with all
Affiliates and Associates (within the meanings
ascribed to such terms in Rule 12b-2 of the
General Rules and Regulations under the
Securities Exchange Act of 1934, as amended (17
C.F.R. 240.12b-2)) of such Person, shall be the
beneficial owner of twenty percent (20%) or
more of the voting stock then outstanding; (b)
the commencement of, or after the first public
announcement of any Person to commence, a
tender or exchange offer the consummation of
which would result in any Person becoming the
beneficial owner of voting stock aggregating
thirty percent (30%) or more of the then
outstanding voting stock; (c) the announcement
of any transaction relating to the Company
required to be described pursuant to the
requirements of Item 6(e) of Schedule 14A of
Regulation 14A of the Securities and Exchange
Commission under the Securities Exchange Act of
1934 (17 C.F.R. 240.14a-101, item 6(e)); (d) a
proposed change in the constituency of the
Board of Directors of the Company such that,
during any period of two (2) consecutive years,
individuals who at the beginning of such period
constitute the Board of Directors of the
Company cease for any reason to constitute at
least a majority thereof, unless the election
or nomination for election by the shareholders
of the Company of each new Director was
approved by a vote of at least two-thirds (2/3)
of the directors then still in office who were
members of the Board of Directors of the
Company at the beginning of the period; or (e)
any other event which shall be deemed by a
majority of the Compensation Committee of the
Board of Directors of the Company to constitute
a "change in control."
8. The "Prime Rate" shall be the base rate on
corporate loans posted by at least 75 percent
of the nation's 30 largest banks as reported
daily in The Wall Street Journal.
II. ADMINISTRATION
1. The Committee shall have the full power to
construe and interpret the Plan and to
establish and to amend these Rules and
Regulations for its administration.
2. No member of the Committee shall participate in
a decision as to their own eligibility for, or
award of, an incentive award payment.
3. Prior to the beginning of each Plan Year, the
Committee shall approve a list of eligible
executives and notify those so approved that
they are eligible to participate in the Plan
for such Plan Year.
4. Prior to the beginning of each Plan Year, the
Committee shall draw up an Annual Operating
Plan. The Annual Operating Plan shall include
the Plan's performance measures and performance
targets as well as the target incentive award
levels for each salary grade covered by the
Plan for the following Plan Year. The Annual
Operating Plan, insofar as it is relevant to
each individual Participant, shall be made
available by the Committee to each Participant
in the Plan at the beginning of each Plan Year.
5. The Committee shall have final discretion to
determine actual award payment levels, method
of payment, and whether or not payments shall
be made for any Plan Year. However, unless the
Plan's performance objectives are met for the
Plan Year, no award shall be made for that Plan
Year. Performance targets modified pursuant to
section II of the Plan will be deemed
performance targets for purposes of determining
whether or not these targets have been met.
III. PLAN PERFORMANCE MEASURES
1. The Committee shall establish the percentage
attainment of earnings measure and the
percentage attainment of individual goals
measure. The Committee may establish more or
fewer performance measures as it deems
necessary.
2. The earnings measure shall be set by reference
to the earnings of the Company or the
individual business unit.
3. Individual performance will be assessed based
on the achievement of annually established
individual objectives.
4. Plan performance measures will be applied at
the corporate level for individuals such as the
Chief Executive Officer whose major or sole
impact is Company-wide, or at the business unit
level for individuals whose major or sole
impact is on the business unit results. The
Annual Operating Plan shall contain a list of
individuals to whom the Plan performance
measures will be applied at the corporate level
and a list of those individuals for whom the
Plan performance measures will be applied at
the business unit level. The relevant business
unit for each individual will be identified.
5. The Committee shall set threshold, target and
maximum award levels for the performance
measures, for each business unit, and for the
Company. Those levels shall be included in the
Annual Operating Plan.
6. The Committee will retain the authority to
determine whether or not the actual attainment
of these measures has been made.
IV. TARGET INCENTIVE AWARDS
1. Target incentive awards will be a percentage
of each Participant's assigned salary grade
midpoint.
2. Target incentive awards shall be set by the
Committee annually and will be included in the
Annual Operating Plan.
V. INCENTIVE FUND DETERMINATION
1. The target incentive fund is the sum of the
individual target incentive awards for all
eligible Participants.
2. The actual incentive fund will be determined by
the Committee, based on actual performance as
compared with the approved performance
measures.
3. As soon as practicable following the close of
each Plan Year, the Chief Executive Officer
will provide the Committee with an analysis
showing the Company's and each relevant
business unit's performance in relation to both
of the performance measures. The Committee
will review the analysis and determine, in its
sole discretion, the amount of the actual
incentive fund.
4. In determining the actual incentive fund, the
Committee may consider any recommendations of
the Chief Executive Officer.
VI. INDIVIDUAL AWARD DETERMINATION
1. The Committee shall have the sole discretion to
determine each individual Participant's award.
The Committee's decision will be based first
upon the level of performance achieved by the
Company or business unit and second upon the
individual's performance.
2. The Committee, after consultation with the
Chief Executive Officer, shall set the award as
a percentage from 0 percent to 150 percent of
the Participant's target incentive award,
adjusted for Company or business unit
performance.
VII. PAYMENT OF AWARDS
1. On the date the Committee determines the awards
to be made to individual Participants, it shall
also establish the Payment Date.
2. In order to receive an award under the Plan, a
Participant must remain in the employment of
the Company for the entire Plan Year and be an
employee on the Payment Date.
3. If employment is terminated prior to Payment
Date as a result of death, disability or
retirement, or due to special circumstances as
determined by the Committee in its sole
discretion, payment may be made after
termination.
4. Payments of the awards may be made in cash,
stock or a combination thereof as determined by
the Committee. Such payments shall be made on
the Payment Date unless the Participant has
deferred, in whole or in part, the receipt of
the award by making an election on the deferral
form attached hereto, prior to the end of the
Plan Year immediately preceding the Payment
Date.
5. In the event a Participant has elected to defer
receipt of all or a portion of the award, the
Company shall set up an account in their name.
The amount of their award to the extent
deferred will be credited to the participant's
account on the Payment Date.
6. The balance credited to an account of a
Participant who has elected to defer receipt of
an award will be an unsecured, unfunded
obligation of the Company.
7. Interest shall accrue on the balance credited
to a Participant's account. The rate of
interest shall be the Prime Rate plus
1 percentage point as reported on the last
Friday in January of each year. Interest on
the balance in an account shall accrue at the
rate so determined from the Payment Date
immediately following the determination to the
Payment Date of the following year.
8. Interest shall be credited to the account on
the day preceding Payment Date and shall be
calculated on the balance in the Participant's
account as of that date.
9. A Participant may elect to defer any
percentage, not to exceed l00, of an annual
award.
10. A Participant electing to defer any part of an
award must elect one of the following dates for
payment:
(1) Retirement date;
(2) Payment Date next following
termination of employment; or
(3) Payment Date of the fifth year
following the year in which the award
may be made.
11. A Participant may elect to receive the deferred
amounts accumulated in the Participant's
account in monthly installments, not to exceed
120. In the event the Participant elects to
receive the amounts in the Participant's
account in more than one installment, interest
shall continue to accrue on the balance
remaining in their account at the applicable
rate or rates determined annually by the
Committee.
12. In the event of the death of a Participant in
whose name a deferred account has been set up,
the Company shall, within six months
thereafter, pay to the Participant's estate or
the designated beneficiary the entire amount in
the deferred account.
13. In the event of a "change in control" then any
award deferred by each Participant shall become
immediately payable to the Participant. In the
event the Participant files suit to collect a
deferred award then all of the Participant's
court costs, other expenses of litigation, and
attorneys' fees shall be paid by the Company in
the event the Participant prevails upon any of
the Participant's claims for payment.
__________________________
Rules and Regulations adopted November 4, 1982
Rules and Regulations amended August 5, 1987
Rules and Regulations amended February 9, 1989
Rules and regulations amended May 15, 1996, effective January 1, 1996
Rules and regulations amended November 13, 1996, effective January 1, 1997
MDU RESOURCES GROUP, INC.
SUPPLEMENTAL INCOME SECURITY PLAN
(As Amended and Restated Effective January 1, 1997)
TABLE OF CONTENTS
INTRODUCTION
ARTICLE I -- DEFINITIONS
ARTICLE II -- ELIGIBILITY
ARTICLE III -- SUPPLEMENTAL DEATH AND RETIREMENT BENEFITS
ARTICLE IV -- EXCESS RETIREMENT BENEFITS
ARTICLE V -- DISABILITY BENEFITS
ARTICLE VI -- MISCELLANEOUS
ARTICLE VII -- ADDITIONAL AFFILIATED COMPANIES
INTRODUCTION
The objective of the MDU Resources Group, Inc. Supplemental
Income Security Plan (the "Plan") is to provide certain levels of survivor
benefits and retirement income for a select group of management or highly
compensated employees and their families. Eligibility for participation in
this Plan shall be limited to management or highly compensated employees
who are selected by the Chief Executive Officer of MDU Resources, Inc. (the
"Company"). This Plan became effective January 1, 1982, has been amended
from time to time thereafter, and has been amended and restated effective
January 1, 1997.
The Plan is intended to constitute an unfunded "excess benefit
plan" as defined in Section 3(36) of the Employee Retirement Income
Security Act of 1974, as amended ("ERISA"), to the extent it provides
benefits that would be paid under one or more of the tax-qualified pension
plans of the Company or certain of its subsidiaries but for certain
limitations set forth under the Internal Revenue Code of 1986, as amended
(the "Code"), and constitutes an unfunded plan of deferred compensation
maintained by the Company primarily for the purpose of providing non-
elective deferred compensation for a select group of management or highly
compensated employees.
ARTICLE I -- DEFINITIONS
Unless a different meaning is plainly implied by the context, the
following terms as used in this Plan shall have the following meanings:
1.1 "Administrator" means the Chief Executive Officer of the
Company or any other person to whom the Chief Executive Officer of the
Company has delegated the authority to administer the Plan. The Manager of
the Corporate Human Resources Department of the Company is initially
delegated the authority to perform the administrative responsibilities
required under the Plan.
1.2 "Affiliated Company" means any current or future corporation
which (i) is in a controlled group of corporations (within the meaning of
Section 414(b) of the Code) of which the Company is a member and (ii) has
been approved by the Chief Executive Officer of the Company to adopt the
Plan for the benefit of its Employees.
1.3 "Beneficiary" means an individual or individuals, any entity
or entities (including corporations, partnerships, estates or trusts) that
shall be entitled to receive benefits payable pursuant to the provisions of
this Plan by virtue of a Participant's death; provided, however, that if
more than one such person is designated as a Beneficiary hereunder, each
such person's proportionate share of the death benefit hereunder must
clearly be set forth in a written statement of the Participant received by
and filed with the Administrator prior to the Participant's death. If such
proportionate share for each Beneficiary is not set forth in the
designation, each Beneficiary shall receive an equal share of the death
benefits provided hereunder.
1.4 "Company" means MDU Resources Group, Inc., and its
successors, if any.
1.5 "Effective Date" of the Plan means January 1, 1982. The
Effective Date of this amendment and restatement of the Plan is January 1,
1997.
1.6 "Eligible Retirement Date" means the First Eligible
Retirement Date and the last day of each subsequent calendar month.
1.7 "Employee" means each person actively employed by an
Employer, as determined by such Employer in accordance with its practices
and procedures.
1.8 "Employer" means the Company and any Affiliated Company which
shall adopt this Plan with respect to its Employees with the prior approval
of the Company as set forth in Article 7 of the Plan.
