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, 1995
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. __
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 23, 1996: $587,338,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 23, 1996: 28,476,981 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 23 through 49 of the Annual Report to Stockholders for 1995,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 4, 1996, 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
Coal Operations
Construction Materials 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
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 Coal Mining Company
(Knife River), the Fidelity Oil Group (Fidelity Oil) and
Prairielands Energy Marketing, Inc. (Prairielands).
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.
Knife River surface mines and markets low sulfur lignite
coal at mines located in Montana and North Dakota and,
through its wholly owned subsidiary, KRC Holdings, Inc.
(KRC Holdings), surface mines and markets aggregates and
related construction materials in the Anchorage, Alaska
area, southern Oregon, north-central California and the
Hawaiian Islands.
Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity
Oil Holdings, Inc., which own oil and natural gas interests
in the western United States, the Gulf Coast and Canada
through investments with several oil and natural gas
producers.
Prairielands seeks new energy markets while continuing to
expand present markets for natural gas. Its activities
include buying and selling natural gas and arranging
transportation services to end users, pipelines and local
distribution companies and, through its wholly owned
subsidiary, Prairie Propane, Inc., operating bulk propane
facilities in north-central and southeastern North Dakota.
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, 1995, the Company had 1,864 full-time
employees with 95 employed at MDU Resources Group, Inc., including
Fidelity Oil and Prairielands, 1,090 at Montana-Dakota, 277 at
Williston Basin, 158 at Knife River's coal operations and 244 at
Knife River's construction materials operations. Approximately 523
and 87 of the Montana-Dakota and Williston Basin employees,
respectively, are represented by the International Brotherhood of
Electrical Workers. Labor contracts with such employees are in
effect through December 1996, for both Montana-Dakota and Williston
Basin. Knife River's coal operations have a labor contract through
August 1998, with the United Mine Workers of America, which
represents its hourly workforce approximating 106 employees. Knife
River's construction materials operations have 8 labor contracts
covering 100 employees. These contracts have expiration dates
ranging from May 1996, to December 1998.
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 1995 (Annual
Report), which are incorporated by reference herein.
ENERGY DISTRIBUTION OPERATIONS AND PROPERTY (MONTANA-DAKOTA)
Electric Generation, Transmission and Distribution
General --
Montana-Dakota provides electric service at retail, serving
over 112,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as of
December 31, 1995. 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 miles
and 3,900 miles of transmission lines 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, 1995, Montana-Dakota's
net electric plant investment approximated $280.7 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 public service commissions of North Dakota,
Montana, South Dakota and Wyoming. The percentage of
Montana-Dakota's 1995 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 411,013 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 plants (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) (61,400 kW in 1995) for its
interconnected system. The following table sets forth details
applicable to the Company's electric generating stations:
Nameplate Summer 1995 Net
Generating Rating Capability Generation
Station Type (kW) (kW) (MWh)
North Dakota --
Coyote* Steam 103,647 106,750 699,032
Heskett Steam 86,000 99,800 227,472
Williston Combustion
Turbine 7,800 8,900 (66)**
South Dakota --
Big Stone* Steam 94,111 98,763 548,351
Montana --
Lewis & Clark Steam 44,000 43,800 224,181
Glendive Combustion
Turbine 34,780 31,600 12,130
Miles City Combustion
Turbine 23,150 21,400 6,977
393,488 411,013 1,718,077
*Reflects Montana-Dakota's ownership interest.
**Station use exceeded generation.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. See "Construction
Materials and Mining Operations and Property (Knife River) -- Coal
Operations" for a discussion of a suit 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, 1991, through December 31,
1995, 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,
1995 1994 1993 1992 1991
Average cost of
coal per
million Btu $.94 $.97 $.96 $.97 $.99
Average cost of
coal per ton $12.90 $12.88 $12.78 $12.79 $13.06
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. 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 2000 will approximate .6 percent annually.
Kilowatt-hour (kWh) sales have increased approximately 1.7 percent
annually during the most recent five years. Montana-Dakota's
latest forecast indicates that its sales growth rate through 2000
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 2005.
Montana-Dakota has major interconnections with its neighboring
utilities, all of whom are Mid-Continent Area Power Pool (MAPP)
members, which it considers 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 1998.
The Sheridan System is supplied through an interconnection with
Pacific Power & Light Company under a supply contract through
December 31, 1996. In September 1994, Montana-Dakota entered into
a ten-year power supply contract with Black Hills Corporation,
which operates its electric utility as Black Hills Power and Light
Company (BHPL). Beginning January 1, 1997, BHPL will supply the
electric power and energy for Montana-Dakota's electric service
requirements for its Sheridan System. The contract is subject to
approval of the FERC.
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 increasing level of
competition is being fostered, in part, by the enactment in 1992 of
the National Energy Policy Act (NEPA). NEPA encourages competition
by allowing both utilities and non-utilities to form 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 March 29, 1995, the FERC issued a Notice of Proposed
Rulemaking (NOPR) on Open Access Non-Discriminatory Transmission
Services by Public Utilities and Transmitting Utilities (FERC
Docket No. RM95-8-000) and a supplemental NOPR on Recovery of
Stranded Costs (FERC Docket No. RM94-7-001).
The proposed rules are intended to facilitate competition among
generators for sales to the bulk power supply market. If adopted,
the NOPR would require public utilities under the Federal Power Act
to file a generic set of transmission tariff terms and conditions
as set forth in the rulemaking to provide open access to their
transmission systems. Previously, the FERC had not imposed on
utilities a general obligation to provide access to their
transmission systems. In addition, each public utility would also
be required to establish separate rates for its transmission and
generation services for new wholesale service, and to take
transmission services (including ancillary services) under the same
tariffs that would be applicable to third-party users for all of
its new wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public utilities of legitimate and verifiable
stranded costs associated with exiting wholesale requirements
customers and retail customers who become unbundled wholesale
transmission customers of the utility. The FERC would provide
public utilities with a mechanism for recovery of stranded costs
that result from municipalization, former retail customers becoming
wholesale customers, or the loss of a wholesale customer. The FERC
would consider allowing recovery of stranded investment costs
associated with retail wheeling only if a state regulatory
commission lacks the authority to consider that issue.
It is anticipated that a final rule will be issued in the
first half of 1996. In connection with the FERC's NOPR, the MAPP
is currently preparing a filing to provide for open access
transmission on its members' systems on a non-discriminatory basis.
It is expected that such filing will be submitted to the FERC in
1996. Although no assurances can be provided as to the competitive
effects resulting from open access, Montana-Dakota does not believe
it will materially impact its operations.
Many state public utility commissions, including Montana, are
currently studying the issue of retail wheeling. Additionally,
federal legislation addressing this issue has been introduced.
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
1995 actual and 1996 through 1998 anticipated construction
expenditures applicable to Montana-Dakota's electric operations:
Actual Estimated
1995 1996 1997 1998
Production $ 5.7 $ 5.4 $ 5.1 $ 7.3
Transmission 2.0 3.0 3.2 2.9
Distribution, General
and Common 12.0 9.9 8.5 7.5
$19.7 $18.3 $16.8 $17.7
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 Clean Air Act (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 Act will limit the amount of nitrous oxide
emissions, although the rules as they relate to the majority of
Montana-Dakota's generating stations have not yet been finalized by
the United States Environmental Protection Agency (EPA).
Accordingly, Montana-Dakota is unable to determine what
modifications may be necessary or the costs associated with any
changes which may be required.
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 1995 and does not expect to incur any
significant capital expenditures related to environmental facilities
during 1996 through 1998.
Retail Natural Gas and Propane Distribution
General --
Montana-Dakota sells natural gas at retail, serving over 195,000
residential, commercial and industrial customers located in 140
communities and adjacent rural areas as of December 31, 1995, and
provides natural gas transportation services to certain customers
on its system. These services are provided through a natural gas
distribution system aggregating over 4,000 miles. In addition,
Montana-Dakota sells propane at retail, serving over 600 residential
and commercial customers in two small communities through propane
distribution systems aggregating 13 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, 1995, Montana-Dakota's net gas and propane
distribution plant investment approximated $80.0 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 public service
commissions of North Dakota, Montana, South Dakota and Wyoming
regarding retail rates, service, accounting and, in certain
instances, security issuances. The percentage of Montana-Dakota's
1995 natural gas and propane utility operating revenues by
jurisdiction is as follows: North Dakota -- 43 percent; Montana --
30 percent; South Dakota -- 20 percent and Wyoming -- 7 percent.
System Supply, System Demand and Competition --
Montana-Dakota serves retail natural gas markets, consisting
principally of residential and firm commercial space and water
heating users, in portions of the following states and major
communities -- North Dakota, including Bismarck, Dickinson,
Williston, Minot and Jamestown; eastern Montana, including Billings,
Glendive and Miles City; western and north-central South Dakota,
including Rapid City, Pierre and Mobridge; and northern Wyoming,
including Sheridan. These markets are highly seasonal and sales
volumes depend on 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,
Retail Natural Gas 1995 1994 1993 1992 1991
and Propane Throughput Mdk (thousands of decatherms)
Sales:
Residential 20,135 19,039 19,565 17,141 18,904
Commercial 13,509 12,403 11,196 9,256 10,865
Industrial 295 398 386 284 305
Total Sales 33,939 31,840 31,147 26,681 30,074
Transportation:
Commercial 1,742 2,011 3,461 3,450 3,582
Industrial 9,349 7,267 9,243 10,292 8,679
Total Transporta-
tion 11,091 9,278 12,704 13,742 12,261
Total Throughput 45,030 41,118 43,851 40,423 42,335
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
varying in length from less than one year to over four years and is
transported under firm transportation agreements by Williston Basin
and Northern Gas Company and, with respect to Montana-Dakota's
system expansion into north-central South Dakota and to south-
central North Dakota, 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
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.
On June 30, 1995, Montana-Dakota filed a general natural gas
rate increase application with the Montana Public Service
Commission (MPSC) requesting increased revenues of approximately
$2.1 million, or 4.4 percent. Hearings were held in January 1996
and Montana-Dakota is awaiting the MPSC's order.
Capital Requirements --
In 1995, Montana-Dakota expended $8.9 million for natural gas
and propane distribution facilities and currently anticipates
expending approximately $7.7 million, $7.8 million and $8.0 million
in 1996, 1997 and 1998, 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 issues 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.
In June 1990, Montana-Dakota was notified by the EPA that it
and several others were named as Potentially Responsible Parties
(PRPs) in connection with the cleanup of pollution at a landfill
site located in Minot, North Dakota. In June 1993, the EPA issued
its decision on the selected remediation to be performed at the
site. Based on the EPA's proposed remediation plan, estimates of
the total cleanup costs, including oversight costs, at this site
range from approximately $3.7 million to $4.8 million. In October
1995, the EPA and the City of Minot entered into a consent decree
which requires the city to implement as well as assume liability
for all cleanup costs associated with the remediation plan. The
remaining liability at this site for past and future federal
government oversight costs has been estimated by the EPA to be
approximately $1 million. Montana-Dakota believes that it was not
a material contributor to this contamination and, therefore,
further believes that its share of the approximately $1 million
estimated remaining liability will not have a material effect on
its results of operations.
CENTENNIAL ENERGY HOLDINGS, INC.
NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY (WILLISTON BASIN)
General --
Williston Basin owns and operates over 3,800 miles of
transmission, gathering and storage lines and 24 compressor
stations located in the states of Montana, North Dakota, South
Dakota and Wyoming. Through three underground storage fields
located in Montana and Wyoming, storage services are provided to
local distribution companies, producers, 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, 1995, the net natural gas transmission plant
investment was approximately $161.1 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 have relatively secure residential and commercial end-
users, virtually all have some price-sensitive end-users that could
switch to alternate fuels.
In recent years, Williston Basin has provided the majority of
Montana-Dakota's annual natural gas requirements. However, upon
Williston Basin's implementation of Order 636, Montana-Dakota
elected to acquire substantially all of its system requirements
directly from processors and other producers. Williston Basin
transports essentially all such natural gas for Montana-Dakota
under firm transportation agreements. In addition, Montana-Dakota
has contracted with Williston Basin to provide firm storage
services to facilitate meeting Montana-Dakota's winter peak
requirements.
Preliminary discussions are currently underway between Montana-
Dakota and Williston Basin regarding the renewal of firm
transportation agreements representing 97 percent of Williston
Basin's currently subscribed firm transportation capacity, which
will expire in mid 1997. Williston Basin is currently unable to
determine the outcome of these discussions.
For additional information regarding Williston Basin's sales
and transportation for 1993 through 1995, 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.
In November 1994, Williston Basin completed a storage
enhancement project which increased its certificated storage
withdrawal capacity by 95 MMcf per day. This increase allows
Williston Basin to expand and enhance the storage services it
offers to its customers.
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.
In 1993, Williston Basin interconnected its facilities with
those of Many Islands Pipeline Ltd., a subsidiary of TransGas Ltd.,
a Saskatchewan, Canada pipeline. This interconnect, from which
Williston Basin began receiving firm transportation gas in January
1994, currently provides access up to 10,000 Mcf per day firm
Canadian supply with additional opportunities for interruptible
volumes.
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.
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 its natural gas
reserves. 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 its operations.
Information on Williston Basin's natural gas production,
average sales prices and production costs per Mcf related to its
natural gas interests for 1995 and 1994 is as follows:
1995 1994
Production (MMcf) 5,184 4,932
Average sales price $0.91 $1.37
Production costs, including taxes,
per Mcf $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, 1995, are as follows:
Gross Net
Productive Wells 522 469
Developed Acreage (000's) 228 206
Undeveloped Acreage (000's) 53 47
The following table shows the results of natural gas development
wells drilled and tested during 1995 and 1994:
1995 1994
Productive 17 13
Dry Holes --- ---
Total 17 13
At December 31, 1995, there were five wells in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 113.0 Bcf at December 31, 1995.
