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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, 1994
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 (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes X . No __.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. X
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 24, 1995: $510,213,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 24, 1995: 18,984,654 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 27 through 53 of the Annual Report to Stockholders for 1994,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 6, 1995, incorporated in Part III,
Items 10, 11, 12 and 13 of this Report.
CONTENTS
PART I
Items 1 and 2 -- Business and Properties
General 2
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 Mining and Construction Materials
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 255 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., surface mines and markets aggregates
and related construction materials in the Anchorage,
Alaska area, southern Oregon and north-central
California.
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, Gwinner Propane,
Inc., operating bulk propane facilities in
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.
Details applicable to the Company's continuing construction
program and the expansion of the Company's non-regulated mining and
construction materials, and oil and natural gas production
operations are discussed in the sections devoted to each business.
See Item 7 -- "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a discussion of "Liquidity
and Capital Commitments" and the anticipated level of funds to be
generated internally for these activities.
All of the Company's electric and natural gas distribution
properties, with certain exceptions, are subject to the lien of the
Indenture of Mortgage dated May 1, 1939, as supplemented and
amended, from the Company to The Bank of New York and W. T.
Cunningham, successor trustees.
As of December 31, 1994, the Company had 2,053 full-time
employees with 94 employed at MDU Resources Group, Inc., including
Fidelity Oil and Prairielands, 1,208 at Montana-Dakota, 281 at
Williston Basin, 184 at Knife River's coal operations and 286 at
Knife River's construction materials operations. Approximately 567
and 89 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 August 1995, for Montana-Dakota and December 1996,
for Williston Basin. Knife River's coal operations have a labor
contract through August 1995, with the United Mine Workers of
America, which represents its hourly workforce approximating 126
employees. Knife River's construction materials operations have
eight labor contracts covering 155 employees. These contracts have
expiration dates ranging from December 1995, to May 1997.
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 27 through 51 in
the Company's Annual Report to Stockholders for 1994 (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 111,000 residential, commercial, industrial and municipal
customers located in 176 communities and adjacent rural areas as of
December 31, 1994. 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, System Demand and Competition", and over 3,100
miles and 3,800 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, 1994, Montana-Dakota's
net electric plant investment approximated $276.0 million.
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. These operations, including 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 1994 electric utility retail
operating revenues by jurisdiction is as follows: North Dakota --
60%; Montana -- 23%; South Dakota -- 8% and Wyoming -- 9%.
System Supply, System Demand and Competition --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and their 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
(including interests in the Big Stone Station and the Coyote
Station aggregating 22.7% and 25.0%, respectively) which have an
aggregate turbine nameplate rating attributable to Montana-Dakota's
interest of 394,588 Kilowatts (kW) and a total summer net
capability of 414,911 kW. The four principal generating stations
are steam-turbine generating units using lignite coal for fuel.
The nameplate rating for Montana-Dakota's ownership interest in
these four plants 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 ultimately up to 66,000 kW of
participation power from Basin Electric Power Cooperative (Basin)
(56,000 kW in 1994) for its interconnected system as described
herein. The following table sets forth details applicable to the
Company's electric generating stations:
Nameplate Summer 1994 Net
Generating Rating Capability Generation
Station Type (kW) (kW) (MWh)
North Dakota --
Coyote* Steam 103,647 106,500 620,714
Heskett Steam 86,000 102,000 442,911
Williston Combustion
Turbine 7,800 10,000 (38)**
South Dakota --
Big Stone* Steam 94,111 102,511 570,058
Montana --
Lewis & Clark Steam 44,000 43,800 256,582
Glendive Combustion
Turbine 34,780 30,100 7,053
Miles City Combustion
Turbine 24,250 20,000 3,839
394,588 414,911 1,901,119
*Reflects Montana-Dakota's ownership interest.