1.9 "First Eligible Retirement Date" for a Participant means the
last day of the month during which such Participant is both no longer
actively employed by any Employer and has attained at least age 65.
1.10 "Limitation on Benefits" shall mean the statutory limitation
on the maximum benefit that may be payable to participants under a Pension
Plan due to the application of certain provisions contained in the Code.
1.11 "Participant" means a present or former management or highly
compensated Employee selected by the Chief Executive Officer of the Company
to receive benefits under this Plan. An Employee will become a Participant
at the time such Employee commences participation hereunder pursuant to the
provisions of Section 2.1 hereof.
1.12 "Pension Plan" means the MDU Resource Group, Inc. Pension
Plan for Non-Bargaining Unit Employees, the Williston Basin Interstate
Pipeline Company Pension Plan for Non-Bargaining Unit Employees, or the
Knife River Coal Mining Company Salaried Employees' Pension Plan, as in
effect on the Effective Date and as amended from time to time.
1.13 "Plan" means the Plan designated as the MDU Resources Group,
Inc. Supplemental Income Security Plan, as embodied herein, and any
amendments thereto.
1.14 "Plan Year" means the calendar year. The first Plan Year
for this Plan shall be the 1982 calendar year.
1.15 "Salary" means annual base earnings payable by an Employer
to a Participant excluding (i) bonuses, (ii) incentive compensation, and
(iii) any other form of supplemental income.
1.16 "Standard Actuarial Factors" means, with respect to a
Participant, the actuarial factors and assumptions used for the calculation
of actuarial equivalents under the Pension Plan under which the Participant
actively participates from time to time.
1.17 "Standard Life Insurance" means life insurance that could be
purchased from a commercial life insurance company at standard rates
without a surcharge assessed, based on an individual's general good health.
1.18 "Standard Underwriting Factors" means life insurance rating
factors utilized by a commercial life insurance company selected by the
Chief Executive Officer of the Company which are based on the risk
assessment classifications utilized by such insurer to determine if an
applicant qualifies for insurance at standard rates or if health or other
factors might require a surcharge.
1.19 "Year of Participation" means each Plan Year of
participation in the Plan by a Participant while actively employed by one
or more of the Employers (including years while such Participant is
qualified as totally disabled under the Employer's disability plan), as
determined in the sole discretion of the Administrator.
ARTICLE II -- ELIGIBILITY
2.1 Eligibility for Participation. The Chief Executive Officer
of the Company shall determine which management and/or highly compensated
Employees may be eligible to participate in the Plan. General criteria for
initial consideration of an Employee includes, but is not limited to, the
following: (A) either an officer (excluding assistant secretary or
assistant treasurer), or a senior management employee of an employer
earning a base salary exceeding a threshold amount as determined by the
Chief Executive Officer of the Company; (B) an executive who makes a
significant contribution to the Company's success and profitability; (C) an
executive in a business unit where benefits of this nature are a common
practice, or there is a specific need to recruit and retain key executives;
and (D) the expectation that participation in the Plan will not exceed four
percent of the total employment of the Company and affiliated companies.
Each Employee who is selected as eligible to participate hereunder and who
meets the requirements for participation set forth under Section 2.2 hereof
shall commence participation on the first day of the Plan Year coincident
with or next following the date of such Employee's selection.
2.2 Requirements for Participation. In order to be eligible to
participate in the Plan, an Employee selected by the Chief Executive
Officer of the Company must (i) be actively at work for one or more of the
Employers; (ii) have a current state of health and physical condition that
would satisfy customary requirements for insurability under Standard Life
Insurance; provided, however, that no provision of this Plan shall be
construed or interpreted to limit participation in the Plan in
contravention of the Americans With Disabilities Act and related federal
and state laws; and (iii) consent to supply information or to otherwise
cooperate as necessary to allow the Company to obtain life insurance on
behalf of such Employee (as set forth under Section 6.3 of the Plan).
2.3 Eligibility for Benefits. Subject to the provisions of
Articles III and IV hereof, Participants who terminate their employment
with an Employer subsequent to becoming vested in a retirement benefit
under a Pension Plan shall be eligible to receive a benefit under this
Plan. Plan benefits may commence (i) as of the earlier to occur of (A) the
first day of the month following the date of the Participant's death or (B)
if the Participant who elects to receive retirement benefits under Article
3 hereof, the Participant's First Eligible Retirement Date, for purposes of
the benefits payable under Article III of the Plan, and (ii) at the time
benefit payments commence to the Participant under a Pension Plan, for
purposes of the benefits payable under Article IV of the Plan.
2.4 Relationship to Other Plans. Participation in the Plan
shall not preclude or limit the participation of the Participant in any
other benefit plan sponsored by one or more of the Employers for which such
Participant otherwise would be eligible. However, any benefits payable
under this Plan shall not be deemed salary or compensation to the
Participant for purposes of determining benefits under any other employee
benefit plan maintained by one or more of the Employers.
2.5 Forfeiture of Benefits. Notwithstanding any provision of
this Plan to the contrary, if any Participant is discharged from employment
by one or more of the Employers for cause due to willful misconduct,
dishonesty, or conviction of a crime or felony, all as determined at the
sole discretion of the Chief Executive Officer of the Company the rights of
such Participant (or any Beneficiary of such Participant) to any present or
future benefit under this Plan shall be forfeited to the extent not
prohibited by applicable law.
ARTICLE III -- SUPPLEMENTAL DEATH AND RETIREMENT BENEFITS
3.1 Amount of Benefit.
(a) Subject to the provisions of Section 3.3 of the Plan,
the monthly supplemental death and/or retirement benefits payable on behalf
of (or to) a Participant as of such Participant's date of death (or First
Eligible Retirement Date) will be an amount determined at the sole
discretion of the Chief Executive Officer of Company at the time of the
Participant's commencement of participation in the Plan, as may be adjusted
from time to time thereafter by the Chief Executive Officer of the Company.
However, in no event will a Participant be entitled to have a monthly
supplemental death benefit paid on such Participant's behalf (or be
entitled to receive a monthly supplemental retirement benefit) that exceeds
the Monthly Death Benefit or Monthly Retirement Benefit (as applicable)
corresponding to the Participant's Salary in effect at the date such
initial or revised benefit determination is to be effective, all as set
forth in the applicable Appendix hereto. Benefits for Participants
retiring or dying after December 31, 1989, and prior to January 1, 1997,
shall be determined in accordance with Appendix A. Benefits for
Participants retiring or dying after December 31, 1996, shall be determined
in accordance with Appendix B; provided, however, that benefits for each
such individual who also was a Participant on December 31, 1996, shall be
determined in accordance with Appendix A or Appendix B, whichever such
Appendix provides for the greatest amount of benefits. Changes in Salary
do not automatically result in changes to a Participant's level of
benefits.
(b) Participants who died, terminated employment with, or
retired from, the Employers prior to January 1, 1990, will receive benefits
hereunder in accordance with the terms of the Plan as in effect at the time
of the Participant's death, termination of employment or retirement from
the Employers.
(c) The benefit amounts determined by the Chief Executive
Officer of the Company pursuant to Section (a) above are based on the
assumption that each Participant's health and physical condition at the
time of such Participant's commencement of participation in the Plan meets
customary requirements for Standard Life Insurance. Benefits under the
Plan may be reduced by the Chief Executive Officer of the Company within a
reasonable period following the establishment of such benefit level in
accordance with Standard Underwriting Factors, but only with respect to
that portion of the monthly death or retirement benefit for which the
criteria for health and physical condition are not met. Participants will
be notified of any such reduction within a reasonable period following
participation in the Plan. Once retirement benefits have been reduced
under this Section 3.1, such benefits shall not be further reduced for the
remainder of the Participant's participation in the Plan.
3.2 Amount of Monthly Benefit for Retirement or Death Prior to
Completing at Least 10 Years of Participation. If a Participant retires or
terminates employment with an Employer (for reasons other than the
Participant's death) before the Participant completes at least 10 Years of
Participation, the monthly death and/or retirement benefits to which such
Participant otherwise would be entitled under the terms of Section 3.1
hereof shall be reduced as follows:
Years of Participation Percent of Section 3.1
Completed by the Participant Benefits Payable
Less than 3 years 0%
3 years but less than 5 years 10%
5 years but less than 7 years 25%
7 years but less than 9 years 50%
9 years but less than 10 years 75%
10 years or more 100%
3.3 Payment of Monthly Benefit. Upon attainment of age 65 or,
as of such Participant's First Eligible Retirement Date (if later), a
Participant wil be entitled to determine the form of benefit payable to
such Participant under subsection (a) hereof, and the date of commencement
of such benefits, subject to the approval of the Chief Executive Officer of
the Company, in accordance with the terms of the Plan.
(a) The Participant may elect to receive:
(i) a monthly death benefit in amounts determined
pursuant to Section 3.1 hereof, multiplied by the appropriate percentage
amount set forth in Section 3.2, or
(ii) in lieu of any death benefits under this Plan
a monthly retirement benefit determined in accordance with Section 3.1,
multiplied by the appropriate percentage amount set forth in Section 3.2,
with no death benefit, or
(iii) a percentage of each benefit described in
subsections(a)(i) and (a)(ii) above. The percentage of each benefit must
be in even increments of ten percent (10%).
(b) A Participant must select one of the options under
subsection (a) above. If, in accordance with Sections 3.3(a)(ii) or (iii),
a Participant has elected to receive less than one hundred percent (100%)
of such Participant's monthly retirement benefit, the Participant may
subsequently elect to begin receiving an increased retirement benefit
except that there may be no more than two(2) such increases during the
Participant's lifetime, and no more than one (1) such increase during any
calendar year. Any such increase in retirement benefit payments will
result in a reduction in death benefits equal, when expressed as a
percentage amount, to the percentage increase in retirement benefit.
Participants shall not be entitled to decrease retirement benefit payments.
(c) Elections under this Section 3.3 must be communicated
in writing to the Administrator and will be effective as of the first day
of the first month following the Administrator's receipt and the approval
of such request by the Chief Executive Officer of the Company.
3.4 Payment of Monthly Death and Retirement Benefits.
(a) Death Benefits. Any death benefits payable with
respect to a Participant pursuant to Sections 3.3(a)(i) or 3.3(a)(iii)
shall commence on the first day of the calendar month next following the
date of the Participant's death and shall be payable in monthly
installments for a period of 180 months.
(b) Retirement Benefits. The monthly retirement benefits
under this Plan shall commence on the Eligible Retirement Date selected by
the Participant (upon 30 day's written notice to the Administrator) and
will be payable to such Participant in monthly installments for a period of
180 months. In the event the Participant dies prior to the completion of
such 180-month payment period, the balance of such retirement benefits
shall be paid to the Participant's Beneficiary at such times and in such
amounts as if the Participant had not died, such payment being made in
addition to any death benefits payable under Sections 3.3(a)(i) or (iii)
hereof. To the extent a Participant elects to commence receiving increased
retirement benefits pursuant to Section 3.3(b), the amount of increase of
retirement benefits shall be in the form of a monthly benefit payable for a
separate 180-month period.
(c) Method of Payment. Notwithstanding the provisions of
subsections (a) and (b) of this Section 3.4, the Chief Executive Officer of
the Company reserves the right to pay benefits in the form of an
actuarially equivalent single sum (as determined by the Administrator) when
retirement or death benefits are payable due to termination of employment,
excluding disability, or death prior to the Participant's attainment of age
55.
3.5 Exclusions and Limitations.
(a) No death benefits will be payable with respect to a
Participant in the event of such Participant's death by suicide within two
(2) years after commencement of participation in the Plan, and no benefit
increase will apply in the event of any such Participant's death by suicide
within two (2) years after such Participant becomes eligible for an
increase in death benefits.