These amounts are supported by a report dated January 23, 1996,
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 (Court) against Williston Basin and the Company
disputing certain price and volume issues under the contract. In
its complaint, Moncrief alleged that, for the period January 1,
1985, through December 31, 1992, it had suffered damages ranging
from $1.2 million to $5.0 million, without interest, on the price
paid by Williston Basin for natural gas purchased. Moncrief
requested that the Court award it such amount and further requested
that Williston Basin be obligated for damages for additional volumes
not purchased for the period from November 1, 1993, (the date when
Williston Basin implemented FERC Order 636 and abandoned its natural
gas sales merchant function) to mid-1996, the remaining period of
the contract.
In June 1994, Moncrief filed a motion to amend its complaint
whereby it alleged a new pricing theory under Section 105 of the
Natural Gas Policy Act for natural gas purchased in the past and for
future volumes which Williston Basin refused to purchase effective
November 1, 1993. In July 1994, the Court denied Moncrief's motion
to amend its complaint.
However, in July 1994, the Court, as part of addressing the
proper litigants in this matter, allowed Moncrief to amend its
complaint to assert its new pricing theory under the contract.
Through the course of this action Moncrief has submitted damage
calculations which total approximately $19 million or, under its
alternative pricing theory, approximately $39 million. On March 10,
1995, the Court issued a summary judgment dismissing Moncrief's
pricing theories and substantially reducing Moncrief's claims.
Trial was held in January 1996, and Williston Basin is awaiting the
Court's decision.
Moncrief's damage claims, in Williston Basin's opinion, are
grossly overstated. Williston Basin plans to file for recovery from
ratepayers of amounts which may be ultimately due to Moncrief, if
any.
Regulatory Matters and Revenues Subject to Refund --
Williston Basin had pending with the FERC two general natural
gas rate change applications implemented in 1989 and 1992. In
May 1994, the FERC issued an order relating to the 1989 rate change.
Williston Basin requested rehearing of certain issues addressed in
the order and a stay of compliance and refund pending issuance of
a final order by the FERC. The requested stay was denied by the
FERC and in July 1994, Williston Basin refunded $47.8 million to its
customers, including $33.4 million to Montana-Dakota, all of which
had been reserved. On April 5, 1995, the FERC issued an order
granting in part and denying in part Williston Basin's rehearing
request. As a result of the FERC's order, Williston Basin, on
May 18, 1995, billed its customers approximately $2.7 million, plus
interest, to recover a portion of the amount previously refunded in
July 1994.
On July 25, 1995, the FERC issued an order relating to Williston
Basin's 1992 rate change application. On August 24, 1995, Williston
Basin filed, under protest, tariff sheets in compliance with the
FERC's order, with rates to be effective September 1, 1995.
Williston Basin requested rehearing of certain issues addressed in
the order and the rehearing is pending before the FERC.
On June 30, 1995, Williston Basin filed a general rate increase
application with the FERC requesting an increase of $3.6 million or
6.55 percent, effective August 1, 1995. Williston Basin began
collecting such increase, subject to refund, on January 1, 1996.
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 $6.0 million, $4.6 million and
$3.9 million in 1995, 1994 and 1993, 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 and represent
costs which Williston Basin may not recover. This matter is
currently on appeal. The issue regarding the applicability of
assessing storage charges to the gas creates additional uncertainty
as to the costs associated with holding the gas.
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
December 31, 1995, 17.6 MMdk of this natural gas had been sold by
Williston Basin for use by both on- and off-system markets.
Williston Basin will continue to aggressively market the remaining
43.2 MMdk of this natural gas whenever market conditions are
favorable. In addition, it will continue to seek long-term sales
contracts.
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
1995 actual and 1996 through 1998 anticipated construction
expenditures applicable to Williston Basin's operations:
Actual Estimated
1995 1996 1997 1998
Production and Gathering $3.5 $ 5.9 $ 3.6 $ 6.5
Underground Storage .3 .3 .2 .2
Transmission 3.5 3.8 7.1 11.3
General 2.4 1.6 1.9 1.9
$9.7 $11.6 $12.8 $19.9
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)
Coal Operations:
General --
The Company, through Knife River, is engaged in lignite coal
mining operations. Knife River's surface mining operations are
located at Beulah, North Dakota, Savage, Montana and, until August
1995, at Gascoyne, North Dakota. The average annual production
from the Beulah and Savage mines approximates 2.6 million and
300,000 tons, respectively, while the Gascoyne Mine's production
had historically averaged 2.1 million tons annually. 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,
1995 1994 1993 1992 1991
(In thousands)
Tons sold:
Montana-Dakota generating stations 453 691 624 521 618
Jointly-owned generating stations--
Montana-Dakota's share 883 1,049 1,034 1,021 953
Others 2,767 3,358 3,299 3,259 3,069
Industrial and other sales 115 108 109 112 91
Total 4,218 5,206 5,066 4,913 4,731
Revenues $39,956 $45,634 $44,230 $43,770 $41,201
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 June 1994, Knife River was notified by the owners of the Big
Stone Station that its contract for supplying approximately 2.1
million tons of lignite annually from the Gascoyne Mine would not
be renewed. The current contract expired in August 1995 and, as a
result, Knife River closed the Gascoyne Mine. The costs of closing
the Gascoyne Mine did not have a significant effect on Knife
River's results of operations.
On November 27, 1995, a suit was filed in District Court
(Court), County of Burleigh, State of North Dakota 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 have alleged a breach of contract against
Knife River of the long-term coal supply agreement (Agreement)
between the owners of the Coyote Station and Knife River. The Co-
owners have requested a determination by the 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 Court. The Co-owners are also
alleging 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 such contract, and are seeking damages in an
unspecified amount. On January 8, 1996, the Company and Knife
River filed separate motions with the Court to dismiss or stay
pending arbitration. Such matter is pending before the Court with
oral arguments scheduled for April 22, 1996. The Company and Knife
River believe they have meritorious defenses and intend to
vigorously defend the suit.
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, as
well as participating in the development of clean coal
technologies.
In order to seek greater growth opportunities and to utilize
further its surface mining expertise, Knife River, in 1992, began
expanding its operations into the mining and marketing of
aggregates and related construction materials as discussed below.
Construction Materials Operations:
General --
Knife River, through KRC Holdings, operates construction
materials and mining businesses in the Anchorage, Alaska area,
north-central California and southern Oregon. 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 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 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 following table reflects sales volumes and revenues for the
construction materials operations during the last three years:
Years Ended December 31,
1995 1994 1993
(In thousands)
Aggregates (tons) 2,904 2,688 2,391
Asphalt (tons) 373 391 141
Ready-mixed concrete (cubic yards) 307 315 157
Revenues $73,110 $71,012 $46,167
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 1993, 1994 and 1995, no
single customer accounted for more than 10 percent of annual
construction materials revenues.
Consolidated Construction Materials and Mining Operations:
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1995 actual, including the amount related to the acquisition of
Hawaiian Cement, and 1996 through 1998 anticipated construction
expenditures applicable to Knife River's consolidated construction
materials and mining operations:
Actual Estimated
1995 1996 1997 1998
Construction Materials $35.5 $3.1 $3.0 $3.3
Coal 1.3 3.6 4.8 4.5
$36.8 $6.7 $7.8 $7.8
Knife River continues to seek additional growth opportunities.
These include not only identifying possibilities for alternate uses
of lignite coal but also 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. Knife River believes that these operations are in
substantial compliance with those regulations.
Reserve Information --
As of December 31, 1995, Knife River had under ownership or
lease, reserves of approximately 232 million tons of recoverable
lignite coal (including 114 million tons at the recently closed
Gascoyne Mine), 92 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 and 1995 production. Knife River estimates that
approximately 70 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.
As of December 31, 1995, the combined construction materials
operations had under ownership approximately 68 million tons of
recoverable aggregate reserves.
OIL AND NATURAL GAS OPERATIONS AND PROPERTY (FIDELITY OIL)
General --
The Company, through Fidelity Oil, is involved in the
acquisition, exploration, development and production of oil and
natural gas properties.
Fidelity Oil undertakes ventures, through working-interest
agreements with selected operators. These ventures vary from the
acquisition of producing properties with potential development
opportunities to exploration and are located in the western United
States, offshore in the Gulf of Mexico and in Canada. In these
ventures, Fidelity Oil shares revenues and expenses from the
development of specified properties in proportion to its
investments.
Fidelity Oil, through its net proceeds interests, owns in fee
or holds oil and natural gas leases and operating rights applicable
to the deep rights (below 2,000 feet) in the Cedar Creek Anticline
in southeastern Montana. Pursuant to an operating agreement with
Shell Western E&P, Inc., Shell as operator, controls all
development, production, operations and marketing applicable to
such acreage. As a net proceeds interest owner, Fidelity Oil is
entitled to proceeds only when a particular unit has reached payout
status.
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 net proceeds and working
interests for 1995, 1994 and 1993 are as follows:
1995 1994 1993
Oil:
Production (000's of barrels) 1,973 1,565 1,497
Average sales price $15.07 $13.14 $14.84
Natural Gas:
Production (MMcf) 12,319 9,228 8,817
Average sales price $1.51 $1.84 $1.86
Production costs, including taxes,
per net equivalent barrel $3.18 $4.04 $3.98
Well and Acreage Information --
Fidelity Oil's gross and net productive well counts and gross
and net developed and undeveloped acreage for the net proceeds and
working interests at December 31, 1995, are as follows:
Gross Net
Productive Wells:
Oil 4,829 179
Natural Gas 600 30
Total 5,429 209
Developed Acreage (000's) 1,085 83
Undeveloped Acreage (000's) 655 67
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1995, 1994 and 1993:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1995 3 2 5 8 1 9 14
1994 4 3 7 6 1 7 14
1993 2 2 4 5 1 6 10
At December 31, 1995, there were no exploratory wells or
development wells in the process of drilling.
Capital Requirements --
The following summary (in millions of dollars) reflects capital
expenditures, including those not subject to amortization, related
to oil and natural gas activities for the years 1995, 1994 and
1993:
1995 1994 1993
Acquisitions $ 9.4 $ 5.6 $ 9.3
Exploration 7.7 13.2 7.8
Development 22.6 19.7 7.8
Total Capital Expenditures $39.7 $38.5 $24.9
Fidelity Oil plans additional commitments to oil and gas
investments and has budgeted $40 million, $45 million and $50
million for the years 1996, 1997 and 1998, respectively, for such
activities.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 14.2 million barrels and 66.0
Bcf, respectively, at December 31, 1995. Of these amounts, 9.2
million barrels and 2.1 Bcf, as supported by a report dated
January 9, 1996, 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
The Company and Knife River have been named as defendants in a
legal action primarily related to coal pricing issues at the Coyote
Station. Such suit was filed by the Co-owners of the Coyote
Station as described under Items 1 and 2 -- "Business and
Properties -- Construction Materials and Mining Operations and
Property." The Company's and Knife River's assessment of this
proceeding is included in the description of the litigation.
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 as described under Items 1 and 2 --
"Business and Properties -- Natural Gas Transmission Operations and
Property." Williston Basin's assessment of this proceeding is
included in the description of the litigation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during
the fourth quarter of 1995.
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 1995 and 1994 and
dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High)* (Low)* Per Share*
1995
First Quarter $18.67 $17.17 $ .27
Second Quarter 20.00 17.75 .27
Third Quarter 21.33 19.08 .27
Fourth Quarter 23.08 19.63 .27
$1.08
1994
First Quarter $21.50 $19.58 $ .26
Second Quarter 21.42 17.67 .26
Third Quarter 18.83 16.92 .26
Fourth Quarter 18.67 16.92 .27
$1.05
_______________________
* Adjusted for October 1995 three-for-two common stock split.
As of December 31, 1995, the Company's common stock was held by
approximately 13,900 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 1995 1994 1993
Electric $ 12.0 $ 11.7 $ 12.6
Natural gas distribution 1.6 .3 1.2
Natural gas transmission 8.4 6.1 4.7
Construction materials
and mining 10.8 11.6 12.4
Oil and natural gas production 8.0 9.3 7.1
Earnings on common stock $ 40.8 $ 39.0 $ 38.0
Earnings per common share $ 1.43 $ 1.37 $ 1.34
Return on average common
equity for the 12 months
ended 12.3% 12.1% 12.3%
Earnings information presented in this table and in the
following discussion is before the $8.9 million ($5.5 million after
tax) cumulative effect of a 1993 accounting change. See Note 1 of
Notes to Consolidated Financial Statements for a further discussion
of this accounting change.
Earnings for 1995 increased $1.8 million from the comparable
period a year ago. Increased retail sales at the electric business
and increased throughput at the natural gas distribution and
transmission businesses, increased oil prices and oil and natural
gas production at the oil and natural gas production business and
benefits derived from favorable rate changes at the natural gas
distribution and transmission businesses increased earnings. The
favorable rate change at the natural gas transmission business
resulted from a FERC order received in April 1995 on a rehearing
request relating to a 1989 general rate proceeding. The order
allowed for the one-time billing to customers for approximately
$2.2 million (after tax) to recover a portion of the amount
previously refunded in July 1994. Income from a 50% percent
interest in Hawaiian Cement acquired in September 1995 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 the resulting
closure of the Gascoyne Mine, and increased costs associated with
rainy West Coast weather at the construction materials operations,
partially offset the earnings increase.
Earnings for 1994 increased $1.0 million from 1993. The 1994
realization of an investment gain related to the sale of an equity
investment in GARI, which was $3.3 million (after tax) more than
a corresponding gain realized in 1993, increased earnings. In
addition, higher retail electric sales at the electric business,
favorable rate changes at the natural gas distribution and
transmission businesses, increased sales at the construction
materials operations due to the September 1993 acquisition of the
Oregon construction materials businesses and higher oil revenue due
to increased production at the oil and natural gas production
business contributed to the earnings increase. Increased electric
purchased power demand charges, increased operation and maintenance
expenses at the electric and natural gas distribution businesses,
lower throughput at the natural gas distribution and transmission
businesses, a seasonal first quarter loss experienced at the
Alaskan construction materials operations which was acquired in
April 1993, lower average oil prices at the oil and natural gas
production business, 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.