**Station use exceeded generation.
Virtually all of the current fuel requirements of Montana-
Dakota's principal generating stations are met with lignite coal
supplied by Knife River under various long-term contracts. See
below for a further discussion of the nonrenewal of the Big Stone
Station coal contract with Knife River.
During the years ended December 31, 1990, through December 31,
1994, the average cost of lignite 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 lignite coal so consumed was as
follows:
Years Ended December 31,
1994 1993 1992 1991 1990
Average cost of
lignite coal per
million Btu. . . . $.97 $.96 $.97 $.99 $.98
Average cost of
lignite coal
per ton. . . . . . $12.88 $12.78 $12.79 $13.06 $13.10
In recent years, Knife River, in response to competitive
pressure, has reduced its coal prices and/or not passed through
cost increases which are allowed under the contracts. These price
concessions have allowed Montana-Dakota to be more competitive in
the Mid-Continent Area Power Pool (MAPP).
In June 1994, the owners of the Big Stone Station notified
Knife River that its contract for supplying approximately 2.1
million tons of lignite coal annually would not be renewed upon
expiration in mid-1995. To replace this coal supply, the Big Stone
Station owners entered into a contract with Westmoreland Resources,
Inc. (Westmoreland), which becomes effective immediately upon
termination of the existing contract and expires on December 31,
1999. Under the new contract, the Big Stone Station will purchase
from Westmoreland a minimum of 1.2 million tons annually with a
maximum not to exceed 2 million tons. Any fuel requirements which
exceed the amounts purchased from Westmoreland are expected to be
satisfied through spot market purchases.
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 387,100 kW in July 1991. The 1994 summer peak was
369,800 kW. Montana-Dakota's latest forecast for its
interconnected system indicates that its annual peak will continue
to occur during the summer and the peak demand growth rate through
1999 will approximate 2.1% annually. Kilowatt-hour (kWh) sales
have increased approximately 1.3% annually during the most recent
five years. Montana-Dakota's latest forecast indicates that its
sales growth rates through 1999 will approximate .9% annually.
Montana-Dakota has a participation power contract through
October 31, 2006, with Basin for the ultimate purchase of up to
approximately 66,000 kW (14.8% of the unit's maximum net capacity)
from the Antelope Valley Station II, a lignite coal-fired
generating station located near Beulah, North Dakota. Currently
Montana-Dakota purchases 56,000 kW of such capacity and, under the
terms of the contract, Montana-Dakota will purchase, on an
incremental basis, an additional 5,000 kW of capacity each year for
the years 1995 and 1996 for a total of 66,000 kW annually for the
period 1996 through October 31, 2006. The contract requires the
payment of a fixed monthly demand charge in addition to a per unit
charge for power actually purchased.
Montana-Dakota anticipates having a summer capacity position
(after providing for the 15% MAPP reserve requirement) as follows:
1995 -- 21,000 kW reserve; 1996 -- 22,000 kW reserve; 1997 --
18,000 kW reserve; 1998 -- 14,000 kW reserve and 1999 -- 8,000 kW
reserve.
Montana-Dakota has major interconnections with its neighboring
utilities, all of whom are 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. That
system is supplied through an interconnection with Pacific Power &
Light Company under a supply contract through December 31, 1996.
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 the
implementation of a peak shaving load management system, Montana-
Dakota estimates this annual peak will not be exceeded through
1998.
On September 9, 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.
Montana-Dakota has in place integrated resource plans which are
used in planning for a reliable future supply of electricity which
will coincide with anticipated customer demand. On the supply
side, Montana-Dakota currently estimates that it has adequate
capacity available through existing generating stations and long-
term firm purchase contracts until approximately the year 2005. On
the demand side, Montana-Dakota currently offers rate and other
incentives to its customers designed to promote conservation, load
shifting and peak shaving efforts. The development and evaluation
of other economically feasible strategic marketing programs
continues. Montana-Dakota has filed, as required pursuant to
established filing requirements, its integrated resource plans with
the Montana, North Dakota and Wyoming public service commissions.