(b) In the event that a Participant misrepresents any
health or physical condition at the time of commencement of participation
in the Plan or at the time of a retirement or death benefit increase, no
retirement or death benefit or retirement or death benefit increase will be
payable under the Plan within two (2) years of such misrepresentation.
3.6 Death of a Beneficiary.
(a) In the event any Beneficiary predeceases the
Participant, is not in existence, is not ascertainable, or is not locatable
as of the date benefits under the Plan become payable to such Beneficiary,
Plan benefits shall be paid to such contingent Beneficiary or Beneficiaries
as shall have been named by the Participant on the Participant's most
recent Beneficiary election form that has been received and filed with the
Administrator prior to the Participant's death. If no contingent
Beneficiary has been named, the contingent Beneficiary shall be the
Participant's estate.
(b) In the event any Beneficiary dies after commencing to
receive monthly benefits under the Plan but prior to the payment of all
monthly benefits to which such Beneficiary is entitled, remaining benefits
shall be paid to a beneficiary designated by the deceased Beneficiary (the
"Secondary Beneficiary"), provided such designation has been received and
filed with the Administrator prior to the death of the Beneficiary. If no
such person has been designated by the deceased Beneficiary, the Secondary
Beneficiary shall be the estate of the Beneficiary. In the event the
Secondary Beneficiary shall die prior to the payment of all benefits to
which such Secondary Beneficiary is entitled, the remainder of such
payments shall be made to such Secondary Beneficiary's estate. If the
Administrator is in doubt as to the right of any person to receive benefits
under the Plan, the Administrator may retain such amount, without liability
for any interest thereon, until the rights thereto are determined, or the
Administrator may pay such amount into any court of competent jurisdiction
and such payment shall be a complete discharge of the liability of the Plan
and the Employer therefor.
3.7 Discretion As To Benefit Amount. Notwithstanding the
foregoing, the Chief Executive Officer of the Company may, with full and
complete discretion, disregard Standard Underwriting Factors and customary
requirements for Standard Life Insurance in establishing and/or increasing
the amount of any Participant's retirement or death benefit under the Plan.
3.8 Suspension of Benefits Upon Reemployment. Employment with
any Employer subsequent to the commencement of retirement benefits under
this Article III may, at the sole discretion of the Chief Executive Officer
of the Company, result in the suspension of such benefits for the period of
such employment or reemployment.
ARTICLE IV -- EXCESS RETIREMENT BENEFITS
4.1 Participation. Benefits under this Article IV shall be
payable only to those Participants whose benefits under the Pension Plan
under which they otherwise participate commence prior such Participant's
attainment of age 65 and are reduced or limited by reason of the Limitation
on Benefits. Benefits under this Article IV (i) shall be payable only for
such period that the benefits under the Pension Plan are actually reduced
or limited and (ii) shall terminate as of the last day of the month
immediately preceding the month during which occurs the Participant's
sixty-fifth (65th) birthday. Furthermore, benefits under this Article IV
also shall be payable only to those Participants who are active Employees
on or after January 1, 1997.
4.2 Amount and Method of Payment.
(a) Amount of Benefit. The amount, if any, of the monthly
benefit payable to or on account of a Participant pursuant to this Article
IV shall equal the excess of (i) over (ii) where:
(i) equals the amount of monthly retirement
benefits which would be provided to the Participant under the Pension Plan
without regard to the Limitation on Benefits; and
(ii) equals the amount of monthly retirement
benefits payable to such Participant under the Pension Plan due to the
application of the Limitation on Benefits; provided, however, that no
benefit shall be payable to a Participant under this Article IV unless
the amount of such monthly benefit is at least fifty dollars ($50).
The benefit amount provided under this Section 4.2(a) shall be
determined with reference to the form of benefit determined under
Section 4.2(c) hereof and shall be calculated in accordance with the
Standard Actuarial Factors utilized under the Pension Plan.
(b) Vesting. The amount of benefits payable to a
Participant under this Article IV shall be subject to the vesting schedule
set forth in the Pension Plan. A Participant shall be vested in benefits
under this Article IV to the same extent as such Participant is vested in
benefits under the Pension Plan.
(c) Payment of Benefit. The benefits provided under this
Article IV shall be paid to each such Participant, surviving spouse (as
defined under the Pension Plan) or joint annuitant (as defined under the
Pension Plan) at the same time and in the same form and manner as benefits
are payable under the Pension Plan. Payments shall be made in accordance
with, and subject to, the terms and conditions of the Pension Plan;
provided, however, that no spousal consent shall be required to commence
any form of payment under this Article IV.
(d) Duration of Payments. Subject to Section 4.2(c),
benefits provided under this Article IV shall commence at the same time as
payments commence under the Pension Plan, and shall continue to age 65 or
the death of the Participant, if prior to age 65, and, if applicable, in a
reduced amount until the death of the Participant's lawful spouse or joint
annuitant, whichever is applicable for those Participants receiving
benefits under Appendix B.
(e) Treatment During Subsequent Employment. Employment
with any Employer subsequent to the commencement of benefits under this
Article IV will result in the suspension of such benefits for the period of
such employment or reemployment to the extent forth under the Pension Plan.
(f) Necessity of Actual Reduction. Notwithstanding any
other provision of this Plan, no amount shall be payable under this Article
IV unless the Participant's monthly benefit paid under the Pension Plan is
actually reduced because of application of the Limitation on Benefits.
Benefits payable to a Participant under this Article IV shall not duplicate
benefits payable to such Participant from any other plan or arrangement of
the Company. In the event the Secretary of the Treasury or a change in law
liberalizes the limitations applicable to determining the Limitation on
Benefits such that a Participant may receive additional benefits under the
Pension Plan, and the Pension Plan provides for the payment of such
additional benefits to the Participant, the amount payable under this
Article IV shall be reduced by a corresponding amount.
ARTICLE V -- DISABILITY BENEFITS
5.1 Monthly Disability Benefit.
(a) If a Participant becomes totally disabled following
commencement of participation in the Plan, the Participant shall continue
to receive credit for Years of Participation under the Plan for so long as
the Participant is totally disabled and such Participant's employment with
the Employer has not terminated. Following termination of the Participant's
employment with the Employer, the Participant's monthly retirement benefits
under Article III of the Plan shall commence beginning on or after the
Participant's First Eligible Retirement Date.
(b) A Participant is "totally disabled" if such Participant
is disabled within the meaning of the applicable long-term disability plan
sponsored by such Participant's Employer.
(c) If a Participant who terminates employment with the
Company due to total disability dies while totally disabled and before
attaining age 65, any death benefit payable to the Participant's
Beneficiary will be determined and paid in accordance with the terms of
Article III.
ARTICLE VI -- MISCELLANEOUS
6.1 Amendment and Termination. Any action to amend, modify,
suspend or terminate the Plan may be taken at any time, and from time to
time, by resolution of the Board of Directors of the Company (or any person
or persons duly authorized by resolution of the Board of Directors of the
Company to take such action) in its sole discretion and without the consent
of any Participant or Beneficiary, but no such action shall retroactively
reduce any benefits accrued by any Participant under this Plan prior to the
time of such action.
6.2 No Guarantee of Employment. Nothing contained herein shall
be construed as a contract of employment between a Participant and any
Employer or shall be deemed to give any Participant the right to be
retained in the employ of any Employer.
6.3 Funding of Plan and Benefit Payments. This Plan is unfunded
within the meaning of ERISA. Each Employer will make Plan benefit payments
from its general assets. Each Employer may purchase policies of life
insurance on the lives of Plan Participants and to refuse participation in
the Plan to any Employee who, if requested to do so, declines to supply
information or to otherwise cooperate so that the Employer may obtain life
insurance on behalf of such Participant. The Employer will be the owner
and the beneficiary of any such policy, and Plan benefits will be neither
limited to nor secured by any such policy or its proceeds. Participants
and their Beneficiaries shall have no right, title or interest in any such
life insurance policies, in any other assets of any Employer or in any
investments any Employer may make to assist it in meeting its obligations
under the Plan. All such assets shall be solely the property of such
Employer and shall be subject to the claims of such Employer's general
creditors. There are no assets of any Employer that are identified or
segregated for purposes of the payment of any benefits under this Plan. To
the extent a Participant or any other person acquires a right to receive
payments from an Employer under the Plan, such right shall be no greater
than the right of any unsecured general creditor of such Employer and such
person shall have only the unsecured promise of the Employer that such
payments shall be made.
6.4 Payment Not Assignable. Except in the case of a Qualified
Domestic Relations Order described under Code Section 414(p), Participants
and their Beneficiaries shall not have the right to alienate, anticipate,
commute, sell, assign, transfer, pledge, encumber or otherwise convey the
right to receive any payments under the Plan, and any payments under the
Plan or rights thereto shall not be subject to the debts, liabilities,
contracts, engagements or torts of Participants or their Beneficiaries nor
to attachment, garnishment or execution, nor shall they be transferable by
operation of law in the event of bankruptcy or insolvency. Any attempt,
whether voluntary or involuntary, to effect any such action shall be null,
void and of no effect.
6.5 Applicable Law. The Plan and all rights hereunder shall be
governed by and construed according to the laws of the State of North
Dakota, except to the extent such laws are preempted by the laws of the
United States of America.
6.6 Claims Procedure.
(a) Participants and Beneficiaries eligible for benefits
under this Plan, or any person duly authorized by them, have the right
under ERISA and the Plan to file a written claim to the Administrator for
payment of such benefits.
(b) If the claim is denied in whole or in part, the
claimant will receive written notice of the Administrator's decision,
including the specific reason for the decision, within 90 days after the
Administrator received the claim. If the Administrator needs more than 90
days to make a decision, the Administrator will notify the individual in
writing within the initial 90-day period. An additional 90 days may be
taken if the Administrator sends this notice. The extension notice will
show the date by when the Administrator's decision will be sent.
6.7 Plan Administration.
(a) The Plan shall be administered by the Administrator.
The Administrator shall serve as the final review under the Plan and shall
have sole and complete discretionary authority to determine conclusively
for all persons, and in accordance with the terms of the documents or
instruments governing the Plan, any and all questions arising from the
administration of the Plan and interpretation of all Plan provisions. The
Administrator shall make the final determination of all questions relating
to participation of employees and eligibility for benefits, and the amount
and type of benefits payable to any Participant or Beneficiary. In no way
limiting the foregoing, the Administrator shall have the following specific
duties and obligations in connection with the administration of the Plan:
(i) To promulgate and enforce such rules,
regulations and procedures as may be proper for the efficient
administration of the Plan;
(ii) To determine all questions arising in the
administration, interpretation and application of the Plan, including
questions of eligibility and of the status and rights of Participants
and any other persons hereunder;
(iii) To decide any dispute arising hereunder;
provided, however, that the Administrator shall not participate in any
matter involving any questions relating solely to the Administrator's own
participation or benefit under this Plan;
(iv) To advise the Boards of Directors of the
Employers regarding the known future need for funds to be available for
distribution;
(v) To correct defects, supply omissions and
reconcile inconsistencies to the extent necessary to effectuate the Plan;
(vi) To compute the amount of benefits and other
payments which shall be payable to any Participant or Beneficiary in
accordance with the provisions of the Plan and to determine the person or
persons to whom such benefits shall be paid;
(vii) To make recommendations to the Board of
Directors of the Company with respect to proposed amendments to the Plan;
(viii) To file all reports with government agencies,
Participants and other parties as may be required by law, whether such
reports are initially the obligation of the Employers, or the Plan;
(ix) To engage an actuary to the Plan, if
necessary, and to cause the liabilities of the Plan to be evaluated by such
actuary; and
(x) To have all such other powers as may be
necessary to discharge its duties hereunder.