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. Certain reclassifications have been made in the
following statistics for 1993 and 1994 to conform to the 1995
presentation. Such reclassifications had no effect on net income
or common stockholders' investment as previously reported.
<PAGE>
Montana-Dakota -- Electric Operations
Years ended December 31,
1995 1994 1993
Operating revenues:
Retail sales $ 124.4 $ 123.2 $ 119.7
Sales for resale and other 10.2 10.7 11.4
134.6 133.9 131.1
Operating expenses:
Fuel and purchased power 41.8 43.2 41.3
Operation and maintenance 40.1 41.0 37.4
Depreciation, depletion and
amortization 16.3 15.5 15.3
Taxes, other than income 6.5 6.6 6.6
104.7 106.3 100.6
Operating income 29.9 27.6 30.5
Retail sales (kWh) 1,993.7 1,955.1 1,893.7
Sales for resale (kWh) 408.0 444.5 511.0
Cost of fuel and purchased
power per kWh $ .016 $ .017 $ .016
Montana-Dakota -- Natural Gas Distribution Operations
Years ended December 31,
1995 1994 1993
Operating revenues:
Sales $ 146.8 $ 151.7 $ 151.7
Transportation and other 3.7 3.6 4.3
150.5 155.3 156.0
Operating expenses:
Purchased natural gas sold 102.6 111.3 114.0
Operation and maintenance 30.4 30.0 28.6
Depreciation, depletion and
amortization 6.7 6.1 5.1
Taxes, other than income 3.9 4.0 3.6
143.6 151.4 151.3
Operating income 6.9 3.9 4.7
Volumes (dk):
Sales 33.9 31.8 31.2
Transportation 11.1 9.3 12.7
Total throughput 45.0 41.1 43.9
Degree days (% of normal) 101.6% 96.7% 105.5%
Cost of natural gas, including
transportation, per dk $ 3.02 $ 3.50 $ 3.66
Williston Basin -- Natural Gas Transmission Operations
Years ended December 31,
1995 1994 1993
Operating revenues:
Sales for resale $ --- $ --- $ 51.3*
Transportation 54.1* 52.6* 30.8*
Storage 12.6 10.6 2.2
Natural gas production and
other 5.2 7.7 7.0
71.9 70.9 91.3
Operating expenses:
Purchased natural gas sold --- --- 20.6
Operation and maintenance 35.7* 38.8* 39.0*
Depreciation, depletion and
amortization 7.0 6.6 7.1
Taxes, other than income 3.8 4.2 4.5
46.5 49.6 71.2
Operating income 25.4 21.3 20.1
Volumes (dk):
Sales for resale--
Montana-Dakota --- --- 13.0
Other --- --- .2
Transportation--
Montana-Dakota 35.4 33.0 18.5
Other 32.6 30.9 40.9
Total throughput 68.0 63.9 72.6
Produced (Mdk) 4,981 4,732 3,876
* Includes amortization and
related recovery of deferred
natural gas contract buy-out/
buy-down and gas supply
realignment costs $ 11.4 $ 12.8 $ 13.4
Knife River -- Construction Materials and Mining Operations
Years ended December 31,
1995** 1994 1993
Operating revenues:
Construction materials $ 73.1 $ 71.0 $ 46.2
Coal 39.9 45.6 44.2
113.0 116.6 90.4
Operating expenses:
Operation and maintenance 87.8 88.2 62.7
Depreciation, depletion and
amortization 6.2 6.4 5.6
Taxes, other than income 4.5 5.4 5.1
98.5 100.0 73.4
Operating income 14.5 16.6 17.0
Sales (000's):
Aggregates (tons) 2,904 2,688 2,391
Asphalt (tons) 373 391 141
Ready-mixed concrete
(cubic yards) 307 315 157
Coal (tons) 4,218 5,206 5,066
** 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.<PAGE>
Fidelity Oil -- Oil and Natural Gas Production Operations
Years ended December 31,
1995 1994 1993
Operating revenues:
Oil $ 30.1 $ 20.9 $ 22.7
Natural gas 18.7 17.1 16.4
48.8 38.0 39.1
Operating expenses:
Operation and maintenance 13.7 12.0 11.6
Depreciation, depletion and
amortization 18.6 13.5 12.0
Taxes, other than income 2.6 3.7 3.7
34.9 29.2 27.3
Operating income 13.9 8.8 11.8
Production (000's):
Oil (barrels) 1,973 1,565 1,497
Natural gas (Mcf) 12,319 9,228 8,817
Average sales price:
Oil (per barrel) $ 15.07 $ 13.14 $ 14.84
Natural gas (per Mcf) 1.51 1.84 1.86
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 $54.6 million, $49.2 million and $5.4
million, respectively, for 1995, $65.2 million, $58.5 million and
$6.7 million, respectively, for 1994, and $68.3 million, $56.5
million and $11.8 million, respectively, for 1993.
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 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 charges 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 depreciable plant balances, 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
a year ago. The effects of a Wyoming Supreme Court order granting
recovery in 1994 of a prior refund made by Montana-Dakota and the
pass-through of lower average natural gas costs reduced revenues.
The effect of higher volumes transported were largely offset by
lower average transportation rates. Higher operation expenses, due
primarily to higher benefit-related costs somewhat offset by lower
sales expenses, partially offset the operating income improvement.
Increased depreciation expense, due to higher depreciable plant
balances, also partially offset the increase in operating income.
Natural gas distribution earnings increased due to the
improvement in operating income. A decreased return recognized 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
Operating income increased primarily due to an increase in
transportation and storage revenues. The transportation revenue
increase resulted primarily from the benefits of a favorable FERC
order received in April 1995 on a rehearing request relating to a
1989 general rate proceeding. The order allowed for the one-time
billing to 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, 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 deferred natural gas contract litigation
settlement costs required to be recovered, added to the
transportation revenue improvement. Lower operation and
maintenance expenses, primarily lower production royalty expenses
and reduced deferred natural gas contract litigation settlement
costs required to be amortized, 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 depreciable plant
balances, 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, but at lower prices, higher ready-mixed
concrete prices, but lower volumes, higher construction and
aggregate delivery revenues, and increased steel fabrication sales
volumes, partially offset the operating income decline. Lower
asphalt sales volumes due to increased competition 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, lower depreciation expense and lower
taxes other than income, 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 a 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.
1994 compared to 1993
Montana-Dakota -- Electric Operations
The decline in operating income reflects increased fuel and
purchased power costs and operation expenses. Fuel and purchased
power costs increased principally due to higher demand charges
associated with the pass-through of periodic maintenance costs and
the purchase of an additional five megawatts of firm capacity
related to a participation power contract. Operation expenses
increased primarily the result of higher payroll and benefit-
related costs, largely the accrual of SFAS No. 106 costs. In
addition, decreased sales for resale, the result of a delay in
water conservation efforts by hydroelectric generators, reduced
operating income. Increased retail sales to all major markets, the
result of increased demand due to more normal summer weather than
that experienced in 1993, partially offset the operating income
decline.
Earnings for the electric business decreased due to the
operating income decline and increased long-term debt interest,
resulting from lower interest received from Williston Basin due to
the retirement of intercompany debt, partially offset by the
retirement of $15.0 million of 5.8 percent medium-term notes on
April 1, 1994. Decreased income taxes somewhat offset the earnings
decline.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income decreased at the natural gas distribution
business from the corresponding period in 1993 due to a 1.7 million
decatherm (MMdk) weather-related decline in sales and decreased
transportation volumes, primarily due to two oil refineries
bypassing Montana-Dakota's distribution facilities. In addition,
higher operation and maintenance expenses, primarily increased
payroll and benefit-related costs and increased distribution and
sales expenses due to the system expansion into north-central South
Dakota, and increased depreciation expense reduced operating
income. The benefits of general rate increases placed into effect
in late 1993 and during 1994 in North Dakota, South Dakota, Wyoming
and Montana and the addition of nearly 5,000 customers improved
operating income. Also contributing to operating income was a
Wyoming Supreme Court order granting recovery in 1994 of a prior
refund.
Gas distribution earnings decreased due to the operating income
decline and increased interest expense, primarily carrying costs
being accrued on natural gas costs refundable through rate
adjustments, higher financing costs related to increased capital
expenditures and the previously described intercompany debt
retirement. The return earned on the storage gas inventory
(included in Other income--net) somewhat mitigated the decline in
earnings.
Williston Basin -- Natural Gas Transmission Operations
The increase in operating income reflects a January 1994 rate
change due to a rate stipulation agreement with the FERC and the
realization of revenue related to 5.0 MMdk of natural gas
transported to storage. Prior to the implementation of Order 636,
these revenues were recognized during the winter months when gas
was withdrawn from storage whereas such revenues are now recognized
primarily in the summer months when gas is transported to storage.
Natural gas production revenues increased due to increased volumes
produced, partially offset by a 15 cent per decatherm decline in
realized natural gas prices. In addition, decreased operation and
maintenance expenses, depreciation and taxes other than income,
primarily due to the sale or transfer of unneeded facilities,
further improved operating income. Decreased net throughput,
primarily to off-system markets and LDC end users, partially offset
the operating income increase. A 1993 out-of-period credit
adjustment to take-or-pay surcharge amortizations also partially
offset the improvement in operating income.
Earnings for this business increased due to the operating
income improvement, decreased long-term debt interest, the result
of debt refinancing and debt retirements in July 1993, and April
1994, respectively, and increased interest being accrued on gas
supply realignment transition costs (included in Other income--
net). Partially offsetting the earnings improvement were increased
carrying costs associated with the natural gas repurchase
commitment, due to higher average rates, and decreased investment
income, the result of lower investible funds stemming from a
regulatory refund made in mid-1994.
Knife River -- Construction Materials and Mining Operations
Construction Materials Operations --
Increased sales due to the September 1993 acquisition of the
Oregon construction materials businesses and improved cement,
asphalt and building materials sales at the Alaskan operations were
the primary contributors to the $461,000 increase in construction
materials operating income. Somewhat offsetting this improvement
were the effects of a seasonal first quarter loss experienced at
the Alaskan operations which was acquired in April 1993 and reduced
aggregate and ready-mixed concrete sales at these operations due to
fewer large commercial construction projects in the area than 1993.
Coal Operations --
Operating income for the coal operations decreased $853,000
primarily due to increased operation expenses. Higher overburden
removal costs at the Beulah Mine, and increased reclamation
expenses and costs associated with an early retirement program
stemming from the closing of the Gascoyne Mine in mid-1995
increased operation expenses. An improvement in coal revenues,
primarily increased sales at the Gascoyne Mine, mainly the result
of increased demand by electric generation customers, and increased
selling prices at the Beulah Mine, partially offset the decline in
coal operating income.
Consolidated --
Earnings decreased due to the decline in coal operating income
and reduced investment income, primarily lower investible funds due
to the aforementioned acquisitions. The improvement in
construction materials operating income somewhat mitigated the
earnings decline.
Fidelity Oil -- Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production
business declined as a result of lower oil revenues, $2.7 million
of which was due to lower average oil prices partially offset by a
$1.0 million increase resulting from higher production. A volume-
related increase in operation expenses and depreciation, depletion
and amortization also contributed to the decline in operating
income. A natural gas revenue improvement, $764,000 of which was
due to higher natural gas production, partially offset the decline
in operating income.
Earnings for this business improved due to the realization of
an investment gain related to the sale of an equity investment in
GARI, which was $3.3 million (after tax) more than a corresponding
gain realized in 1993. The decline in operating income partially
offset the earnings increase.
Prospective Information
Each of the Company's businesses is subject to competition,
varying in both type and degree. See Items 1 and 2 for a further
discussion of the effects these competitive forces have on each of
the Company's businesses.
The operating results of the Company's electric, natural gas
distribution, natural gas transmission, and construction materials
and mining businesses are, in varying degrees, influenced by the
weather as well as by the general economic conditions within their
respective market areas. Additionally, the ability to recover
costs through the regulatory process affects the operating results
of the Company's electric, natural gas distribution and natural gas
transmission businesses.
Knife River continues to seek additional growth opportunities.
These include 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. See Items 1 and 2 under Knife River
for a discussion of an acquisition made during 1995.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of" (SFAS No. 121). SFAS No. 121 imposes stricter
criteria for assets, including regulatory assets, by requiring that
such assets be probable of future recovery at each balance sheet
date. The Company will adopt SFAS No. 121 on January 1, 1996, and
the adoption will not have a material affect on the Company's
financial position or results of operations. This conclusion may
change in the future depending on the extent to which recovery of
the Company's long-lived assets is influenced by an increasingly
competitive environment in the electric and natural gas industries.
Liquidity and Capital Commitments
The Company's construction costs and additional investments in
construction materials and mining, and oil and natural gas
activities (in millions of dollars) for 1993 through 1995 and as
anticipated for 1996 through 1998 are summarized in the following
table, which also includes the Company's capital needs for the
retirement of maturing long-term securities.
Estimated
1993 1994 1995 Company/Description 1996 1997 1998
Montana-Dakota:
$ 16.2 $ 14.2 $ 19.7 Electric $ 18.3 $ 16.8 $ 17.7
15.0 13.2 8.9 Natural Gas Distribution 7.7 7.8 8.0
31.2 27.4 28.6 26.0 24.6 25.7
5.4 14.4 9.7 Williston Basin 11.6 12.8 19.9
43.1 3.6 36.8 Knife River 6.7 7.8 7.8
24.9 38.6 39.9 Fidelity 40.0 45.0 50.0
1.0 1.0 2.6 Prairielands 3.3 1.2 2.6
105.6 85.0 117.6 87.6 91.4 106.0
Retirement of Long-Term
3.2 35.8 20.5 Debt/Preferred Stock 17.1 16.6 11.4
$108.8 $120.8 $138.1 Total $104.7 $108.0 $117.4
In reconciling construction expenditures to investing
activities per the Consolidated Statements of Cash Flows, the
construction 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 1993, 1994 and
1995. 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 1993 and 1994 Williston Basin amounts are reflected in the
table above net of the sale of storage gas of $1.7 million and $8.3
million, respectively.
