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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.
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
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.
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.
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.
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.
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.
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
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.