(b) Decisions by the Administrator shall be final,
conclusive and binding on all parties and not subject to further review.
(c) The Administrator may employ attorneys, consultants,
accountants or other persons (who may be attorneys, consultants, actuaries,
accountants or persons performing other services for, or are employed by,
any Employer or any affiliate of any Employer), and the Administrator, the
Employers and their other officers and directors shall be entitled to rely
upon the advice, opinions or valuations of any such persons. No member of
the Board of Directors of any Employer, the Chief Executive Officer of the
Company, the Administrator, nor any other officer, director or employee of
the Company or of any Employer acting on behalf of the Board of Directors
of any Employer or the Chief Executive Officer of the Company or the
Administrator, shall be personally liable for any action, determination or
interpretation taken or made in good faith with respect to the Plan, and
all members of the Boards of Directors of the Employers, the Chief
Executive Officer of the Company and the Administrator and each officer or
employee of the Company or of an Employer acting on their behalf shall be
fully indemnified and protected by the Company for all costs, liabilities
and expenses (including, but not limited to, reasonable attorneys' fees and
court costs) relating to any such action, determination or interpretation.
6.8 Binding Nature. This Plan shall be binding upon and inure
to the benefit of the Employers and their successors and assigns and to the
Participants, their Beneficiaries and their estates. Nothing in this Plan
shall preclude any Employer from consolidating or merging into or with, or
transferring all or substantially all of its assets to another company or
corporation, whether or not such other company or corporation assumes this
Plan and any obligation of the Employer hereunder.
6.9 Withholding Taxes. The Employers may withhold from any
benefits payable under this Plan all Federal, State, city or other taxes as
shall be required pursuant to any law or governmental regulation or ruling.
6.10 Action Affecting Chief Executive Officer. To the extent any
action required to be taken by the Chief Executive Officer of the Company
would decrease, increase, accelerate, delay or otherwise materially impact
such individual's benefits under the Plan, such action shall be taken
instead by the Compensation Committee of the Board of Directors of the
Company.
6.11 Payments Due Missing Persons. The Administrator shall make
a reasonable effort to locate all persons entitled to benefits (including
retirement benefits and death benefits for Beneficiaries) under the Plan;
however, notwithstanding any provisions of this Plan to the contrary, if,
after a period of five years from the date such benefits first become due,
any such persons entitled to benefits have not been located, their rights
under the Plan shall stand suspended. Before this provision becomes
operative, the Administrator shall send a certified letter to all such
persons at their last known address advising them that their benefits under
the Plan shall be suspended. Any such suspended amounts shall be held by
the Employer for a period of three additional years (or a total of eight
years from the time the benefits first became payable) and thereafter such
amounts shall be forfeited and non-payable.
6.12 Liability Limited. Neither the Employers, the
Administrator, nor any agents, employees, officers, directors or
shareholders of any of them, nor any other person shall have any liability
or responsibility with respect to this Plan, except as expressly provided
herein.
6.13 Incapacity. If the Administrator shall receive evidence
satisfactory to it that a Participant or Beneficiary entitled to receive
any benefit under the Plan is, at the time when such benefit becomes
payable, a minor or is physically or mentally incompetent to receive such
benefit and to give a valid release therefor, and that another person or an
institution is then maintaining or has custody of such Participant or
Beneficiary and that no guardian, committee or other representative of the
estate of such Participant or Beneficiary shall have been duly appointed,
the Administrator may make payment of such benefit otherwise payable to
such Participant or Beneficiary (or to such guardian, committee or other
representative of person's estate) to such other person or institution, and
the release of such other person or institution shall be a valid and
complete discharge for the payment of such benefit.
6.14 Plurals. Where appearing in the Plan, the singular shall
include the plural, and vice versa, unless the context clearly indicates a
different meaning.
6.15 Headings. The headings and sub-headings in this Plan are
inserted for the convenience of reference only and are to be ignored in any
construction of the provisions hereof.
6.16 Severability. In case any provision of this Plan shall be
held illegal or void, such illegality or invalidity shall not affect the
remaining provisions of this Plan, but shall be fully severable, and the
Plan shall be construed and enforced as if said illegal or invalid
provisions had never been inserted herein.
6.17 Payment of Benefits. All amounts payable hereunder may be
paid directly by the Employer or pursuant to the terms of the grantor
trust, if any, established as a funding vehicle for benefits provided
hereunder.
ARTICLE VII -- ADDITIONAL AFFILIATED COMPANIES
7.1 Participation in the Plan.
(a) Any Employer may become an Affiliated Company with
respect to this Plan with the consent of the Chief Executive Officer of the
Company, upon the following conditions:
(i) such Employer shall make, execute and deliver
such instruments as the Company requires; and
(ii) such Employer shall designate the Company, the
Chief Executive Officer of the Company and the Administrator, as its agents
for purposes of this Plan.
(b) Any such Affiliated Company may by action of its Board
of Directors withdraw from participation, subject to approval by the Chief
Executive Officer of the Company.
7.2 Effect of Participation. Each Affiliated Company which with
the consent of the Chief Executive Officer of the Company complies with
Section 7.1(a) shall be deemed to have adopted this Plan for the benefit of
its Employees who participate in this Plan.
IN WITNESS WHEREOF, the Company, as the sponsoring employer of
the Plan, has caused this Plan document to be duly executed by its
President and Chief Executive Officer on this 14 day of November, 1996.
MDU RESOURCES GROUP, INC.
By: /s/ H. J. Mellen, Jr.
H. J. Mellen, Jr.
President and Chief Executive Officer
APPENDIX A
Monthly
Monthly Retirement
Level Salary Death Benefit Benefit*
D $ 50,000 - $ 59,999 $ 3,456 $ 1,728
E $ 60,000 - $ 74,999 $ 4,320 $ 2,160
F $ 75,000 - $ 99,999 $ 5,760 $ 2,880
G $100,000 - $124,999 $ 7,200 $ 3,600
H $125,000 - $149,999 $ 8,640 $ 4,320
I $150,000 - $174,999 $10,080 $ 5,040
J $175,000 - $199,999 $11,520 $ 5,760
K $200,000 - $224,999 $12,960 $ 6,480
L $225,000 - $249,999 $14,400 $ 7,200
M $250,000 - $274,999 $15,840 $ 7,920
N $275,000 - $299,999 $17,280 $ 8,640
O $300,000 - $324,999 $18,720 $ 9,360
P $325,000 - $349,999 $20,160 $10,080
All benefits are paid for a maximum of 180 months.
* This amount shall be lesser than the net present value of the death
benefit, as determined at the sole discretion of the Administrator.
APPENDIX B
Monthly Monthly
Death Retirement
Level Salary Benefit Benefit*
D $ 50,000 - $ 59,999 $ 2,660 $ 1,330
E $ 60,000 - $ 69,999 $ 3,600 $ 1,800
F $ 75,000 - $ 99,999 $ 5,160 $ 2,580
G $100,000 - $124,999 $ 7,200 $ 3,600
H $125,000 - $149,999 $ 8,940 $ 4,470
I $150,000 - $174,999 $10,720 $ 5,360
J $175,000 - $199,999 $12,500 $ 6,250
K $200,000 - $224,999 $14,600 $ 7,300
L $225,000 - $249,999 $16,430 $ 8,215
M $250,000 - $274,999 $18,250 $ 9,125
N $275,000 - $299,999 $20,950 $10,475
O $300,000 - $324,999 $24,290 $12,145
P $325,000 - $349,999 $27,340 $13,670
Q $350,000 - $399,999 $32,220 $16,110
R $400,000 - $449,999 $39,050 $19,525
S $450,000 - $499,999 $45,700 $22,850
T $500,000+ $52,400 $26,200
All benefits are paid for a maximum of 180 months.
* This amount shall be lesser than the net present value of the death
benefit, as determined at the sole discretion of the Administrator.
MDU RESOURCES GROUP, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
1996 1995 1994 1993 1992
(In thousands of dollars)
Earnings Available for
Fixed Charges:
Net Income per
Consolidated
Statements
of Income $45,470 $41,633 $39,845 $38,817* $35,371
Income Taxes 16,087 23,057 18,833 19,982* 10,900
61,557 64,690 58,678 58,799 46,271
Rents (a) 1,031 894 878 871 504
Interest (b) 34,101 29,924 29,173 27,928 30,056
Total Available for
Fixed Charges $96,689 $95,508 $88,729 $87,598* $76,831
Fixed Charges (c) $35,132 $30,818 $30,051 $28,799 $30,560
Ratio of Earnings to
Fixed Charges 2.75x 3.10x 2.95x 3.04x* 2.51x
* 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.<PAGE>
1996 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resource 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, careful 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, 1996 1995 1994
(In thousands, except per share amounts)
Operating Revenues
Electric $138,761 $134,609 $133,953
Natural gas 175,408 167,787 160,970
Construction materials and mining 132,222 113,066 116,646
Oil and natural gas production 68,310 48,784 37,959
514,701 464,246 449,528
Operating Expenses
Fuel and purchased power 43,983 41,769 43,203
Purchased natural gas sold 48,886 53,351 52,893
Operation and maintenance 225,682 202,327 203,269
Depreciation, depletion and
amortization 62,651 54,825 48,113
Taxes, other than income 21,974 21,398 23,875
403,176 373,670 371,353
Operating Income
Electric 29,476 29,898 27,596
Natural gas distribution 11,504 6,917 3,948
Natural gas transmission 30,231 25,427 21,281
Construction materials and mining 16,062 14,463 16,593
Oil and natural gas production 24,252 13,871 8,757
111,525 90,576 78,175
Other income -- net 5,617 4,789 10,480
Interest expense 28,832 24,690 25,350
Costs on natural gas repurchase
commitment (Note 3) 26,753 5,985 4,627
Income before income taxes 61,557 64,690 58,678
Income taxes 16,087 23,057 18,833
Net income 45,470 41,633 39,845
Dividends on preferred stocks 787 792 797
Earnings on common stock $ 44,683 $ 40,841 $ 39,048
Earnings per common share $ 1.57 $ 1.43 $ 1.37
Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533
Average common shares outstanding 28,477 28,477 28,477
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1996 1995 1994
(In thousands)
ASSETS
Property, Plant and Equipment
Electric $ 546,477 $ 535,016 $ 514,152
Natural gas distribution 164,843 161,080 157,174
Natural gas transmission 273,775 271,773 263,971
Construction materials and mining 173,663 151,751 147,284
Oil and natural gas production 211,555 167,542 151,532
1,370,313 1,287,162 1,234,113
Less accumulated depreciation,
depletion and amortization 617,724 570,855 541,842
752,589 716,307 692,271
Current Assets
Cash and cash equivalents 47,799 33,398 37,190
Receivables 73,187 61,961 55,409
Inventories 27,361 23,949 27,090
Deferred income taxes 26,011 31,663 26,694
Prepayments and other
current assets 17,300 11,261 12,287
191,658 162,232 158,670
Natural gas available under
repurchase commitment (Note 3) 37,233 70,750 70,913
Investments (Note 16) 53,501 46,188 16,914
Deferred charges and other assets 54,192 61,002 65,950
$1,089,173 $1,056,479 $1,004,718
CAPITALIZATION AND LIABILITIES
Capitalization (See Separate
Statements)
Common stockholders' investment $ 350,674 $ 337,317 $ 327,183
Preferred stocks 16,800 16,900 17,000
Long-term debt 280,666 237,352 217,693
648,140 591,569 561,876
Commitments and contingencies
(Notes 2,3,4,13 and 15) --- --- ---
Current Liabilities
Short-term borrowings 3,950 600 680
Accounts payable 31,580 22,261 20,222
Taxes payable 8,683 13,566 8,817
Other accrued liabilities,
including reserved revenues 100,938 100,779 88,516
Dividends payable 8,099 7,958 7,793
Long-term debt and preferred
stock due within one year 11,854 17,087 20,450
165,104 162,251 146,478
Natural gas repurchase commitment
(Note 3) 66,294 88,200 88,404
Deferred credits:
Deferred income taxes 116,208 118,459 114,341
Other 93,427 96,000 93,619
209,635 214,459 207,960
$1,089,173 $1,056,479 $1,004,718
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1996 1995 1994
(In thousands)
Common Stockholders' Investment
Common stock (Note 9):
Authorized -- 75,000,000 shares,
$3.33 par value
Outstanding -- 28,476,981 shares
in 1996 and 1995,
and 18,984,654
shares in 1994 $ 94,828 $ 94,828 $ 63,219
Other paid in capital 64,305 64,305 95,914
Retained earnings (Note 10) 191,541 178,184 168,050
Total common stockholders'
investment 350,674 337,317 327,183
Preferred Stocks (Note 11)
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 -- 19,000 shares
in 1996 (20,000 in 1995 and
21,000 in 1994) 1,900 2,000 2,100
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000 5,000
15,000 15,000 15,000
Total preferred stocks 16,900 17,000 17,100
Less current maturities and