In 1995 the Company's regulated businesses operated by Montana-
Dakota and Williston Basin provided all of the funds needed for
construction purposes. The Company's 1995 capital needs to retire
maturing long-term securities were $20.5 million.
It is anticipated that Montana-Dakota will continue to provide
all of the funds required for its construction requirements for the
years 1996 through 1998 from internal sources, through the use of
its $30 million revolving credit and term loan agreement, $21.5
million of which was outstanding at December 31, 1995, 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.
Williston Basin expects to meet its construction requirements
and financing needs for the years 1996 through 1998 with a
combination of internally generated funds, short-term lines of
credit aggregating $35 million, none of which is outstanding at
December 31, 1995, 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. On April 1,
1994, Williston Basin borrowed $25 million under a term loan
agreement, with the proceeds used solely for the purpose of
refinancing purchase money mortgages payable to the Company. At
December 31, 1995, $7.5 million is available and outstanding under
the term loan agreement.
Knife River's 1995 capital needs, including the acquisition of
a 50 percent interest in Hawaiian Cement, were met through funds on
hand, funds generated from internal sources, short-term lines of
credit and a long-term revolving credit agreement. It is
anticipated that funds generated from internal sources, short-term
lines of credit aggregating $6 million, none of which was
outstanding at December 31, 1995, and a long-term revolving credit
agreement of $40 million, $25 million of which was outstanding at
December 31, 1995, will continue to meet the needs of this business
unit for 1996 through 1998, excluding funds which may be required
for future acquisitions. It is anticipated that funds required for
future acquisitions will be met primarily through the issuance of
a combination of long-term debt and equity securities.
Fidelity Oil's 1995 capital needs related to its oil and
natural gas acquisition, development and exploration program were
met through funds generated from internal sources and long-term
lines of credit aggregating $25 million, $2 million of which was
outstanding at December 31, 1995. It is anticipated that
Fidelity's 1996 through 1998 capital needs will be met from
internal sources and its long-term lines of credit.
See Note 13 of Notes to Consolidated Financial Statements for
a discussion of notices of proposed deficiency received from the
IRS proposing substantial additional income taxes. The level of
funds which could be required as a result of the proposed
deficiencies could be significant if the IRS position were upheld.
Prairielands' 1995 capital needs were met through funds
generated internally and short-term lines of credit aggregating
$5.4 million, $600,000 of which was outstanding at December 31,
1995. It is anticipated that Prairielands' 1996 through 1998
capital needs will be met from internal sources and its short-term
lines of credit.
The Company utilizes its short-term lines of credit aggregating
$40 million and its $30 million revolving credit and term loan
agreement to meet its short-term financing needs and to take
advantage of market conditions when timing the placement of long-
term or permanent financing. There were no borrowings outstanding
at December 31, 1995, under the short-term lines of credit.
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, 1995, the Company could have issued
approximately $200 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 3.0 and 2.9 times for 1995 and 1994, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 3.9 times in 1995 compared to 3.3 times in 1994. Stockholders'
equity as a percent of total capitalization was 57% and 58% at
December 31, 1995 and 1994, 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 13 and 14 of the
Company's Proxy Statement dated March 4, 1996 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 6 through 13 of the Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 14 of the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits.
Index to Financial Statements and Financial Statement
Schedules.
1. Financial Statements:
Report of Independent Public Accountants *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 1995 *
Consolidated Balance Sheets at December 31,
1995, 1994 and 1993 *
Consolidated Statements of Capitalization at
December 31, 1995, 1994 and 1993 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1995 *
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 1995 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 1995 is not to be
deemed filed as part of this report.<PAGE>
3. Exhibits:
3(a) Composite Certificate of Incorporation
of MDU Resources Group, Inc., 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 MDU Resources Group, Inc.,
as amended to date, filed as Exhibit 3(b)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
4(a) Indenture of Mortgage, dated as of
May 1,
1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of
April 21, 1992, and the Forty-Sixth
through Forty-Eighth Supplements thereto
between the Company and the New York
Trust Company (The Bank of New York,
successor Corporate Trustee) and A. C.
Downing (W. T. Cunningham, successor
Co-Trustee), filed as Exhibit 4(a)
in Registration No. 33-66682; and
Exhibits 4(e), 4(f) and 4(g)
in Registration No. 33-53896 *
+ 10(a) Management Incentive Compensation Plan,
filed as Exhibit 10(a) in Registration
No. 33-66682 *
+ 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, filed as Exhibit 10(d)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
+ 10(e) Directors' Compensation Policy, filed as
Exhibit 10(d) in Registration No. 33-66682 *
+ 10(f) Deferred Compensation Plan for Directors,
filed as Exhibit 10(e) in Registration
No. 33-66682 *
+ 10(g) Non-Employee Director Stock Compensation
Plan **
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 1995 **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Consent of Independent Public Accountants **
23(b) Consent of Engineer **
23(c) Consent of Engineer **
27 Financial Data Schedule **
* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement required
to be filed as an exhibit to this form pursuant to Item 14(c)
of this report.
(b) Reports on Form 8-K.
Form 8-K was filed on December 12, 1995. Under Item 5--Other
Events, it was reported that on November 27, 1995, a suit was
filed in District Court, County of Burleigh, State of North
Dakota by Minnkota Power Cooperative, Inc., Otter Tail Power
Company, Northwestern Public Service Company, and Northern
Municipal Power Agency, the owners of an aggregate interest of
75 percent of the Coyote electrical generating station,
against the Company (an owner of a 25 percent interest in the
Coyote Station) and Knife River.<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, 1996 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, 1996
Harold J. Mellen, Jr. Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief Operating February 28, 1996
Douglas C. Kane (Executive Vice President Officer and
and Chief Operating Officer) Director
/s/ Warren L. Robinson Chief Financial February 28, 1996
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 28, 1996
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director February 28, 1996
John A. Schuchart (Chairman of the Board)
/s/ Thomas Everist Director February 28, 1996
Thomas Everist
/s/ Richard L. Muus Director February 28, 1996
Richard L. Muus
/s/ Robert L. Nance Director February 28, 1996
Robert L. Nance
/s/ John L. Olson Director February 28, 1996
John L. Olson
/s/ San W. Orr, Jr. Director February 28, 1996
San W. Orr, Jr.
/s/ Charles L. Scofield Director February 28, 1996
Charles L. Scofield
/s/ Homer A. Scott, Jr. Director February 28, 1996
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director February 28, 1996
Joseph T. Simmons
/s/ Stanley F. Staples, Jr. Director February 28, 1996
Stanley F. Staples, Jr.
/s/ Sister Thomas Welder Director February 28, 1996
Sister Thomas Welder<PAGE>
EXHIBIT INDEX
Exhibit No.
3(a) Composite Certificate of Incorporation
of MDU Resources Group, Inc., 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 MDU Resources Group, Inc.,
as amended to date, filed as Exhibit 3(b)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
4(a) Indenture of Mortgage, dated as of May 1,
1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of
April 21, 1992, and the Forty-Sixth
through Forty-Eighth Supplements thereto
between the Company and the New York
Trust Company (The Bank of New York,
successor Corporate Trustee) and A. C.
Downing (W. T. Cunningham, successor
Co-Trustee), filed as Exhibit 4(a)
in Registration No. 33-66682; and
Exhibits 4(e), 4(f) and 4(g)
in Registration No. 33-53896 *
+ 10(a) Management Incentive Compensation Plan,
filed as Exhibit 10(a) in Registration
No. 33-66682 *
+ 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, filed as Exhibit 10(d)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
+ 10(e) Directors' Compensation Policy, filed as
Exhibit 10(d) in Registration No. 33-66682 *
+ 10(f) Deferred Compensation Plan for Directors,
filed as Exhibit 10(e) in Registration
No. 33-66682 *
+ 10(g) Non-Employee Director Stock Compensation
Plan **
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 1995 **
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.
MDU RESOURCES GROUP, INC.
NON-EMPLOYEE DIRECTOR STOCK COMPENSATION PLAN
I. Purpose
The purpose of the MDU Resources Group, Inc. Non-Employee
Director Stock Compensation Plan is to provide ownership of the
Company's stock to non-employee members of the Board of Directors
in order to improve the Company's ability to attract and retain
highly qualified individuals to serve as directors of the Company
and to strengthen the commonality of interest between directors and
stockholders.
II. Definitions
When used herein, the following terms shall have the
respective meanings set forth below:
"Agent" means a securities broker-dealer selected by the
Company and registered under the Exchange Act.
"Annual Retainer" means the annual retainer payable by the
Company to Non-Employee Directors (exclusive of any per
meeting fees or expense reimbursements.)
"Annual Meeting of Stockholders" means the annual meeting of
stockholders of the Company at which directors of the Company
are elected.
"Board" or "Board of Directors" means the Board of Directors
of the Company.
"Committee" means a committee whose members meet the
requirements of Section IV(A) hereof, and who are appointed
from time to time by the Board to administer the Plan.
"Common Stock" means the common stock, $3.33 par value, of the
Company.
"Company" means MDU Resources Group, Inc., a Delaware
corporation, and any successor corporation.
"Effective Date" means the date as of which the Plan is
approved by the stockholders of the Company.
"Employee" means any officer or other common law employee of
the Company or of any of its business units or divisions or of
any Subsidiary.
"Exchange Act" means the Securities Exchange Act of 1934, as
amended.
"Non-Employee Director" or "Participant" means any person who
is elected or appointed to the Board of Directors of the
Company and who is not an Employee.
"Plan" means the Company's Non-Employee Director Stock
Compensation Plan, adopted by the Board on February 9, 1995,
and approved by the stockholders on April 25, 1995, as it may
be amended from time to time.
"Plan Year" means the period commencing on the Effective Date
of the Plan and ending the next following December 31 and,
thereafter, the calendar year.
"Stock Payment" means that portion of the Annual Retainer to
be paid to Non-Employee Directors in shares of Common Stock
rather than cash for services rendered as a director of the
Company, as provided in Section V hereof, including that
portion of the Stock Payment resulting from any election
specified in Section VI hereof.
"Subsidiary" means any corporation that is a "subsidiary
corporation" of the Company, as that term is defined in
Section 424(f) of the Internal Revenue Code of 1986, as
amended.
III. Shares of Common Stock Subject to the Plan
Subject to Section VII below, the maximum aggregate number of
shares of Common Stock that may be delivered under the Plan is
75,000 shares. The Common Stock to be delivered under the Plan
will be made available from authorized but unissued shares of
Common Stock, treasury stock or shares of Common Stock purchased on
the open market. Shares of Common Stock purchased on the open
market shall be purchased by the Agent in compliance with Rule 10b-
6 and Rule 10b-18 under the Exchange Act to the extent compliance
shall be required. Shares of Common Stock purchased on the open
market by the Agent shall be purchased and held in such manner that
such shares are not returned to the status of treasury stock or
authorized but unissued shares of Common Stock.
IV. Administration
A. The Plan will be administered by a committee appointed by
the Board, consisting of two or more persons who are not eligible
to participate in the Plan. Members of the Committee need not be
members of the Board. The Company shall pay all costs of
administration of the Plan.
B. Subject to and not inconsistent with the express
provisions of the Plan, the Committee has and may exercise such
powers and authority of the Board as may be necessary or
appropriate for the Committee to carry out its functions under the
Plan. Without limiting the generality of the foregoing, the
Committee shall have full power and authority (i) to determine all
questions of fact that may arise under the Plan, (ii) to interpret
the Plan and to make all other determinations necessary or
advisable for the administration of the Plan and (iii) to
prescribe, amend and rescind rules and regulations relating to the
Plan, including, without limitation, any rules which the Committee
determines are necessary or appropriate to ensure that the Company
and the Plan will be able to comply with all applicable provisions
of any federal, state or local law. All interpretations,
determinations and actions by the Committee will be final and
binding upon all persons, including the Company and the
Participants.
V. Determination of Annual Retainer and Stock Payments
A. The Board shall determine the Annual Retainer payable to
all Non-Employee Directors of the Company.
B. Each director who is a Non-Employee Director immediately
following the date of the Company's Annual Meeting of Stockholders
shall receive on the fifteenth business day following the Annual
Meeting a Stock Payment of 300 shares of Common Stock as a portion
of the Annual Retainer payable to such director for the Plan Year
in which such date occurs. Certificates evidencing the shares of
Common Stock constituting Stock Payments shall be registered in the
respective names of the Participants and shall be issued to each
Participant. The cash portion of the Annual Retainer shall be paid
to Non-Employee Directors at such times and in such manner as may
be determined by the Board of Directors.
C. Any director may decline a Stock Payment for any Plan
Year; provided, however, that no cash compensation shall be paid in
lieu thereof. Any director who declines a Stock Payment must do so
in writing prior to the performance of any services as a
Non-Employee Director for the Plan Year to which such Stock Payment
relates.
D. No Non-Employee Director shall be required to forfeit or
otherwise return any shares of Common Stock issued as a Stock
Payment pursuant to the Plan (including any shares of Common Stock
received as a result of an election under Section VI)
notwithstanding any change in status of such Non-Employee Director
which renders him ineligible to continue as a Participant in the
Plan. Any person who is a Non-Employee Director immediately
following the Company's Annual Meeting of Stockholders shall be
entitled to receive a Stock Payment as a portion of the applicable
Annual Retainer.