sinking fund requirements 100 100 100
Net preferred stocks 16,800 16,900 17,000
Long-term Debt (Note 12)
Total long-term debt 292,420 254,339 238,043
Less current maturities and sinking
fund requirements 11,754 16,987 20,350
Net long-term debt 280,666 237,352 217,693
Total capitalization $648,140 $591,569 $561,876
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1996 1995 1994
(In thousands)
Operating Activities
Net income $ 45,470 $ 41,633 $ 39,845
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 62,651 54,825 48,113
Deferred income taxes and
investment tax credit -- net 4,551 7,631 3,409
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 6,580 7,177 7,866
Write-down of natural gas available
under repurchase commitment, net
of income taxes (Note 3) 11,364 --- ---
Changes in current assets and
liabilities:
Receivables (9,346) (6,552) 12,144
Inventories (1,218) 3,141 (6,799)
Other current assets 4,185 (3,943) 7,524
Accounts payable 7,584 2,039 (4,745)
Other current liabilities (22,434) 17,177 (19,249)
Other noncurrent changes (3,149) (1,023) 6,133
Net cash provided by operating
activities 106,238 122,105 94,241
Financing Activities
Net change in short-term borrowings 3,350 (80) (8,860)
Issuance of long-term debt 81,300 36,710 26,750
Repayment of long-term debt (43,262) (20,433) (35,700)
Retirement of preferred stocks (100) (100) (100)
Retirement of natural gas
repurchase commitment (4,157) (204) (10,121)
Dividends paid (32,113) (31,499) (30,793)
Net cash provided by (used in)
financing activities 5,018 (15,606) (58,824)
Investing Activities
Capital expenditures including
acquisitions of businesses:
Electric (18,674) (19,689) (14,188)
Natural gas distribution (6,255) (8,878) (19,033)
Natural gas transmission (10,127) (9,688) (6,147)
Construction materials and mining (25,063) (36,810) (3,597)
Oil and natural gas production (51,821) (39,917) (38,595)
(111,940) (114,982) (81,560)
Net proceeds from sale or disposition
of property 11,803 2,802 3,572
Net capital expenditures (100,137) (112,180) (77,988)
Sale of natural gas available
under repurchase commitment 10,595 163 8,118
Investments (7,313) 1,726 (56)
Net cash used in investing
activities (96,855) (110,291) (69,926)
Increase (decrease) in cash
and cash equivalents 14,401 (3,792) (34,509)
Cash and cash equivalents --
beginning of year 33,398 37,190 71,699
Cash and cash equivalents --
end of year $ 47,799 $ 33,398 $ 37,190
The accompanying notes are an integral part of these consolidated statements.<PAGE>
NOTE 1
Statement of Principal 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 1996, 1995 and 1994.
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.
Investments
Investments consist principally of the company's partnership
investment in Hawaiian Cement. The company accounts for its
partnership investment in Hawaiian Cement by the equity method. See
Note 16 for more information on this partnership investment.
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.
See Note 3 for more information on a write-down of the natural gas
available under the repurchase commitment with Frontier which occurred
in 1996.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventory 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. In
addition, the company recognizes revenue for its construction business
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 deferred credits" 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.
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, 1996 1995 1994
(In thousands)
Interest, net of amount capitalized $25,449 $24,436 $22,775
Income taxes $28,163 $18,330 $13,539
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Reclassifications
Certain reclassifications have been made in the financial statements
for 1995 and 1994 to conform to the 1996 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
New Accounting Standard
In October 1996, the American Institute of Certified Public
Accountants issued Statement of Position 96-1, "Environmental
Remediation Liabilities" (SOP 96-1). SOP 96-1 provides authoritative
guidance for the recognition, measurement, display and disclosure of
environmental remediation liabilities in financial statements. The
company will adopt SOP 96-1 on January 1, 1997, and the adoption is
not expected to have a material effect on the company's financial
position or results of operations.
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. In July 1995, the FERC issued
an order relating to Williston Basin's rate change application. In
August 1995, Williston Basin filed, under protest, tariff sheets in
compliance with the FERC's order, with rates which went into effect on
September 1, 1995. Williston Basin requested rehearing of certain
issues addressed in the order. On July 19, 1996, the FERC issued an
order granting in part and denying in part Williston Basin's rehearing
request. A hearing was held on August 29, 1996, and this matter is
currently pending before the FERC. In addition, Williston Basin has
appealed certain issues contained in the FERC's orders to the U.S.
Court of Appeals for the D.C. Circuit (D.C. Circuit Court).
Williston Basin anticipates filing briefs with the D.C. Circuit Court
on February 3, 1997, related to its appeal of orders which had been
received from the FERC beginning in May 1993, regarding the
appropriate selling price of certain natural gas in underground
storage which was determined to be excess upon Williston Basin's
implementation of Order 636. The FERC ordered that the gas be offered
for sale to Williston Basin's customers at its original cost.
Williston Basin requested rehearing of this matter on the grounds that
the FERC's order constituted a confiscation of its assets, which
request was subsequently denied by the FERC. Williston Basin believes
that it should be allowed to sell this natural gas at its fair value
and retain any profits resulting from such sales since its ratepayers
had never paid for the natural gas. Oral arguments on this matter
before the D.C. Circuit Court are scheduled for May 9, 1997.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund with respect to pending regulatory
proceedings and for the recovery of certain producer settlement buy-
out/buy-down costs 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, 1996, borrowings
totalled $84.0 million at a weighted average interest rate of
6.13 percent of which $66.3 million is reflected on the company's
Consolidated Balance Sheets under "Natural gas repurchase commitment"
and $17.7 million is included in "Other accrued liabilities" and
relates to current amounts owed as a result of recent sales of a
portion of this natural gas. 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. On December 26, 1996, the D.C. Circuit Court 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.
Beginning in October 1992, as a result of prevailing natural gas
prices, Williston Basin began to sell and transport a portion of the
natural gas held under the repurchase commitment. Through the second
quarter of 1996, 17.8 MMdk of this natural gas had been sold.
However, 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 the remaining
43.0 MMdk of this gas to its then current market 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. The recognition of the then
current market value of this natural gas facilitated the sale by
Williston Basin of 10.5 MMdk from the date of this write-down through
December 31, 1996, and should allow Williston Basin to market the
remaining 32.5 MMdk on a sustained basis enabling Williston Basin to
liquidate this asset over approximately the next five 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 totalled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
On August 16, 1996, the Federal District Court issued its decision
finding that Moncrief is entitled to damages for the difference
between the price Moncrief would have received under the geographic
favored-nations price clause of the contract for the period from
August 13, 1993, through July 7, 1996, and the actual price received
for the gas. The favored-nations price is the highest price paid from
time to time under contracts in the same geographic region for natural
gas of similar quantity and quality. The Federal District Court
reopened the record until October 15, 1996, to receive additional
briefs and exhibits on this issue.
On October 15, 1996, Moncrief submitted its brief claiming damages
ranging as high as $22 million under the geographic favored-nations
price theory. Williston Basin, in its brief, contended that Moncrief
waived its claim for a favored-nations price under an agreement with
Williston Basin, and Moncrief's damage claims were calculated
utilizing non-comparable contracts. Williston Basin's exhibits show
Moncrief's damages should be limited to approximately $800,000 under
the geographic favored-nations price theory.
A hearing on all pending matters is currently scheduled for April 3,
1997. Williston Basin plans to file for recovery from ratepayers of
amounts which may be ultimately due to Moncrief, if any.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota District Court,
Northwest Judicial District, against Williston Basin and the company.
Apache and Snyder are oil and natural gas producers who 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. Williston Basin, the company and Koch have settled their
disputes. Apache and Snyder have recently provided alleged damages
under differing theories ranging up to $8.2 million without interest.
A motion to intervene in the case by several other producers, all of
whom had contracts with Koch but not with Williston Basin, was denied
on December 13, 1996. Trial on this matter is scheduled for
September 8, 1997.
The claims of Apache and Snyder, in Williston Basin's opinion, are
without merit and overstated. If any amounts are ultimately found to
be due Apache and Snyder, Williston Basin plans to file for recovery
from ratepayers.
On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in United
States District Court for the District of Columbia against Williston
Basin and over 70 other natural gas pipeline companies. Grynberg,
acting on behalf of the United States under the False Claims Act, is
alleging improper measurement of the heating content or volume of
natural gas purchased by the defendants resulting in the underpayment
of royalties to the United States. The United States government,
particularly officials from the Departments of Justice and Interior,
reviewed the complaint and the evidence presented by Grynberg and
declined to intervene in the action, permitting Grynberg to proceed on
his own. Williston Basin believes Grynberg's claims are without merit
and intends to vigorously contest this suit.
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 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 as 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 are seeking damages in an unspecified amount.
On January 8, 1996, the company and Knife River filed separate motions
with the State District Court to dismiss or stay pending arbitration.
On May 6, 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.
On September 12, 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. In the alternative, the Co-owners 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, 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. 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. 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 United States 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 United States 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
payment of punitive damages. Hawaiian Cement is a Hawaiian general
partnership whose general partners (with joint and several liability)
are Knife River Hawaii, Inc., an indirect wholly owned subsidiary of
the company, and Adelaide Brighton Cement (Hawaii), Inc. Unitek is
seeking civil penalties under the Clean Air Act (as described below),
and had sought damages for various claims (as described above) of up
to $20 million in the aggregate.
On August 7, 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.
On September 16, 1996, Unitek and Hawaiian Cement reached a settlement
which resolved all claims relating to the $20 million in damages that
Unitek had previously sought. However, the settlement did not resolve
the matter regarding the civil penalties sought by Unitek relating to
the alleged violations by Hawaiian Cement of the Clean Air Act nor did
it affect the EPA's Notice of Violation (NOV) as discussed below.
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 continue to negotiate the remaining Clean Air Act
claims.
On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The NOV
states 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. It is also possible that the EPA could elect to
join the suit filed by Unitek. Depending upon the specific actions
that may ultimately be taken by either the EPA or the District Court,
Hawaiian Cement is likely to have to modify its operations at its
cement manufacturing facility. Hawaiian Cement has met with the EPA
and settlement discussions are currently ongoing.