VI. Election to Increase Amount of Stock Payment
In lieu of receiving the cash portion of the Annual Retainer
for any Plan Year, a Participant may make a written election to
reduce the cash portion of such Annual Retainer by a specified
dollar amount and have such amount applied to purchase additional
shares of Common Stock of the Company. The election shall be made
on a form provided by the Committee and must be returned to the
Committee no later than six months prior to the applicable Annual
Meeting of Stockholders of the Company. The election form shall
state the amount by which the Participant desires to reduce the
cash portion of the Annual Retainer, which shall be applied toward
the purchase of Common Stock to be delivered on the same date that
the Stock Payment is made; provided, however, that no fractional
shares may be purchased. Cash in lieu of any fractional share
shall be paid to the Participant. An election shall continue in
effect until changed or revoked by the Participant. No Participant
shall be allowed to change or revoke any election for the then
current year, but may change an election for any subsequent Plan
Year.
VII. Adjustment For Changes in Capitalization
If the outstanding shares of Common Stock of the Company are
increased, decreased or exchanged for a different number or kind of
shares or other securities, or if additional shares or new or
different shares or other securities are distributed with respect
to such shares of Common Stock or other securities, through merger,
consolidation, sale of all or substantially all of the property of
the Company, reorganization or recapitalization, reclassification,
stock dividend, stock split, reverse stock split, combinations of
shares, rights offering, distribution of assets or other
distribution with respect to such shares of Common Stock or other
securities or other change in the corporate structure or shares of
Common Stock, the number of shares to be granted annually, the
maximum number of shares and/or the kind of shares that may be
issued under the Plan shall be appropriately adjusted by the
Committee. Any determination by the Committee as to any such
adjustment will be final, binding and conclusive. The maximum
number of shares issuable under the Plan as a result of any such
adjustment shall be rounded down to the nearest whole share.
VIII. Amendment and Termination of Plan
A. The Board will have the power, in its discretion, to
amend, suspend or terminate the Plan at any time; provided,
however, that no amendment which requires stockholder approval in
order for the Plan to continue to comply with Rule 16b-3 under the
Exchange Act, including any successor to such Rule, shall be
effective unless such amendment shall be approved by the requisite
vote of the stockholders of the Company entitled to vote thereon.
B. Notwithstanding the foregoing, any provision of the Plan
that either states the amount and price of securities to be issued
under the Plan and specifies the price and timing of such
issuances, or sets forth a formula that determines the amount,
price and timing of such issuances, shall not be amended more than
once every six months, other than to comport with changes in the
Internal Revenue Code, the Employee Retirement Income Security Act,
or the rules thereunder.
IX. Effective Date and Duration of the Plan
The Plan will become effective upon the Effective Date, and
shall remain in effect, subject to the right of the Board of
Directors to terminate the Plan at any time pursuant to Section
VIII, until all shares subject to the Plan have been purchased or
acquired according to the Plan's provisions.
X. Miscellaneous Provisions
A. Continuation of Directors in Same Status
Nothing in the Plan or any action taken pursuant to the Plan
shall be construed as creating or constituting evidence of any
agreement or understanding, express or implied, that the Company
will retain a Non-Employee Director as a director or in any other
capacity for any period of time or at a particular retainer or
other rate of compensation, as conferring upon any Participant any
legal or other right to continue as a director or in any other
capacity, or as limiting, interfering with or otherwise affecting
the right of the Company to terminate a Participant in his capacity
as a director or otherwise at any time for any reason, with or
without cause, and without regard to the effect that such
termination might have upon him as a Participant under the Plan.
B. Compliance with Government Regulations
Neither the Plan nor the Company shall be obligated to issue
any shares of Common Stock pursuant to the Plan at any time unless
and until all applicable requirements imposed by any federal and
state securities and other laws, rules and regulations, by any
regulatory agencies or by any stock exchanges upon which the Common
Stock may be listed have been fully met. As a condition precedent
to any issuance of shares of Common Stock and delivery of
certificates evidencing such shares pursuant to the Plan, the Board
or the Committee may require a Participant to take any such action
and to make any such covenants, agreements and representations as
the Board or the Committee, as the case may be, in its discretion
deems necessary or advisable to ensure compliance with such
requirements. The Company shall in no event be obligated to
register the shares of Common Stock deliverable under the Plan
pursuant to the Securities Act of 1933, as amended, or to qualify
or register such shares under any securities laws of any state upon
their issuance under the Plan or at any time thereafter, or to take
any other action in order to cause the issuance and delivery of
such shares under the Plan or any subsequent offer, sale or other
transfer of such shares to comply with any such law, regulation or
requirement. Participants are responsible for complying with all
applicable federal and state securities and other laws, rules and
regulations in connection with any offer, sale or other transfer of
the shares of Common Stock issued under the Plan or any interest
therein including, without limitation, compliance with the
registration requirements of the Securities Act of 1933, as amended
(unless an exemption therefrom is available), or with the
provisions of Rule 144 promulgated thereunder, if applicable, or
any successor provisions. Certificates for shares of Common Stock
may be legended as the Committee shall deem appropriate.
C. Nontransferability of Rights
No Participant shall have the right to assign the right to
receive any Stock Payment or any other right or interest under the
Plan, contingent or otherwise, or to cause or permit any
encumbrance, pledge or charge of any nature to be imposed on any
such Stock Payment (prior to the issuance of stock certificates
evidencing such Stock Payment) or any such right or interest.
D. Severability
In the event that any provision of the Plan is held invalid,
void or unenforceable, the same shall not affect, in any respect
whatsoever, the validity of any other provision of the Plan.
E. Governing Law
To the extent not preempted by Federal law, the Plan shall be
governed by the laws of the State of North Dakota.
Approved by the Board of Directors February 9, 1995
Approved by the Stockholders April 25, 1995
Amended August 17, 1995 and effective October 13, 1995, as to the
three-for-two stock split
MDU RESOURCES GROUP, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
1995 1994 1993 1992 1991
(In thousands of dollars)
Earnings Available for
Fixed Charges:
Net Income per
Consolidated
Statements
of Income $41,633 $39,845 $38,817* $35,371 $38,017
Income Taxes 23,057 18,833 19,982* 10,900 16,808
64,690 58,678 58,799 46,271 54,825
Rents (a) 894 878 871 504 519
Interest (b) 29,924 29,173 27,928 30,056 36,392
Total Available for
Fixed Charges $95,508 $88,729 $87,598* $76,831 $91,736
Fixed Charges (c) $30,818 $30,051 $28,799 $30,560 $36,911
Ratio of Earnings to
Fixed Charges 3.10x 2.95x 3.04x* 2.51x 2.49x
* Before cumulative effect of accounting change of $5,521 (net of
income taxes).
(a) Represents portion (33 1/3%) of rents which is estimated to
approximately constitute the return to the lessors on their
investment in leased premises.
(b) Represents interest and amortization of debt discount and expense
on all indebtedness and excludes amortization of gains or losses
on reacquired debt which, under the Uniform System of Accounts,
is classified as a reduction of, or increase in, interest expense
in the Consolidated Statements of Income. Also includes carrying
costs associated with natural gas available under a repurchase
agreement with Frontier Gas Storage Company as more fully
described in Notes to Consolidated Financial Statements.
(c) Represents rents and interest, both as defined above.
MDU RESOURCES GROUP, INC.
1995 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with generally accepted accounting principles as applied to
the company's regulated and non-regulated businesses and necessarily
include some amounts that are based on informed judgments and
estimates of management.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of internal
accounting controls designed to provide assurance, on a cost-effective
basis, that transactions are carried out in accordance with
management's authorizations and that assets are safeguarded against
loss from unauthorized use or disposition. The system includes an
organizational structure which provides an appropriate segregation of
responsibilities, 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.<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1995 1994 1993
(In thousands, except per share amounts)
Operating Revenues
Electric $134,609 $133,953 $131,109
Natural gas 167,787 160,970 178,981
Construction materials and mining 113,066 116,646 90,397
Oil and natural gas production 48,784 37,959 39,125
464,246 449,528 439,612
Operating Expenses
Fuel and purchased power 41,769 43,203 41,298
Purchased natural gas sold 53,351 52,893 78,121
Operation and maintenance 202,327 203,269 167,374
Depreciation, depletion and
amortization 54,825 48,113 45,162
Taxes, other than income 21,398 23,875 23,565
373,670 371,353 355,520
Operating Income
Electric 29,898 27,596 30,520
Natural gas distribution 6,917 3,948 4,730
Natural gas transmission 25,427 21,281 20,108
Construction materials and mining 14,463 16,593 16,984
Oil and natural gas production 13,871 8,757 11,750
90,576 78,175 84,092
Other income--net 4,789 10,480 3,877
Interest expense 24,690 25,350 25,273
Carrying costs on natural gas
repurchase commitment (Note 3) 5,985 4,627 3,897
Income before income taxes 64,690 58,678 58,799
Income taxes 23,057 18,833 19,982
Income before cumulative effect
of accounting change 41,633 39,845 38,817
Cumulative effect of accounting
change (Note 1) --- --- 5,521
Net income 41,633 39,845 44,338
Dividends on preferred stocks 792 797 802
Earnings on common stock $ 40,841 $ 39,048 $ 43,536
Earnings per common share:
Earnings before cumulative effect
of accounting change $ 1.43 $ 1.37 $ 1.34
Cumulative effect of accounting
change --- --- .19
Earnings $ 1.43 $ 1.37 $ 1.53
Dividends per common share $ 1.08 $ 1.05 $ 1.01
Average common shares outstanding 28,477 28,477 28,477
The accompanying notes are an integral part of these consolidated statements.<PAGE>
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1995 1994 1993
(In thousands)
ASSETS
Property, Plant and Equipment
Electric $ 535,016 $ 514,152 $ 503,690
Natural gas distribution 161,080 157,174 141,100
Natural gas transmission 271,773 263,971 258,766
Construction materials and mining 151,751 147,284 145,014
Oil and natural gas production 167,542 151,532 116,833
1,287,162 1,234,113 1,165,403
Less accumulated depreciation,
depletion and amortization 570,855 541,842 501,451
716,307 692,271 663,952
Current Assets
Cash and cash equivalents 33,398 37,190 71,699
Receivables 61,961 55,409 67,553
Inventories 23,949 27,090 19,415
Deferred income taxes 31,663 26,694 32,243
Prepayments and other
current assets 11,261 12,287 14,262
162,232 158,670 205,172
Natural gas available under
repurchase commitment (Note 3) 70,750 70,913 79,031
Investments (Note 16) 46,188 16,914 16,858
Deferred charges and other assets 61,002 65,950 76,038
$1,056,479 $1,004,718 $1,041,051
CAPITALIZATION AND LIABILITIES
Capitalization (See Separate
Statements)
Common stockholders' investment $ 337,317 $ 327,183 $ 318,131
Preferred stocks 16,900 17,000 17,100
Long-term debt 237,352 217,693 231,770
591,569 561,876 567,001
Commitments and contingencies
(Notes 2, 3, 4, 13 and 15) --- --- ---
Current Liabilities
Short-term borrowings 600 680 9,540
Accounts payable 22,261 20,222 24,967
Taxes payable 13,566 8,817 9,204
Other accrued liabilities,
including reserved revenues 100,779 88,516 107,566
Dividends payable 7,958 7,793 7,605
Long-term debt and preferred
stock due within one year 17,087 20,450 15,300
162,251 146,478 174,182
Natural gas repurchase commitment
(Note 3) 88,200 88,404 98,525
Deferred credits:
Deferred income taxes 118,459 114,341 113,477
Other 96,000 93,619 87,866
214,459 207,960 201,343
$1,056,479 $1,004,718 $1,041,051
The accompanying notes are an integral part of these consolidated statements.<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1995 1994 1993
(In thousands)
Common Stockholders' Investment
Common stock (Note 9):
Authorized-- 75,000,000 shares,
$3.33 par value in 1995
and 1994, 50,000,000
shares, $5 par value
in 1993
Outstanding--28,476,981 shares in 1995,
and 18,984,654 shares in
1994 and 1993 $ 94,828 $ 63,219 $ 94,923
Other paid in capital 64,305 95,914 64,210
Retained earnings (Note 10) 178,184 168,050 158,998
Total common stockholders'
investment 337,317 327,183 318,131
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--20,000 shares
in 1995 (21,000 in 1994 and
22,000 in 1993) 2,000 2,100 2,200
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 17,000 17,100 17,200
Less current maturities and
sinking fund requirements 100 100 100
Net preferred stocks 16,900 17,000 17,100
Long-term Debt (Note 12)
Total long-term debt 254,339 238,043 246,970
Less current maturities and sinking
fund requirements 16,987 20,350 15,200
Net long-term debt 237,352 217,693 231,770
Total capitalization $591,569 $561,876 $567,001
The accompanying notes are an integral part of these consolidated statements.<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1995 1994 1993
(In thousands)
Operating Activities
Net income $ 41,633 $ 39,845 $ 44,338
Cumulative effect of accounting
change --- --- (5,521)
Adjustments to reconcile net income
to net cash provided by operations:
Depreciation, depletion and
amortization 54,825 48,113 45,162
Deferred income taxes and
investment tax credit--net 7,631 3,409 16,197
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 7,177 7,866 8,716
Changes in current assets and
liabilities:
Receivables (6,552) 12,144 (775)
Inventories 3,141 (6,799) (1,201)
Other current assets (3,943) 7,524 12,954
Accounts payable 2,039 (4,745) (430)
Other current liabilities 17,177 (19,249) (8,160)
Other noncurrent changes 1,779 9,705 (14,093)
Net cash provided by operating
activities 124,907 97,813 97,187
Financing Activities
Net change in short-term borrowings (80) (8,860) 1,765
Issuance of long-term debt 36,710 26,750 ---
Repayment of long-term debt (20,433) (35,700) (3,100)
Retirement of preferred stocks (100) (100) (100)
Retirement of natural gas
repurchase commitment (204) (10,121) (16,412)
Dividends paid (31,499) (30,793) (29,659)
Net cash used in financing
activities (15,606) (58,824) (47,506)
Investing Activities
Additions to property, plant and
equipment and acquisitions of
businesses:
Electric (19,689) (14,188) (16,156)
Natural gas distribution (8,878) (19,033) (15,012)
Natural gas transmission (9,688) (6,147) (3,669)
Construction materials and mining (36,810) (3,597) (43,123)
Oil and natural gas production (39,917) (38,595) (24,943)
(114,982) (81,560) (102,903)
Sale of natural gas available
under repurchase commitment 163 8,118 13,007
Investments 1,726 (56) 45,076
Net cash used in investing
activities (113,093) (73,498) (44,820)
Increase (decrease) in cash
and cash equivalents (3,792) (34,509) 4,861
Cash and cash equivalents--
beginning of year 37,190 71,699 66,838
Cash and cash equivalents--
end of year $ 33,398 $ 37,190 $ 71,699
The accompanying notes are an integral part of these consolidated statements.<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 1995, 1994 and 1993
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 its
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.
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 in accordance with the provisions of SFAS
No. 71. All other significant intercompany balances and transactions
have been eliminated where appropriate.
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 was insignificant in 1995, 1994 and 1993.
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, other than the company's partnership investment in
Hawaiian Cement, consist principally of securities held for corporate
development purposes, which are carried at market which approximates
cost.
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 repurchase commitment is carried at
Frontier Gas Storage Company's cost of purchased natural gas, less an
allowance to reflect changed market conditions.
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.
Utility Revenue and Energy Cost
Effective with a January 1, 1993 accounting change, the company began
recognizing revenue each month based on the services provided to all
customers during the month. Prior to 1993, the company recorded
revenue and the cost of purchased natural gas sold when customers were
billed. The cumulative effect of this change on net income for the 12
months ended December 31, 1993, is presented net of applicable income
taxes of $3,355,000.
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 adopted the provisions of SFAS No. 109, "Accounting for
Income Taxes" (SFAS No. 109) on January 1, 1993, and is now providing
deferred federal and state income taxes on all temporary differences.
Effective with the adoption of SFAS No. 109, the company elected
to record the cumulative effect of the accounting change on prior
years in 1993 as allowed by SFAS No. 109, with such amount being
immaterial to its financial position or results of operations. Excess
deferred income tax balances associated with Montana-Dakota's and
Williston Basin's rate-regulated activities have been recorded as a
regulatory liability and are included in "Other deferred credits" in
the company's Consolidated Balance Sheets at December 31, 1995, 1994
and 1993. 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 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, 1995 1994 1993
(In thousands)
Interest, net of amount capitalized $24,436 $22,775 $22,717
Income taxes $18,330 $13,539 $24,545
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 1994 and 1993 to conform to the 1995 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
New Accounting Standard
In March 1995, the Financial Accounting Standards Board issued SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS No. 121
imposes stricter criteria for assets, including regulatory assets, by
requiring that such assets be probable of future recovery at each
balance sheet date. The company will adopt SFAS No. 121 on January 1,
1996, and the adoption will not have a material affect on the
company's financial position or results of operations. This
conclusion may change in the future depending on the extent to which
recovery of the company's long-lived assets is influenced by an
increasingly competitive environment in the electric and natural gas
industries.
NOTE 2
Regulatory Matters and Revenues Subject to Refund
General Rate Proceedings
Williston Basin had pending with the FERC two general natural gas rate
change applications implemented in 1989 and 1992. In May 1994, the
FERC issued an order relating to the 1989 rate change. Williston
Basin requested rehearing of certain issues addressed in the order and
a stay of compliance and refund pending issuance of a final order by
the FERC. The requested stay was denied by the FERC and in July 1994,
Williston Basin refunded $47.8 million to its customers, including
$33.4 million to Montana-Dakota, all of which had been reserved. On
April 5, 1995, the FERC issued an order granting in part and denying
in part Williston Basin's rehearing request. As a result of the
FERC's order, Williston Basin, on May 18, 1995, billed its customers
approximately $2.7 million, plus interest, to recover a portion of the
amount previously refunded in July 1994.
On July 25, 1995, the FERC issued an order relating to Williston
Basin's 1992 rate change application. On August 24, 1995, Williston
Basin filed, under protest, tariff sheets in compliance with the
FERC's order, with rates to be effective September 1, 1995. Williston
Basin requested rehearing of certain issues addressed in the order and
the rehearing is pending before the FERC.
Reserves have been provided for a portion of the revenues that
have been collected subject to refund with respect to pending
regulatory proceedings and 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 Gas Storage Company (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, 1995, borrowings totalled $88.4 million at a weighted
average interest rate of 6.6 percent. The term loan agreement will
terminate on October 2, 1999, subject to an option to renew this
agreement 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 and represent costs
which Williston Basin may not recover. This matter is currently on
appeal. The issue regarding the applicability of assessing storage
charges to the gas creates additional uncertainty as to the costs
associated with holding the gas.
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
December 31, 1995, 17.6 MMdk of this natural gas had been sold by
Williston Basin for use by both on- and off-system markets. Williston
Basin will continue to aggressively market the remaining 43.2 MMdk of
this natural gas whenever market conditions are favorable. In
addition, it will continue to seek long-term sales contracts.
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 has submitted damage
calculations which total approximately $19 million or, under its
alternative pricing theory, approximately $39 million. On March 10,
1995, the Federal District Court issued a summary judgment dismissing
Moncrief's pricing theories and substantially reducing Moncrief's
claims. Trial was held in January 1996, and Williston Basin is
awaiting the Federal District Court's decision.
Moncrief's damage claims, in Williston Basin's opinion, are
grossly overstated. Williston Basin plans to file for recovery from
ratepayers of amounts which may be ultimately due to Moncrief, if any.
On November 27, 1995, a suit was filed in District Court, County
of Burleigh, State of North Dakota (State District Court) by Minnkota
Power Cooperative, Inc., Otter Tail Power Company, Northwestern Public
Service Company and Northern Municipal Power Agency (Co-owners), the
owners of an aggregate 75 percent interest in the Coyote electrical
generating station (Coyote Station), against the company (an owner of
a 25 percent interest in the Coyote Station) and Knife River. In its
complaint, the Co-owners have alleged a breach of contract against
Knife River of the long-term coal supply agreement (Agreement) between
the owners of the Coyote Station and Knife River. The Co-owners have
requested a determination by the State District Court of the pricing
mechanism to be applied to the Agreement and have further requested
damages during the term of such alleged breach on the difference
between the prices charged by Knife River and the prices as may
ultimately be determined by the State District Court. The Co-owners
are also alleging 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 such contract, 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. Such matter is pending before the State
District Court with oral arguments scheduled for April 22, 1996. The
company and Knife River believe they have meritorious defenses and
intend to vigorously defend the suit.
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 June 1990, Montana-Dakota was notified by the EPA that it and
several others were named as Potentially Responsible Parties (PRPs) in
connection with the cleanup of pollution at a landfill site located in
Minot, North Dakota. In June 1993, the EPA issued its decision on the
selected remediation to be performed at the site. Based on the EPA's
proposed remediation plan, estimates of the total cleanup costs,
including oversight costs, at this site range from approximately $3.7
million to $4.8 million. In October 1995, the EPA and the City of
Minot entered into a consent decree which requires the city to
implement as well as assume liability for all cleanup costs associated
with the remediation plan. The remaining liability at this site for
past and future federal government oversight costs has been estimated
by the EPA to be approximately $1 million. Montana-Dakota believes
that it was not a material contributor to this contamination and,
therefore, further believes that its share of the approximately $1
million estimated remaining liability will not have a material effect
on its results of operations.
Electric Purchased Power Commitments
Montana-Dakota has contracted to purchase through October 31, 2006, up
to 66,000 kW of participation power from Basin Electric Power
Cooperative (61,000 kW in 1995). In addition, Montana-Dakota under a
total requirements contract through December 31, 1996, is purchasing
approximately 44,000 kW of power from Pacific Power & Light Company.
Beginning January 1, 1997, Montana-Dakota will purchase up to 55,000
kW of capacity from Black Hills Power and Light Company under a 10-
year power supply contract, subject to approval by the FERC.
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 million at December 31, 1995,
$45 million at December 31, 1994, and $49 million at December 31,
1993. In addition, $6.6 million, $6.9 million and $1.3 million at
December 31, 1995, 1994 and 1993, 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:
1995 1994 1993
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ 15,275 $ 24,069 $ 34,915
Long-term debt refinancing costs 11,082 12,228 13,462
Postretirement benefit costs 4,833 4,551 3,345
Plant costs 3,509 3,678 3,846
Other 7,091 4,664 723
Total regulatory assets 41,790 49,190 56,291
Regulatory liabilities:
Reserves for regulatory matters 58,277 49,427 83,782
Natural gas costs refundable
through rate adjustments 21,192 14,878 ---
Taxes refundable to customers 12,531 12,229 16,836
Plant decommissioning costs 4,777 4,290 3,845
Other 7,205 9,883 656
Total regulatory liabilities 103,982 90,707 105,119
Net regulatory position $(62,192) $(41,517) $(48,828)
As of December 31, 1995, 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 income statement as an extraordinary
item in the period in which the discontinuance of SFAS No. 71 occurs.
NOTE 7
Financial Instruments
Derivatives
The company's operations involve managing market risks related to
changes in commodity prices and interest rates. Derivative financial
instruments, specifically swap and collar agreements, are used to
reduce and manage those risks. The company does not currently hold or
issue financial instruments for trading purposes.
The company periodically enters into swap and collar agreements
to hedge its exposure to commodity price fluctuations in connection
with the operations of Montana-Dakota, Williston Basin and Fidelity
Oil. The company believes that there is a high degree of correlation
because the timing of purchases/production and the hedge agreement are
closely matched, and hedge prices are established in the areas of the
company's operations. Recognized gains and losses on hedge
transactions are matched and reported as a component of the related
transaction.
At December 31, 1995, Montana-Dakota was a party to a natural gas
price collar with a notional amount of 3.7 million MMBtus for the
12 months ended March 1996, at a floor price of $1.22 per MMBtu and at
a cap price of $1.52 per MMBtu. Fidelity Oil was a party to two
natural gas price swaps with a total notional amount of 2.8 million
MMBtus for 1996 at a fixed price of approximately $1.80 per MMBtu.
Fidelity Oil was also a party to a natural gas price collar with a
notional amount of 1.5 million MMBtus for 1996 at a floor price of
$1.80 per MMBtu and a cap price of $2.05 per MMBtu.
Williston Basin has entered into an interest rate swap agreement
related to the natural gas repurchase commitment. The purpose of this
swap is to fix the interest rate on a portion of the variable rate
natural gas repurchase commitment and reduce Williston Basin's
exposure to interest rate fluctuations. At December 31, 1995,
Williston Basin had an interest rate swap with a notional amount of
$20 million. Under this agreement, Williston Basin will pay the
counterparty interest at a fixed rate of 5.97 percent and the
counterparty will pay Williston Basin interest at a rate based on the
three month floating London Interbank Offered Rate (LIBOR). This
transaction was executed for a two-year period beginning August 1995.
The company's hedging transactions did not have a material effect
on its results of operations for the years ended December 31, 1995,
1994 and 1993. There were no derivative financial instruments
outstanding at December 31, 1994.
Fair Value
The estimated fair value of long-term debt and preferred stocks are
based on quoted market prices of the same or similar issues. The
estimated fair value of long-term debt and preferred stocks at
December 31 are as follows:
1995 1994 1993
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
(In thousands)
Long-term
debt $254,339 $274,320 $238,043 $ 233,196 $ 246,970 $ 268,937
Preferred
stocks $ 17,000 $ 10,500 $ 17,100 $ 10,486 $ 17,200 $ 11,090
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 $86.4 million at December 31, 1995. 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 $600,000 at December 31, 1995, $680,000
at December 31, 1994, and $9.5 million at December 31, 1993. The
weighted average interest rate for borrowings outstanding at
December 31, 1995, 1994 and 1993, was 8.5 percent, 8.5 percent and
4.2 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.
On August 17, 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 prior years as set forth in the table
below.