Although no assurance can be provided, the company does not believe
that the total cost of any modifications to the facility, the level of
civil penalties which may ultimately be assessed or settlement costs,
will 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, up
to 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 $42.3 million at December 31,
1996, $42.1 million at December 31, 1995, and $45.2 million at
December 31, 1994. In addition, $7.2 million, $6.6 million and $6.9
million at December 31, 1996, 1995 and 1994, 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:
1996 1995 1994
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ 4,960 $ 15,275 $ 24,069
Long-term debt refinancing costs 13,520 11,082 12,228
Postretirement benefit costs 3,849 4,833 4,551
Plant costs 3,341 3,509 3,678
Other 7,890 7,091 4,664
Total regulatory assets 33,560 41,790 49,190
Regulatory liabilities:
Reserves for regulatory matters 59,277 58,277 49,427
Natural gas costs refundable
through rate adjustments 1,499 21,192 14,878
Taxes refundable to customers 12,868 12,531 12,229
Plant decommissioning costs 5,301 4,777 4,290
Other 2,433 7,205 9,883
Total regulatory liabilities 81,378 103,982 90,707
Net regulatory position $(47,818) $(62,192) $(41,517)
As of December 31, 1996, 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 20 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
a 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 for
1996, 1995 and 1994:
1996 1995 1994
(Notional amounts in thousands)
Oil swap/collar agreements:*
Range of fixed prices per barrel $18.74-$19.07 $17.75-$20.75 $17.00-$21.05
Notional amount (in barrels) 635 260 242
Natural gas swap/collar agreements:*
Range of fixed prices per MMBtu $1.40-$2.05 $1.70-$1.85 $1.85-$2.32
Notional amount (in MMBtu's) 5,331 644 3,130
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% 5.97% ---
Notional amount (in dollars) $30,000 $20,000 ---
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The following table summarizes swap agreements outstanding at
December 31, 1996 (notional amounts in thousands):
Range of Notional
Fixed Prices Amount
Year (Per barrel) (In barrels)
Oil swap agreements* 1997 $19.77-$21.36 730
Range of Notional
Fixed Prices Amount
Year (Per MMBtu) (In MMBtu's)
Natural gas swap agreements* 1997 $1.30-$2.25 7,737
Notional
Range of Fixed Amount
Year Interest Rates (In dollars)
Interest rate swap agreements:** 1997 5.50%-6.50% $30,000
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 unfavorable position on
all swap and collar agreements outstanding at December 31, 1996, was
$4.2 million.
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:
1996 1995 1994
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
(In thousands)
Long-term
debt $292,420 $298,592 $254,339 $ 274,320 $ 238,043 $ 233,196
Preferred
stocks $ 16,900 $ 10,762 $ 17,000 $ 10,500 $ 17,100 $ 10,486
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 lines of credit from
several banks totalling $91.4 million at December 31, 1996. 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 $4.0 million at December 31, 1996,
$600,000 at December 31, 1995, and $680,000 at December 31, 1994. The
weighted average interest rate for borrowings outstanding at
December 31, 1996, 1995 and 1994, was 7.25 percent, 8.50 percent and
8.50 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
At the Annual Meeting of Stockholders held in April 1994, the
company's common stockholders approved an amendment to the Certificate
of Incorporation increasing the authorized number of common shares
from 50 million shares to 75 million shares and reducing the par value
of the common stock from $5.00 per share to $3.33 per share.
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. Common stock information appearing in the
accompanying consolidated financial statements and notes thereto has
been restated to give retroactive effect to the stock split, except
for shares outstanding in 1994 as set forth in the table below.
Changes in common stock and other paid in capital during the years
ended December 31, 1996, 1995 and 1994 are summarized below:
Shares Par Other Paid
Outstanding Value In Capital
(In thousands)
Balance at December 31, 1994 18,984,654 $63,219 $ 95,914
Three-for-two common stock split 9,492,327 31,609 (31,609)
Balance at December 31, 1995 and
1996 28,476,981 $94,828 $ 64,305
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. Shares held in the K-Plans
also participate in the DRIP. Since January 1, 1989, the DRIP and K-
Plans have been funded by the purchase of shares of common stock on
the open market. However, beginning January 1, 1997, shares of
authorized but unissued common stock are being used to fund the DRIP.
At December 31, 1996, there were 5,830,345 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
Retained Earnings
Changes in retained earnings for the years ended December 31, 1996,
1995 and 1994 are as follows:
1996 1995 1994
(In thousands)
Balance at beginning of year $178,184 $168,050 $158,998
Net income 45,470 41,633 39,845
223,654 209,683 198,843
Deduct:
Dividends declared --
Preferred stocks at required
annual rates 787 792 797
Common stock 31,326 30,707 29,996
32,113 31,499 30,793
Balance at end of year $191,541 $178,184 $168,050
NOTE 11
Preferred Stocks
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 stock:
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, 1996, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1996 1995 1994
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 25,000 $ 50,000 $ 50,000
9 1/8% Series, due October 1, 2016 20,000 20,000 20,000
Pollution Control Refunding Revenue
Bonds, Series 1992:
Mercer County, North Dakota,
6.65%, due June 1, 2022 15,000 15,000 15,000
Morton County, North Dakota,
6.65%, due June 1, 2022 2,600 2,600 2,600
Richland County, Montana,
6.65%, due June 1, 2022 3,250 3,250 3,250
Secured Medium-Term Notes,
Series A:
6.30%, due April 1, 1995 --- --- 10,000
6.95%, due April 1, 1996 --- 10,000 10,000
7.20%, due April 1, 1997 5,000 5,000 5,000
8.25%, due April 1, 2007 30,000 30,000 30,000
8.60%, due April 1, 2012 35,000 35,000 35,000
Total first mortgage bonds
and notes 135,850 170,850 180,850
Pollution control lease and
note obligation, 6.20%, due
March 1, 2004 4,000 4,300 4,600
Senior notes:
7.35%, due July 31, 2002 5,000 5,000 ---
8.43%, due December 31, 2000 15,000 15,000 15,000
7.51%, expires October 9, 2003 3,000 --- ---
7.45%, due May 31, 2006 20,000 --- ---
7.60%, due November 3, 2008 15,000 --- ---
Revolving lines of credit:
8.25%, expires December 31, 1998 30,000 21,500 17,000
Other revolving lines of credit at
rates ranging from 6.03% to 8.50%,
expiring at various dates ranging
from October 6, 2001, through
April 30, 2002 61,800 27,000 3,000
Term credit facilities:
5.95%, due March 31, 1997 --- 7,500 17,500
7.70%, due December 1, 2003 1,556 1,800 ---
Other term credit facilities at
rates ranging from 8.00% to 9.00%,
due from June 30, 1999, through
December 1, 2000 1,308 1,527 250
Other (94) (138) (157)
Total long-term debt 292,420 254,339 238,043
Less current maturities and sinking
fund requirements 11,754 16,987 20,350
Net long-term debt $280,666 $237,352 $217,693
Under the revolving lines of credit, the company has $120 million
available, $91.8 million of which was outstanding at December 31,
1996. The amounts of scheduled long-term debt maturities and sinking
fund requirements for the five years following December 31, 1996,
aggregate $11.8 million in 1997; $44.5 million in 1998; $15.1 million
in 1999; $18.4 million in 2000 and $10.9 million in 2001.
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
$247 million of additional first mortgage bonds at December 31, 1996.
Certain of the company's other debt instruments contain restrictive
covenants all of which the company is in compliance with at December
31, 1996.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1996 1995 1994
(In thousands)
Current:
Federal $12,617 $20,259 $11,995
State 3,272 3,801 2,644
Foreign 60 369 210
15,949 24,429 14,849
Deferred:
Investment tax credit -- net (1,099) (1,028) (1,137)
Income taxes --
Federal 1,139 (564) 4,589
State 120 220 532
Foreign (22) --- ---
138 (1,372) 3,984
Total income tax expense $16,087 $23,057 $18,833
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1996 1995 1994
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 38,404 $ 36,894 $ 33,076
Natural gas available under
repurchase commitment 10,521 6,762 6,778
Accrued pension costs 7,814 7,039 5,646
Deferred investment tax credits 3,160 3,623 4,022
Accrued land reclamation 3,604 4,033 4,256
Natural gas costs refundable
through rate adjustments --- 6,125 4,034
Other 13,499 11,321 10,220
Total deferred tax assets 77,002 75,797 68,032
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 121,763 119,078 115,966
Basis differences on oil and
natural gas producing properties 30,361 28,113 21,049
Natural gas contract settlement and
restructuring costs 1,926 5,413 9,327
Long-term debt refinancing costs 4,688 4,524 4,745
Other 8,461 5,465 4,592
Total deferred tax liabilities 167,199 162,593 155,679
Net deferred income tax liability $(90,197) $(86,796) $(87,647)
The following table reconciles the change in the net deferred income
tax liability to the deferred income tax expense included in the
Consolidated Statements of Income:
1996 1995
(In thousands)
Net change in deferred income tax liability
from the preceding table $ 3,401 $(851)
Change in tax effects of income tax-related
regulatory assets and liabilities 1,155 507
Deferred taxes associated with acquisitions (3,319) ---
Deferred income tax expense for the period $ 1,237 $(344)
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:
1996 1995 1994
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $21,545 35.0 $22,642 35.0 $20,537 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,070) (1.7) (1,346) (2.1) (1,454)(2.5)
State income
taxes -- net of
federal income tax
benefit 2,770 4.5 2,492 3.9 2,337 4.0
Investment tax credit
amortization (1,099) (1.8) (1,028) (1.6) (1,137)(1.9)
Tax reserve adjustment (6,600)(10.7) --- --- --- ---
Other items 541 .8 297 .4 (1,450)(2.5)
Actual taxes $16,087 26.1 $23,057 35.6 $18,833 32.1
The company's consolidated federal income tax returns were under
examination by the Internal Revenue Service (IRS) for the tax years
1983 through 1991. In 1991, the company received a notice of proposed
deficiency from the IRS for the tax years 1983 through 1985 which
proposed substantial additional income taxes, plus interest. In an
alternative position contained in the notice of proposed deficiency,
the IRS had claimed a lower level of taxes due, plus interest as well
as penalties. In 1992 and 1995, similar notices of proposed
deficiency were received for the years 1986 through 1988 and 1989
through 1991, respectively. Although the notices of proposed
deficiency encompass a number of separate issues, the principal issue
was related to the tax treatment of deductions claimed in connection
with certain investments made by Knife River and Fidelity Oil.
The company timely filed protests for the 1983 through 1991 tax years
contesting the treatment proposed in the notices of proposed
deficiency. In April 1996, the company and the IRS reached a
settlement for the tax years 1983 through 1988, which should also
result in settlement of related issues for the years 1989 through
1991. The company reflected the effect of the settlement in the third
quarter of 1996 and, in addition, reversed reserves previously
provided which were deemed to be no longer required.
NOTE 14
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.
Segment operating information at December 31, 1996, 1995 and 1994, is
presented in the Consolidated Statements of Income. Other segment
information is presented below:
1996 1995 1994
(In thousands)
Depreciation, depletion and
amortization:
Electric $ 17,053 $ 16,361 $ 15,513
Natural gas distribution 6,880 6,719 6,118
Natural gas transmission 6,748 6,940 6,590
Construction materials
and mining 6,974 6,199 6,394
Oil and natural gas production 24,996 18,606 13,498
Total depreciation, depletion
and amortization $ 62,651 $ 54,825 $ 48,113
Investment information:
Identifiable assets--
Electric (a) $ 313,815 $ 312,559 $ 307,861
Natural gas distribution (a) 120,645 126,452 124,275
Natural gas transmission (a) 276,843 303,219 311,992
Construction materials
and mining 171,283 141,505 116,347
Oil and natural gas
production 161,647 133,289 106,631
Total identifiable assets 1,044,233 1,017,024 967,106
Corporate assets (b) 44,940 39,455 37,612
Total consolidated assets $1,089,173 $1,056,479 $1,004,718
(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 4 percent of construction materials and mining revenues
in 1996 (4 percent in 1995 and 6 percent in 1994) represent Knife
River's direct sales of lignite coal to the company. The company's
share of Knife River's 1996 sales for use at the Coyote Station, a
generating station jointly owned by the company and other utilities,
was approximately 5 percent of construction materials and mining
revenues in 1996. In 1995 and 1994, 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 and 8 percent, respectively, 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, 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.
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 15
Employee Benefit Plans
The company has noncontributory defined benefit pension plans covering
substantially all full-time employees. Pension benefits are based 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:
1996 1995 1994
(In thousands)
Service cost/benefits earned during
the year $ 3,852 $ 3,538 $ 4,035
Interest cost on projected benefit
obligation 10,823 10,784 9,912
Loss (return) on plan assets (24,972) (37,185) 3,154
Net amortization and deferral 11,494 24,407 (15,410)
Special termination benefit cost --- 853 ---
Total pension costs 1,197 2,397 1,691
Less amounts capitalized 131 184 198
Total pension expense $ 1,066 $ 2,213 $ 1,493
The funded status of the company's plans at December 31 is summarized
as follows:
1996 1995 1994
(In thousands)
Projected benefit obligation:
Vested $122,119 $121,879 $105,561
Nonvested 3,923 4,731 4,124
Accumulated benefit obligation 126,042 126,610 109,685
Provision for future pay increases 24,787 28,114 25,084
Projected benefit obligation 150,829 154,724 134,769
Plan assets at market value 185,872 170,793 139,332
(35,043) (16,069) (4,563)
Plus:
Unrecognized transition asset 7,336 8,326 9,315
Unrecognized net gains and prior
service costs 35,848 14,686 2,466
Accrued pension costs $ 8,141 $ 6,943 $ 7,218
The projected benefit obligation was determined using an assumed
discount rate of 7.50 percent (7.25 percent in 1995 and 8 percent in
1994) and assumed long-term rates for estimated compensation increases
of 4.50 percent (4.50 percent in 1995 and 5 percent in 1994). The
change in these assumptions had the effect of decreasing the projected
benefit obligation at December 31, 1996, by $5 million but increasing
the projected benefit obligation at December 31, 1995, by $12 million.
The assumed long-term rate of return on plan assets is 8.50 percent.
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
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:
1996 1995 1994
(In thousands)
Service cost/benefits earned during
the year $ 1,333 $1,226 $1,454
Interest cost on accumulated
postretirement benefit obligation 4,701 4,777 4,584
Return on plan assets (2,491) (183) (176)
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral 1,260 (719) 76
Total postretirement benefits cost 7,261 7,559 8,396
Less amounts capitalized 735 442 419
Total postretirement benefits expense $ 6,526 $7,117 $7,977
The funded status of the company's plans at December 31 is summarized
as follows:
1996 1995 1994
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $40,775 $43,543 $36,985
Active employees fully eligible for
benefits --- 66 22
Active employees not fully eligible 24,833 26,229 22,898
Total 65,608 69,838 59,905
Plan assets at market value 21,712 15,095 9,938
43,896 54,743 49,967
Less:
Unrecognized transition obligation 39,322 41,779 44,237
Unrecognized net losses 3,693 12,066 4,896
Accrued postretirement benefits cost $ 881 $ 898 $ 834
The health plan cost trend rate assumed in determining the accumulated
postretirement benefit obligation at December 31, 1996, was 9 percent
decreasing by 1 percent per year until an ultimate rate of 6 percent
is reached in 1999 and remaining level thereafter. 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, 1996, by $3.1
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $233,000.
The accumulated postretirement benefit obligation was determined using
an assumed discount rate of 7.50 percent at December 31, 1996, 7.25
percent at December 31, 1995, and 8 percent at December 31, 1994, and
assumed long-term rates for estimated compensation increases, as they
apply to life insurance benefits, of 4.50 percent at December 31, 1996
and 1995, and 5 percent at December 31, 1994. The change in these
assumptions had the effect of decreasing the accumulated
postretirement benefit obligation at December 31, 1996, by $2 million
but increasing the accumulated postretirement benefit obligation at
December 31, 1995, by $7 million. The assumed long-term rate of
return on assets is 7.50 percent. 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 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 1996, $1.9 million in 1995 and $1.7 million in 1994.
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. The company is
authorized to grant options for up to 1.2 million shares of common
stock and has granted options on 484,540 shares through December 31,
1996. Under the KESOP the option price equals the stock's market
value 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 change in control and
expire 10 years after the date of grant. The company has contributed
$5.7 million to a trust established to fund its commitment under the
KESOP.
Pro forma net income and earnings per common share calculated using
the provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation" have not been presented because such amounts are not
materially different than actual amounts reported.
A summary of the status of the KESOP at December 31, 1996, 1995 and
1994, and changes during the years then ended are as follows:
1996 1995 1994
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at 468,737 $17.48 192,284 $15.82 265,964 $15.82
beginning
of year
Granted --- --- 294,956 18.50 --- ---
Forfeited --- --- (2,700) 20.83 (73,680) 15.80
Exercised (44,760) 15.75 (15,803) 15.75 --- ---
Balance at end
of year 423,977 17.66 468,737 17.48 192,284 15.82
Exercisable at
end of year 93,764 $15.75 138,524 $15.75 --- ---
Exercise prices on options outstanding at December 31, 1996, range
from $15.75 to $18.50 with a weighted average remaining contractual
life of approximately 7 years.
The weighted average fair value of each option granted in 1995 is
$2.67. 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 1995 were a
risk-free interest rate of 7.80 percent, an expected dividend yield of
5.80 percent, an expected life of 10 years and expected volatility of
15.80 percent.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. 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 $1.9 million in 1996, 1995
and 1994.
NOTE 16
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.
Hawaiian Cement 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. Hawaiian Cement, headquartered in
Honolulu, Hawaii, is a partnership which is also 50 percent owned by
Adelaide Brighton Ltd. of Adelaide, Australia.
The company's net investment in Hawaiian Cement is included in
"Investments" in the accompanying Consolidated Balance Sheets at
December 31, 1996 and 1995, while its share of operating results is
included in "Other income -- net" in the accompanying Consolidated
Statements of Income for the years ended December 31, 1996 and 1995.
Summarized financial information for Hawaiian Cement, which is not
consolidated and is accounted for by the equity method, as of and for
the year ended December 31, 1996, and as of and for the four months
ended December 31, 1995, as applicable, is as follows:
1996 1995
(In thousands)
Current assets $17,316 $19,531
Property, plant and equipment, net 52,316 70,544
Current liabilities 10,128 14,209
Other liabilities 14,954 15,736
Net sales 70,059 24,433
Operating margin 9,900 5,096
Income before income taxes 5,373 2,757
The company's investment in Hawaiian Cement exceeds the underlying net
assets by $13.2 million. The excess is being amortized over 30 years.
NOTE 17
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 providing its own financing of 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:
1996 1995 1994
(In thousands)
Big Stone Station:
Utility plant in service $ 48,907 $ 47,687 $ 46,923
Accumulated depreciation 26,676 27,026 25,505
$ 22,231 $ 20,661 $ 21,418
Coyote Station:
Utility plant in service $122,320 $122,126 $ 121,784
Accumulated depreciation 52,721 49,296 45,546
$ 69,599 $ 72,830 $ 76,238
NOTE 18
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1996 and 1995:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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 .45 .30 .29 .53
Average common shares
outstanding 28,477 28,477 28,477 28,477
1995
Operating revenues $116,518 $111,267 $113,945 $122,516
Operating expenses 94,047 91,690 91,606 96,327
Operating income 22,471 19,577 22,339 26,189
Net income 10,272 8,662 10,472 12,227
Earnings per common share .35 .30 .36 .42
Average common shares
outstanding 28,477 28,477 28,477 28,477
Some of the company's 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 19
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.
In 1994, Williston Basin undertook a drilling program designed to
increase production and to gain updated data from which to assess the
future production capabilities of natural gas reserves held primarily
in Montana. In late 1994, upon analysis of the results of this
program, it was determined that the future production related to these
properties can be accelerated and, as a result, the economic value of
these reserves has become material to the company's consolidated oil
and natural gas production operations. Therefore, beginning in 1994,
the tables set forth below include information related to Williston
Basin's natural gas production activities.
The following information includes the company's proportionate share
of all its oil and natural gas interests.
The following table sets forth capitalized costs and related
accumulated depreciation, depletion and amortization related to oil
and natural gas producing activities at December 31:
1996 1995 1994
(In thousands)
Subject to amortization $223,409 $173,501 $155,303
Not subject to amortization 6,792 8,831 8,530
Total capitalized costs 230,201 182,332 163,833
Accumulated depreciation, depletion
and amortization 71,554 49,498 54,376
Net capitalized costs $158,647 $132,834 $109,457
Net capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities for the 12 months
ended December 31 are as follows:
1996 1995 1994
(In thousands)
Acquisitions $23,284 $ 9,159 $ 3,182
Exploration 8,101 7,678 12,656
Development 19,979 24,955 20,247
Net capital expenditures $51,364 $41,792 $36,085
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs, for the 12 months ended
December 31:
1996 1995 1994
(In thousands)
Revenues* $75,335 $53,484 $45,053
Production costs 21,296 16,888 18,463
Depreciation, depletion and
amortization 25,629 19,058 13,926
Pretax income 28,410 17,538 12,664
Income tax expense 10,875 6,397 4,257
Results of operations for
producing activities $17,535 $11,141 $ 8,407
* Includes $7.0 million, $4.7 million and $7.1 million of revenues for
1996, 1995 and 1994, respectively, related to Williston Basin's
natural gas production activities which are included in "Natural
gas" operating revenues on the Consolidated Statements of Income.
The following table summarizes the company's estimated quantities of
proved developed oil and natural gas reserves at December 31, 1996,
1995 and 1994, 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.
1996 1995 1994
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 14,200 179,000 12,500 154,200 11,200 50,300
Production (2,100) (20,400) (2,000) (17,500) (1,600) (9,200)
Extensions and
discoveries 600 27,000 1,800 23,800 1,300 17,800
Purchases of proved
reserves 2,900 9,900 1,100 6,700 600 2,900
Sales of reserves
in place (700) (3,700) (300) (200) (400) (2,700)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 1,200 8,400 1,100 12,000 1,400 95,100*
Balance at end of year 16,100 200,200 14,200 179,000 12,500 154,200
*Includes 99,300 MMcf of Williston Basin's natural gas reserves.
Proved developed reserves:
January 1, 1994 11,100 43,100
December 31, 1994 12,200 147,200**
December 31, 1995 13,600 156,400
December 31, 1996 15,400 168,200
**Includes 98,700 MMcf of Williston Basin's natural gas reserves.
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, 1996, applicable to the company's
$2.0 million 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:
1996 1995 1994
(In thousands)
Future net cash flows before
income taxes $580,300 $267,300 $197,900
Future income tax expenses 194,200 76,100 48,800
Future net cash flows 386,100 191,200 149,100
10% annual discount for estimated
timing of cash flows 152,100 70,300 54,200
Discounted future net cash flows
relating to proved oil and natural
gas reserves $234,000 $120,900 $ 94,900
The following are the sources of change in the standardized measure of
discounted future net cash flows by year:
1996 1995 1994
(In thousands)
Beginning of year $120,900 $ 94,900 $ 71,600
Net revenues from production (54,000) (36,400) (23,800)
Change in net realization 125,800 26,300 (4,100)
Extensions, discoveries and improved
recovery, net of future
production-related costs 43,500 31,200 31,700
Purchases of proved reserves 49,600 10,900 5,800
Sales of reserves in place (6,700) (1,000) (3,700)
Changes in estimated future
development costs -- net of those
incurred during the year (2,400) (8,900) (2,900)
Accretion of discount 16,900 12,300 8,300
Net change in income taxes (69,200) (17,100) (4,000)
Revisions of previous quantity
estimates 8,700 8,900 16,500*
Other 900 (200) (500)
Net change 113,100 26,000 23,300
End of year $234,000 $120,900 $ 94,900
*Includes $19.1 million related to Williston Basin's natural gas
reserves.