Changes in common stock and other paid in capital during the
years ended December 31, 1995, 1994 and 1993 are summarized below:
Shares Par Other Paid
Outstanding Value In Capital
(In thousands)
Balance at December 31, 1992
and 1993 18,984,654 $94,923 $ 64,210
Reduction in par value --- (31,704) 31,704
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 28,476,981 $94,828 $ 64,305
The company's Dividend Reinvestment Plan (DRIP) provides holders
of all classes of the company's capital stock the opportunity to
invest their cash dividends in shares of common stock and to make
optional cash payments of up to $5,000 per quarter for the same
purpose. The company's Tax Deferred Compensation Savings Plans
pursuant to Section 401(k) of the Internal Revenue Code are funded
with common stock and also participate in the DRIP. Since January 1,
1989, these plans have been funded by the purchase of shares of common
stock on the open market. However, shares of authorized but unissued
common stock may be used for this purpose. At December 31, 1995,
there were 1,530,344 shares of common stock reserved for issuance
under the 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, 1995,
1994 and 1993 are as follows:
1995 1994 1993
(In thousands)
Balance at beginning of year $168,050 $158,998 $144,319
Net income 41,633 39,845 44,338
209,683 198,843 188,657
Deduct:
Dividends declared--
Preferred stocks at required
annual rates 792 797 802
Common stock 30,707 29,996 28,857
31,499 30,793 29,659
Balance at end of year $178,184 $168,050 $158,998
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, 1995, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1995 1994 1993
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 50,000 $ 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:
5.80%, due April 1, 1994 --- --- 15,000
6.30%, due April 1, 1995 --- 10,000 10,000
6.95%, due April 1, 1996 10,000 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 170,850 180,850 195,850
Pollution control lease and note
obligation, 6.2%, due
March 1, 2004 4,300 4,600 4,800
Senior notes:
7.35%, due July 31, 2002 5,000 --- ---
8.43%, due December 31, 2000 15,000 15,000 15,000
Revolving lines of credit:
8.50%, expires December 31, 1998 21,500 17,000 30,000
6.375%, expires August 25, 2001 25,000 --- ---
8.50%, expires January 13, 2002 2,000 3,000 1,500
Term credit facilities:
5.95%, due March 31, 1997 7,500 17,500 ---
7.70%, due December 1, 2003 1,800 --- ---
Other term credit facilities at
rates ranging from 8.0% to 9.0%,
due from 1998 through 2000 1,527 250 ---
Other (138) (157) (180)
Total long-term debt 254,339 238,043 246,970
Less current maturities and sinking
fund requirements 16,987 20,350 15,200
Net long-term debt $237,352 $217,693 $231,770
Under the revolving lines of credit, the company has $95 million
available, $48.5 million of which was outstanding at December 31,
1995. The amounts of long-term debt maturities and sinking fund
requirements for the five years following December 31, 1995, aggregate
$17.0 million in 1996; $16.5 million in 1997; $32.8 million in 1998;
$11.3 million in 1999 and $14.5 million in 2000. 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 $200 million of additional
first mortgage bonds at December 31, 1995.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1995 1994 1993
(In thousands)
Current:
Federal $20,259 $11,995 $25,665
State 3,801 2,644 3,997
Foreign 369 210 10
24,429 14,849 29,672
Deferred:
Investment tax credit--net (1,028) (1,137) (1,144)
Income taxes--
Federal (564) 4,589 (9,560)
State 220 532 1,014
(1,372) 3,984 (9,690)
Total income tax expense $23,057 $18,833 $19,982
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1995 1994 1993
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 36,894 $ 33,076 $ 48,412
Natural gas available under
repurchase commitment 6,762 6,778 7,554
Accrued pension costs 7,039 5,646 4,955
Deferred investment tax credits 3,623 4,022 4,462
Accrued land reclamation 4,033 4,256 4,017
Natural gas costs refundable
through rate adjustments 6,125 4,034 ---
Other 11,321 10,220 5,043
Total deferred tax assets 75,797 68,032 74,443
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 119,078 115,966 115,517
Basis differences on oil and
natural gas producing properties 28,113 21,049 15,889
Natural gas contract settlement and
restructuring costs 5,413 9,327 13,530
Long-term debt refinancing costs 4,524 4,745 5,223
Other 5,465 4,592 5,518
Total deferred tax liabilities 162,593 155,679 155,677
Net deferred income tax liability $(86,796) $(87,647) $(81,234)
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:
1995 1994
(In thousands)
Net change in deferred income tax liability
from the preceding table $(851) $ 6,413
Change in tax effects of income tax-related
regulatory assets and liabilities 507 (1,292)
Deferred income tax expense for the period $(344) $ 5,121
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:
1995 1994 1993
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $22,642 35.0 $20,537 35.0 $20,580 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,346) (2.1) (1,454) (2.5) (1,424) (2.4)
State income
taxes--net of
federal income tax
benefit 2,492 3.9 2,337 4.0 2,171 3.7
Investment tax credit
amortization (1,028) (1.6) (1,137) (1.9) (1,144) (2.0)
Other items 297 .4 (1,450) (2.5) (201) (.3)
Actual taxes $23,057 35.6 $18,833 32.1 $19,982 34.0
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 is claiming a lower level of taxes due, plus interest as well
as penalties. In 1992 and the first quarter of 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
is related to the tax treatment of deductions claimed in connection
with certain investments made by Knife River and Fidelity Oil.
The company intends to contest vigorously the deficiencies
proposed by the IRS and, in that regard, has timely filed protests for
the 1983 through 1991 tax years contesting the treatment proposed in
the notices of proposed deficiency. Although it is reasonably
possible that the ultimate resolution of such matters could result in
a loss of up to approximately $21 million in excess of consolidated
reserves, management believes the company has meritorious defenses to
mitigate or eliminate the proposed deficiencies. In that regard, the
company's tax counsel has issued opinions related to the principal
issue discussed above, stating that it is more likely than not that
the company would prevail in this matter.
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, 1995, 1994 and
1993, is presented in the Consolidated Statements of Income. Other
segment information is presented below:
1995 1994 1993
(In thousands)
Depreciation, depletion and
amortization:
Electric $ 16,361 $ 15,513 $ 15,307
Natural gas distribution 6,719 6,118 5,114
Natural gas transmission 6,940 6,590 7,113
Construction materials
and mining 6,199 6,394 5,594
Oil and natural gas production 18,606 13,498 12,034
Total depreciation, depletion
and amortization $ 54,825 $ 48,113 $ 45,162
Investment information:
Identifiable assets--
Electric (a) $ 312,559 $ 307,861 $ 306,179
Natural gas distribution (a) 126,452 124,275 104,013
Natural gas transmission (a) 303,219 311,992 383,355
Construction materials
and mining 141,505 116,347 120,105
Oil and natural gas
production 133,289 106,631 89,690
Total identifiable assets 1,017,024 967,106 1,003,342
Corporate assets (b) 39,455 37,612 37,709
Total consolidated assets $1,056,479 $1,004,718 $1,041,051
(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 1995 (6 percent in 1994 and 7 percent in 1993) represent
Knife River's direct sales of lignite coal to the company. The
company's share of Knife River's sales for use at two generating
stations jointly owned by the company and other utilities was
approximately 7 percent of construction materials and mining revenues
in 1995, 8 percent in 1994 and 10 percent in 1993.
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:
1995 1994 1993
(In thousands)
Service cost/benefits earned during
the year $ 3,538 $ 4,035 $ 3,277
Interest cost on projected benefit
obligation 10,784 9,912 9,488
Loss (return) on plan assets (37,185) 3,154 (14,540)
Net amortization and deferral 24,407 (15,410) 2,916
Special termination benefit cost 853 --- ---
Total pension costs 2,397 1,691 1,141
Less amounts capitalized 184 198 133
Total pension expense $ 2,213 $ 1,493 $ 1,008
The funded status of the company's plans at December 31 is
summarized as follows:
1995 1994 1993
(In thousands)
Projected benefit obligation:
Vested $121,879 $105,561 $108,718
Nonvested 4,731 4,124 4,696
Accumulated benefit obligation 126,610 109,685 113,414
Provision for future pay increases 28,114 25,084 26,379
Projected benefit obligation 154,724 134,769 139,793
Plan assets at market value 170,793 139,332 149,184
(16,069) (4,563) (9,391)
Plus:
Unrecognized transition asset 8,326 9,315 10,305
Unrecognized net gains and prior
service costs 14,686 2,466 4,953
Accrued pension costs $ 6,943 $ 7,218 $ 5,867
The projected benefit obligation was determined using an assumed
discount rate of 7 1/4 percent (8 percent in 1994 and 7 percent in
1993) and assumed long-term rates for estimated compensation increases
of 4 1/2 percent (5 percent in 1994 and 4 1/2 percent in 1993). The
change in these assumptions had the effect of increasing the projected
benefit obligation at December 31, 1995, by $12 million but decreasing
the projected benefit obligation at December 31, 1994, by $16 million.
The assumed long-term rate of return on plan assets is 8 1/2 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. On January 1, 1993, the company
adopted SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" (SFAS No. 106). The company elected to
amortize the transition obligation of approximately $49 million at
January 1, 1993, which represents the accumulated postretirement
benefit obligation at the time of adoption, over 20 years as provided
by SFAS No. 106. 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:
1995 1994 1993
(In thousands)
Service cost/benefits earned during
the year $1,226 $1,454 $ 1,098
Interest cost on accumulated
postretirement benefit obligation 4,777 4,584 3,932
Return on plan assets (183) (176) ---
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral (719) 76 ---
Total postretirement benefits cost 7,559 8,396 7,488
Less amounts capitalized 442 419 ---
Total postretirement benefits expense $7,117 $7,977 $ 7,488
The funded status of the company's plans at December 31 is
summarized as follows:
1995 1994 1993
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $43,543 $36,985 $31,029
Active employees fully eligible for
benefits 66 22 ---
Active employees not fully eligible 26,229 22,898 28,592
Total 69,838 59,905 59,621
Plan assets at market value 15,095 9,938 4,450
54,743 49,967 55,171
Less:
Unrecognized transition obligation 41,779 44,237 46,694
Unrecognized net losses 12,066 4,896 7,992
Accrued postretirement benefits cost $ 898 $ 834 $ 485
The health plan cost trend rate assumed in determining the
accumulated postretirement benefit obligation was 12 percent in 1993,
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, 1995, by $3.5
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $253,000.
The accumulated postretirement benefit obligation was determined
using an assumed discount rate of 7 1/4 percent at December 31, 1995,
8 percent at December 31, 1994, and 7 percent at December 31, 1993,
and assumed long-term rates for estimated compensation increases, as
they apply to life insurance benefits, of 4 1/2 percent (5 percent at
December 31, 1994, and 4 1/2 percent at December 31, 1993). The
change in these assumptions had the effect of increasing the
accumulated postretirement benefit obligation at December 31, 1995, by
$7 million but decreasing the accumulated postretirement benefit
obligation at December 31, 1994, by $9 million. The assumed long-term
rate of return on assets is 7 1/2 percent. Plan assets consist
primarily of 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 $1.9 million in 1995, $1.7 million in 1994 and $1.4
million in 1993.
The company has a Key Employee Stock Option Plan under which the
company is authorized to grant options for up to 1.2 million shares of
common stock with an option price equal to market value on the date of
grant. The company has contributed $4.3 million to a trust
established to fund its commitment under the Plan.
Transactions involving option shares for the Key Employee Stock
Option Plan are as follows:
Options Price
Balance at December 31, 1992 292,199 $12.25-$15.75
Granted 4,830 17.58-20.83
Forfeited (8,595) 15.75
Exercised (22,470) 12.25
Balance at December 31, 1993 265,964 15.75-20.83
Granted ---
Forfeited (73,680) 15.75-17.58
Exercised ---
Balance at December 31, 1994 192,284 15.75-20.83
Granted 294,956 18.50
Forfeited (2,700) 20.83
Exercised (15,803) 15.75
Balance at December 31, 1995 468,737 15.75-18.50
Exercisable at December 31, 1995 138,524 15.75
Available for future grant at
December 31, 1995 715,460
The company has Tax Deferred Compensation Savings Plans for
eligible employees. Each participant may contribute amounts up to 10
percent of eligible compensation (15 percent effective January 1,
1996), 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 1995 and 1994, and $1.7
million in 1993.
NOTE 16
Partnership Investment
In September 1995, KRC Holdings, Inc. (a wholly owned subsidiary of
Knife River) 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, 1995, while its share of operating results is included in
"Other income--net" in the accompanying Consolidated Statements of
Income for the year ended December 31, 1995. Summarized financial
information for Hawaiian Cement, which is not consolidated and is
accounted for by the equity method, as of and for the four months
ended December 31, 1995, as applicable, is as follows:
(In thousands)
Current assets $19,531
Property, plant and equipment, net 70,544
Current liabilities 14,209
Other liabilities 15,736
Net sales 24,433
Operating margin 5,096
Income before income taxes 2,757
The company's original investment in Hawaiian Cement at the date
of acquisition exceeded the underlying net assets by $10.4 million.
The excess is being amortized over 30 years.
NOTE 17
Jointly Owned Facilities
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets,
liabilities and expenses of the Big Stone Station and the Coyote
Station, respectively. Each owner of the Big Stone and Coyote
stations is responsible for 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:
1995 1994 1993
(In thousands)
Big Stone Station:
Utility plant in service $ 47,687 $ 46,923 $ 47,349
Accumulated depreciation 27,026 25,505 24,663
$ 20,661 $ 21,418 $ 22,686
Coyote Station:
Utility plant in service $122,126 $121,784 $121,380
Accumulated depreciation 49,296 45,546 42,482
$ 72,830 $ 76,238 $ 78,898
NOTE 18
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1995 and 1994:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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
1994
Operating revenues $124,362 $105,036 $106,528 $113,602
Operating expenses 99,847 89,880 87,618 94,008
Operating income 24,515 15,156 18,910 19,594
Net income 11,699 5,677 12,351 10,118
Earnings per common share .40 .19 .43 .35
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 holds oil and natural gas interests primarily through a
series of working-interest agreements with several oil and natural gas
producers and through operating agreements with Shell Western E & P,
Inc. (Shell).
Fidelity Oil undertakes ventures, through working-interest
agreements with selected operators. These ventures vary from the
acquisition of producing properties with potential development
opportunities to exploration and are located in the western United
States, offshore in the Gulf of Mexico and in Canada. In these
ventures, Fidelity Oil shares revenues and expenses from the
development of specified properties in proportion to its investments.
Fidelity Oil has net proceeds interests in the production of oil
and natural gas and has an operating agreement (Agreement) with Shell
applicable to certain of its acreage interests. Pursuant to the
Agreement, Shell, as operator, controls all development, production,
operations and marketing applicable to such acreage. As a net
proceeds interest owner, Fidelity Oil is entitled to proceeds only
when a particular unit has reached payout status.
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:
1995 1994 1993
(In thousands)
Subject to amortization $173,501 $155,303 $114,572
Not subject to amortization 8,831 8,530 2,022
Total capitalized costs 182,332 163,833 116,594
Accumulated depreciation, depletion
and amortization 49,498 54,376 36,084
Net capitalized costs $132,834 $109,457 $ 80,510
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:
1995 1994 1993
(In thousands)
Acquisitions $ 9,402 $ 5,542 $ 9,296
Exploration 7,730 13,241 7,787
Development 25,403 21,189 7,836
Total capital expenditures $42,535 $39,972 $24,919
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:
1995 1994 1993
(In thousands)
Revenues* $53,484 $45,053 $39,125
Production costs 16,888 18,463 13,700
Depreciation, depletion and
amortization 19,058 13,926 11,998
Pretax income 17,538 12,664 13,427
Income tax expense 6,397 4,257 4,606
Results of operations for
producing activities $11,141 $ 8,407 $ 8,821
* Includes $4.7 million and $7.1 million of revenues for 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, 1995,
1994 and 1993 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.
1995 1994 1993
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 12,500 154,200 11,200 50,300 12,200 37,200
Production (2,000)(16,800) (1,600) (9,200) (1,500) (8,800)
Extensions and
discoveries 1,800 23,800 1,300 17,800 600 10,600
Purchases of proved
reserves 1,100 6,700 600 2,900 500 9,200
Sales of reserves
in place (300) (200) (400) (2,700) (300) (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 1,100 11,300 1,400 95,100* (300) 2,200
Balance at end of year 14,200 179,000 12,500 154,200 11,200 50,300
*Includes 99,300 MMcf of Williston Basin's natural gas reserves.
Proved developed reserves:
January 1, 1993 11,800 36,500
December 31, 1993 11,100 43,100
December 31, 1994 12,200 147,200**
December 31, 1995 13,600 156,400
**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, 1995, applicable to the company's $9.8
million gross investment in oil and natural gas properties located in
Canada comprise approximately 3 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:
1995 1994 1993
(In thousands)
Future net cash flows before
income taxes $267,300 $197,900 $119,800
Future income tax expenses 76,100 48,800 15,600
Future net cash flows 191,200 149,100 104,200
10% annual discount for estimated
timing of cash flows 70,300 54,200 32,600
Discounted future net cash flows
relating to proved oil and natural
gas reserves $120,900 $ 94,900 $ 71,600
The following are the sources of change in the standardized
measure of discounted future net cash flows by year:
1995 1994 1993
(In thousands)
Beginning of year $ 94,900 $ 71,600 $ 76,700
Net revenues from production (36,400) (23,800) (26,000)
Change in net realization 26,600 (4,100) (24,000)
Extensions, discoveries and improved
recovery, net of future
production-related costs 31,100 31,700 16,800
Purchases of proved reserves 10,900 5,800 14,100
Sales of reserves in place (1,000) (3,700) (1,600)
Changes in estimated future
development costs--net of those
incurred during the year (8,900) (2,900) (3,800)
Accretion of discount 12,300 8,300 8,900
Net change in income taxes (17,100) (4,000) 6,000
Revisions of previous quantity
estimates 8,700 16,500* 4,400
Other (200) (500) 100
Net change 26,000 23,300 (5,100)
End of year $120,900 $ 94,900 $ 71,600
*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>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1995, 1994 and 1993,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1995. 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, 1995,
1994 and 1993, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
1995, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 15 to the consolidated financial
statements, effective January 1, 1993, the company changed its method
of accounting for recording electric and natural gas distribution
revenues, postretirement benefits other than pensions and income
taxes.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Minneapolis, Minnesota
January 24, 1996<PAGE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1995 1994 1993
Selected Financial Data
Operating revenues: (000's)
Electric $ 134,609 $ 133,953 $ 131,109
Natural gas 167,787 160,970 178,981
Construction materials and mining 113,066 116,646 90,397
Oil and natural gas production 48,784 37,959 39,125
$ 464,246 $ 449,528 $ 439,612
Operating income: (000's)
Electric $ 29,898 $ 27,596 $ 30,520
Natural gas distribution 6,917 3,948 4,730
Natural gas transmission 25,427 21,281 20,108
Construction materials and mining 14,463 16,593 16,984
Oil and natural gas production 13,871 8,757 11,750
$ 90,576 $ 78,175 $ 84,092
Earnings (loss) on common
stock: (000's)
Electric $ 12,000 $ 11,719 $ 12,652*
Natural gas distribution 1,604 285 1,182*
Natural gas transmission 8,416 6,155 4,713
Construction materials and mining 10,819 11,622 12,359
Oil and natural gas production 8,002 9,267 7,109
Earnings on common stock
before cumulative effect of
accounting change 40,841 39,048 38,015*
Cumulative effect of
accounting change --- --- 5,521
$ 40,841 $ 39,048 $ 43,536
Earnings per common share before
cumulative effect of
accounting change $ 1.43 $ 1.37 $ 1.34*
Cumulative effect of accounting
change --- --- .19
$ 1.43 $ 1.37 $ 1.53
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 41,633 $ 39,845 $ 38,817
Earnings per common share $ 1.43 $ 1.37 $ 1.34
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.08 $ 1.05 $ 1.01
Book value per common share $ 11.85 $ 11.49 $ 11.17
Market price ratios:
Dividend payout 76% 77% 76%*
Yield 5.5% 5.9% 5.0%
Price/earnings ratio 13.9x 13.2x 15.8x*
Market value as a percent of
book value 167.7% 157.4% 188.0%
Profitability Indicators
Return on average common equity 12.3% 12.1% 12.3%*
Return on average invested capital 9.2% 9.1% 9.4%*
Interest coverage 3.9x 3.3x 3.4x*
Fixed charges coverage, including
preferred dividends 3.0x 2.9x 3.0x*
General
Total assets (000's) $1,056,479 $1,004,718 $1,041,051
Net long-term debt (000's) $ 237,352 $ 217,693 $ 231,770
Redeemable preferred stock (000's) $ 2,000 $ 2,100 $ 2,200
Capitalization ratios:
Common stockholders' investment 57% 58% 56%
Preferred stocks 3 3 3
Long-term debt 40 39 41
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the accrual
of estimated unbilled revenues.
<PAGE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1992 1991 1990
Selected Financial Data
Operating revenues: (000's)
Electric $ 123,908 $128,708 $124,156
Natural gas 159,438 173,865 151,599
Construction materials and mining 45,032 41,201 38,276
Oil and natural gas production 33,797 33,939 31,213
$ 362,175 $377,713 $345,244
Operating income: (000's)
Electric $ 30,188 $ 34,647 $ 32,221
Natural gas distribution 4,509 8,518 6,578
Natural gas transmission 21,331 19,904 19,362
Construction materials and mining 11,532 9,682 7,749
Oil and natural gas production 9,499 12,552 12,523
$ 77,059 $ 85,303 $ 78,433
Earnings (loss) on common
stock: (000's)
Electric $ 13,302 $ 15,292 $ 14,280
Natural gas distribution 1,370 3,645 2,704
Natural gas transmission 3,479 449 (7,578)*
Construction materials and mining 10,662 9,809 9,632
Oil and natural gas production 5,751 8,010 8,071
Earnings on common stock
before cumulative effect of
accounting change 34,564 37,205 27,109*
Cumulative effect of
accounting change --- --- ---
$ 34,564 $ 37,205 $ 27,109*
Earnings per common share before
cumulative effect of
accounting change $ 1.21 $ 1.31 $ .95*
Cumulative effect of accounting
change --- --- ---
$ 1.21 $ 1.31 $ .95*
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 35,852 $ 37,619 $ 28,395*
Earnings per common share $ 1.23 $ 1.29 $ .97*
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ .97 $ .96 $ .95
Book value per common share $ 10.66 $ 10.42 $ 10.08
Market price ratios:
Dividend payout 80% 73% 99%*
Yield 5.6% 5.8% 6.9%
Price/earnings ratio 14.5x 12.6x 14.3x*
Market value as a percent of
book value 165.0% 157.7% 135.6%
Profitability Indicators
Return on average common equity 11.6% 12.7% 9.4%*
Return on average invested capital 8.7% 9.6% 7.8%*
Interest coverage 3.3x 3.8x** 2.7x*
Fixed charges coverage, including
preferred dividends 2.4x 2.4x 1.9x*
General
Total assets (000's) $1,024,510 $964,691 $959,946
Net long-term debt (000's) $ 249,845 $220,623 $229,786
Redeemable preferred stock (000's) $ 2,300 $ 2,400 $ 2,500
Capitalization ratios:
Common stockholders' investment 53% 56% 54%
Preferred stocks 3 3 3
Long-term debt 44 41 43
100% 100% 100%
* Reflects a $6.8 million or 24 cent per share after-tax effect of an
absorption of certain natural gas contract litigation settlement costs.
** Calculation reflects the provisions of the company's restatement of its
Indenture of Mortgage effective April 1992.<PAGE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1995 1994 1993
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,993,693 1,955,136 1,893,713
Sales for resale (thousand kWh) 408,011 444,492 510,987
Electric system generating and
firm purchase capability--kW
(Interconnected system) 472,400 470,900 465,200
Demand peak--kW
(Interconnected system) 412,700 369,800 350,300
Electricity produced
(thousand kWh) 1,718,077 1,901,119 1,870,740
Electricity purchased
(thousand kWh) 867,524 700,912 701,736
Cost of fuel and purchased
power per kWh $.016 $.017 $.016
Natural Gas Distribution Operations
Sales (Mdk) 33,939 31,840 31,147
Transportation (Mdk) 11,091 9,278 12,704
Weighted average degree days--% of
previous year's actual 105% 92% 115%
Energy Marketing Operations
Natural gas volumes (Mdk) 3,556 7,301 6,827
Propane (thousand gallons) 7,471 6,462 2,210
Natural Gas Transmission Operations
Sales for resale (Mdk) --- --- 13,201
Transportation (Mdk) 68,015 63,870 59,416
Produced (Mdk) 4,981 4,732 3,876
Net recoverable reserves (MMcf) 113,000 99,300 ---
Construction Materials and
Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,904 2,688 2,391
Asphalt (tons sold) 373 391 141
Ready-mixed concrete (cubic
yards sold) 307 315 157
Recoverable aggregate reserves
in tons 68,000 71,000 74,200
Coal: (000's)
Sales in tons 4,218 5,206 5,066
Recoverable reserves in tons 231,900 236,100 230,600
Oil and Natural Gas Production
Operations
Production:
Oil (000's of barrels) 1,973 1,565 1,497
Natural gas (MMcf) 12,319 9,228 8,817
Average sales prices:
Oil (per barrel) $15.07 $ 13.14 $14.84
Natural gas (per Mcf) $ 1.51 $ 1.84 $ 1.86
Net recoverable reserves:
Oil (000's of barrels) 14,200 12,500 11,200
Natural gas (MMcf) 66,000 54,900 50,300
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1992 1991 1990
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,829,933 1,877,634 1,820,150
Sales for resale (thousand kWh) 352,550 331,314 285,564
Electric system generating and
firm purchase capability--kW
(Interconnected system) 460,200 454,400 451,600
Demand peak--kW
(Interconnected system) 339,100 387,100 381,600
Electricity produced
(thousand kWh) 1,774,322 1,736,187 1,674,648
Electricity purchased
(thousand kWh) 593,612 611,884 573,099
Cost of fuel and purchased
power per kWh $.016 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 26,681 30,074 28,278
Transportation (Mdk) 13,742 12,261 11,806
Weighted average degree days--% of
previous year's actual 98% 101% 88%
Energy Marketing Operations
Natural gas volumes (Mdk) 3,292 991 1,853
Propane (thousand gallons) --- --- ---
Natural Gas Transmission Operations
Sales for resale (Mdk) 16,841 19,572 19,658
Transportation (Mdk) 64,498 53,930 50,809
Produced (Mdk) 3,551 3,742 1,881
Net recoverable reserves (MMcf) --- --- ---
Construction Materials and
Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 263 --- ---
Asphalt (tons sold) --- --- ---
Ready-mixed concrete (cubic
yards sold) --- --- ---
Recoverable aggregate reserves
in tons 20,600 --- ---
Coal: (000's)
Sales in tons 4,913 4,731 4,439
Recoverable reserves in tons 235,700 256,700 261,500
Oil and Natural Gas Production
Operations
Production:
Oil (000's of barrels) 1,531 1,491 1,374
Natural gas (MMcf) 5,024 2,565 1,846
Average sales prices:
Oil (per barrel) $16.74 $19.90 $20.11
Natural gas (per Mcf) $ 1.53 $ 1.48 $ 1.63
Net recoverable reserves:
Oil (000's of barrels) 12,200 11,600 12,400
Natural gas (MMcf) 37,200 27,500 16,100
SUBSIDIARIES OF MDU RESOURCES GROUP, INC.
December 31, 1995
State or Other
Jurisdiction
in Which
Incorporated
Alaska Basic Industries, Inc. Alaska
Anchorage Sand and Gravel Company, Inc. Alaska
Centennial Energy Holdings, Inc. Delaware
Concrete, Inc. California
Customer One, Inc. Delaware
Fidelity Oil Co. Delaware
Fidelity Oil Holdings, Inc. Delaware
Prairie Propane, Inc. Delaware
Knife River Coal Mining Company Minnesota
Knife River Hawaii, Inc. Delaware
Knife River Marine, Inc. Delaware
KRC Aggregate, Inc. Delaware
KRC Holdings, Inc. Delaware
LTM, Incorporated Oregon
Pompano Marine Chartering, Inc. Florida
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 24, 1996 included in the MDU Resources Group, Inc. Annual
Report to Stockholders for 1995. We also consent to the
incorporation of our report incorporated by reference in this
Form 10-K into the Company's previously filed Registration
Statements on Form S-3, No. 33-46605 and No. 33-66682, and on
Form S-8, No. 33-54486, No. 33-53896 and No. 33-53898.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
February 28, 1996
<PAGE>
CONSENT OF ENGINEER
We hereby consent to the reference to our estimates dated
January 9 and 23, 1996, appearing in this Annual Report on Form
10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and
No. 33-66682, and on Form S-8, No. 33-54486, No. 33-53896 and
No. 33-53898 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, 1996
<PAGE>
CONSENT OF ENGINEER
We hereby consent to the reference to our report dated
May 9, 1994, appearing in this Annual Report on Form 10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and
No. 33-66682, and on Form S-8, No. 33-54486, No. 33-53896 and
No. 33-53898 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, 1996
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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.
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<NAME> MDU RESOURCES GROUP INC.
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