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.<PAGE>
To MDU Resources Group, Inc.
We have audited the accompanying consolidated balance sheets and
statements of capitalization of MDU Resources Group, Inc. (a Delaware
corporation) and Subsidiaries as of December 31, 1996, 1995 and 1994,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1996. 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, 1996, 1995
and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Minneapolis, Minnesota
January 23, 1997
<PAGE>
1996 1995 1994
Selected Financial Data
Operating revenues: (000's)
Electric $ 138,761 $ 134,609 $ 133,953
Natural gas 175,408 167,787 160,970
Construction materials and mining 132,222 113,066 116,646
Oil and natural gas production 68,310 48,784 37,959
$ 514,701 $ 464,246 $ 449,528
Operating income: (000's)
Electric $ 29,476 $ 29,898 $ 27,596
Natural gas distribution 11,504 6,917 3,948
Natural gas transmission 30,231 25,427 21,281
Construction materials and mining 16,062 14,463 16,593
Oil and natural gas production 24,252 13,871 8,757
$ 111,525 $ 90,576 $ 78,175
Earnings on common stock: (000's)
Electric $ 11,436 $ 12,000 $ 11,719
Natural gas distribution 4,892 1,604 285
Natural gas transmission 2,459 8,416 6,155
Construction materials and mining 11,521 10,819 11,622
Oil and natural gas production 14,375 8,002 9,267
Earnings on common stock
before cumulative effect of
accounting change 44,683 40,841 39,048
Cumulative effect of
accounting change --- --- ---
$ 44,683 $ 40,841 $ 39,048
Earnings per common share before
cumulative effect of
accounting change $ 1.57 $ 1.43 $ 1.37
Cumulative effect of accounting
change --- --- ---
$ 1.57 $ 1.43 $ 1.37
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 45,470 $ 41,633 $ 39,845
Earnings per common share $ 1.57 $ 1.43 $ 1.37
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533
Book value per common share $ 12.31 $ 11.85 $ 11.49
Market price per common share
(year-end) $ 23.00 $ 19.88 $ 18.08
Market price ratios:
Dividend payout 70% 76% 77%
Yield 4.8% 5.5% 5.9%
Price/earnings ratio 14.6x 13.9x 13.2x
Market value as a percent of
book value 186.8% 167.7% 157.4%
Profitability Indicators
Return on average common equity 13.0% 12.3% 12.1%
Return on average invested capital 9.5% 9.2% 9.1%
Interest coverage 5.4x 3.9x 3.3x
Fixed charges coverage, including
preferred dividends 2.7x 3.0x 2.9x
General
Total assets (000's) $1,089,173 $1,056,479 $1,004,718
Net long-term debt (000's) $ 280,666 $ 237,352 $ 217,693
Redeemable preferred stock (000's) $ 1,900 $ 2,000 $ 2,100
Capitalization ratios:
Common stockholders' investment 54% 57% 58%
Preferred stocks 3 3 3
Long-term debt 43 40 39
100% 100% 100%
<PAGE>
1993 1992 1991
Selected Financial Data
Operating revenues: (000's)
Electric $ 131,109 $ 123,908 $128,708
Natural gas 178,981 159,438 173,865
Construction materials and mining 90,397 45,032 41,201
Oil and natural gas production 39,125 33,797 33,939
$ 439,612 $ 362,175 $377,713
Operating income: (000's)
Electric $ 30,520 $ 30,188 $ 34,647
Natural gas distribution 4,730 4,509 8,518
Natural gas transmission 20,108 21,331 19,904
Construction materials and mining 16,984 11,532 9,682
Oil and natural gas production 11,750 9,499 12,552
$ 84,092 $ 77,059 $ 85,303
Earnings on common stock: (000's)
Electric $ 12,652* $ 13,302 $ 15,292
Natural gas distribution 1,182* 1,370 3,645
Natural gas transmission 4,713 3,479 449
Construction materials and mining 12,359 10,662 9,809
Oil and natural gas production 7,109 5,751 8,010
Earnings on common stock
before cumulative effect of
accounting change 38,015* 34,564 37,205
Cumulative effect of
accounting change 5,521 --- ---
$ 43,536 $ 34,564 $ 37,205
Earnings per common share before
cumulative effect of
accounting change $ 1.34* $ 1.21 $ 1.31
Cumulative effect of accounting
change .19 --- ---
$ 1.53 $ 1.21 $ 1.31
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 38,817 $ 35,852 $ 37,619
Earnings per common share $ 1.34 $ 1.23 $ 1.29
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.0133 $ .9733 $ .9567
Book value per common share $ 11.17 $ 10.66 $ 10.42
Market price per common share
(year-end) $ 21.00 $ 17.58 $ 16.42
Market price ratios:
Dividend payout 76%* 80% 73%
Yield 5.0% 5.6% 5.8%
Price/earnings ratio 15.8x* 14.5x 12.6x
Market value as a percent of
book value 188.0% 165.0% 157.7%
Profitability Indicators
Return on average common equity 12.3%* 11.6% 12.7%
Return on average invested capital 9.4%* 8.7% 9.6%
Interest coverage 3.4x* 3.3x 3.8x**
Fixed charges coverage, including
preferred dividends 3.0x* 2.4x 2.4x
General
Total assets (000's) $1,041,051 $1,024,510 $964,691
Net long-term debt (000's) $ 231,770 $ 249,845 $220,623
Redeemable preferred stock (000's) $ 2,200 $ 2,300 $ 2,400
Capitalization ratios:
Common stockholders' investment 56% 53% 56%
Preferred stocks 3 3 3
Long-term debt 41 44 41
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the
accrual of estimated unbilled revenues.
** Calculation reflects the provisions of the company's restatement of
its Indenture of Mortgage effective April 1992.<PAGE>
1996 1995 1994
Electric Operations
Sales to ultimate consumers
(thousand kWh) 2,067,926 1,993,693 1,955,136
Sales for resale (thousand kWh) 374,535 408,011 444,492
Electric system generating and
firm purchase capability--kW
(Interconnected system) 481,800 472,400 470,900
Demand peak--kW
(Interconnected system) 393,300 412,700 369,800
Electricity produced
(thousand kWh) 1,829,669 1,718,077 1,901,119
Electricity purchased
(thousand kWh) 809,261 867,524 700,912
Cost of fuel and purchased
power per kWh $.017 $.016 $.017
Natural Gas Distribution Operations
Sales (Mdk) 38,283 33,939 31,840
Transportation (Mdk) 9,423 11,091 9,278
Weighted average degree days--% of
previous year's actual 114% 105% 92%
Natural Gas Transmission Operations
Sales for resale (Mdk) --- --- ---
Transportation (Mdk) 82,169 68,015 63,870
Produced (Mdk) 6,073 4,981 4,732
Net recoverable reserves (MMcf) 133,400 113,000 99,300
Energy Marketing Operations
Natural gas volumes (Mdk) 4,670 3,556 7,301
Propane (thousand gallons) 9,689 7,471 6,462
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 3,374 2,904 2,688
Asphalt (tons sold) 694 373 391
Ready-mixed concrete (cubic
yards sold) 340 307 315
Recoverable aggregate reserves
(tons) 119,800 68,000 71,000
Coal: (000's)
Sales (tons) 2,899 4,218 5,206
Recoverable reserves (tons) 228,900 231,900 236,100
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 2,149 1,973 1,565
Natural gas (MMcf) 14,067 12,319 9,228
Average sales prices:
Oil (per barrel) $17.91 $15.07 $13.14
Natural gas (per Mcf) $ 2.09 $ 1.51 $ 1.84
Net recoverable reserves:
Oil (000's of barrels) 16,100 14,200 12,500
Natural gas (MMcf) 66,800 66,000 54,900
<PAGE>
1993 1992 1991
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,893,713 1,829,933 1,877,634
Sales for resale (thousand kWh) 510,987 352,550 331,314
Electric system generating and
firm purchase capability--kW
(Interconnected system) 465,200 460,200 454,400
Demand peak--kW
(Interconnected system) 350,300 339,100 387,100
Electricity produced
(thousand kWh) 1,870,740 1,774,322 1,736,187
Electricity purchased
(thousand kWh) 701,736 593,612 611,884
Cost of fuel and purchased
power per kWh $.016 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 31,147 26,681 30,074
Transportation (Mdk) 12,704 13,742 12,261
Weighted average degree days--% of
previous year's actual 115% 98% 101%
Natural Gas Transmission Operations
Sales for resale (Mdk) 13,201 16,841 19,572
Transportation (Mdk) 59,416 64,498 53,930
Produced (Mdk) 3,876 3,551 3,742
Net recoverable reserves (MMcf) --- --- ---
Energy Marketing Operations
Natural gas volumes (Mdk) 6,827 3,292 991
Propane (thousand gallons) 2,210 --- ---
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,391 263 ---
Asphalt (tons sold) 141 --- ---
Ready-mixed concrete (cubic
yards sold) 157 --- ---
Recoverable aggregate reserves
(tons) 74,200 20,600 ---
Coal: (000's)
Sales (tons) 5,066 4,913 4,731
Recoverable reserves (tons) 230,600 235,700 256,700
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,497 1,531 1,491
Natural gas (MMcf) 8,817 5,024 2,565
Average sales prices:
Oil (per barrel) $14.84 $16.74 $19.90
Natural gas (per Mcf) $ 1.86 $ 1.53 $ 1.48
Net recoverable reserves:
Oil (000's of barrels) 11,200 12,200 11,600
Natural gas (MMcf) 50,300 37,200 27,500
<PAGE>
SUBSIDIARIES OF MDU RESOURCES GROUP, INC.
December 31, 1996
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
Customer One, Inc. Delaware
Fidelity Oil Co. Delaware
Fidelity Oil Holdings, Inc. Delaware
KRC Aggregate, Inc. Delaware
KRC Holdings, Inc. Delaware
Knife River Corporation Minnesota
Knife River Hawaii, Inc. Delaware
Knife River Marine, Inc. Delaware
LTM, Incorporated Oregon
Medford Ready Mix, Inc. Delaware
Prairie Propane, Inc. Delaware
Prairielands Energy Marketing, Inc. Delaware
Rogue Aggregates, Inc. Oregon
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 23, 1997, included in the MDU Resources Group, Inc.
Annual Report to Stockholders for 1996. 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, No. 33-66682 and
No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896,
No. 33-53898, No. 333-06103 and No. 33-06105.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
February 28, 1997
CONSENT OF ENGINEER
We hereby consent to the reference to our reports dated
January 9 and 31, 1997, 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, No. 33-66682,
and No. 333-06127 and on Form S-8, No. 33-54486, No. 33-53896,
No. 33-53898, No. 333-06103 and No. 333-06105 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
February 28, 1997
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, No. 33-66682
and No. 333-06127, and on Form S-8, No. 33-54486, No. 33-53896,
No. 33-53898, No. 333-06103, and No. 333-06105 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
February 28, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED
STATEMENTS OF CASH FLOW AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000067716
<NAME> MDU RESOURCES GROUP, INC.
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