The electric utility industry has become, and can be expected
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
generation subsidiaries to supply additional electric demand
without being restricted by the Public Utility Holding Company Act
of 1935. As a result of competition in electric generation,
wholesale power markets have become increasingly competitive. In
addition, 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, subject to certain conditions. To date,
no third party producers are connected to Montana-Dakota's system.
Although NEPA specifically bans federally-mandated wheeling of
power for retail customers, several state public utility regulatory
commissions are currently studying retail wheeling and at least two
of these states, California and Michigan, have proposed
implementing retail wheeling on a phased or experimental basis.
Retail wheeling means the movement of electric energy produced
by another entity over an electric utility's transmission and
distribution system, to a retail customer in the utility's service
territory. A requirement to transmit electricity directly to
retail customers would permit retail customers to purchase electric
capacity and energy from the electric utility in whose service area
they are located or from any other electric utility or independent
power producer. None of the legislatures or utility commissions in
Montana-Dakota's service territory have instituted proceedings on
retail wheeling at this time.
With the passage of NEPA and the advent of a more competitive
electric utility environment, Montana-Dakota has intensified its
ongoing strategic planning process and is implementing changes to
increase its competitiveness. Several of these changes include
consolidating small offices, modifying and simplifying operating
practices, maximizing the efficient utilization of electric
generating facilities and the utilization of state-of-the art
computer technology. Although Montana-Dakota is unable to predict
the extent of competition in the future or provide assurances as to
the effect of such on its operations, Montana-Dakota is presently
taking steps to effectively operate in an increasingly competitive
environment.
Regulatory Matters --
The cost of coal purchased from Knife River for use at
Montana-Dakota's electric generating stations is subject to certain
recoverability limits established by the Montana, North Dakota and
South Dakota public service commissions. These limits allow for
the recovery of coal costs which are established based on the
commissions' determination of a reasonable return on equity for
Knife River's coal operations, regardless of the actual cost of
coal purchased. Although disallowances have occurred in the past,
such amounts have not been material to Montana-Dakota's electric
operations. Legislation has been introduced in the states of North
Dakota and Montana which is intended to remove the effects of these
limitations.
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% of
electric revenues), such cost changes are includible in general
rate filings.
As a result of a 1993 inquiry by the North Dakota Public
Service Commission (NDPSC) regarding the level of Montana-Dakota's
electric earnings, the NDPSC reconsidered its prior order in which
it had permitted deferral, for a limited time period, of additional
expenses related to the implementation by Montana-Dakota of
Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" (SFAS
No. 106). On January 19, 1994, the NDPSC issued an order which
requires the expensing, commencing January 1, 1994, of the ongoing
SFAS No. 106 incremental expense estimated at approximately $1.0
million annually. The order further stated that the SFAS No. 106
costs deferred by Montana-Dakota in 1993 are expected to be
recoverable in future rates.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1994 actual and 1995 through 1997 anticipated construction
expenditures applicable to Montana-Dakota's electric operations:
Actual Estimated
1994 1995 1996 1997
Production . . . . . . . . $ 1.8 $ 6.0 $ 7.1 $ 6.7
Transmission . . . . . . . 1.4 1.7 2.5 2.0
Distribution, General
and Common . . . . . . . 11.0 9.4 10.8 8.2
$14.2 $17.1 $20.4 $16.9
Environmental Matters --
Montana-Dakota's electric operations, are subject to extensive
federal, state and local laws and regulations providing for
environmental, 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 applicable regulations, including environmental
regulations, as well as all applicable 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 lignite coal fired. All of these
stations, with the exception of the Big Stone Station, are 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. Current assessments indicate that
the emissions requirement is expected to be met at the Big Stone
Station 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.
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 1994 and does not expect to incur any
substantial capital expenditures related to environmental
facilities during 1995 through 1997.
Retail Natural Gas and Propane Distribution
General --
Montana-Dakota sells natural gas at retail, serving over 191,000
residential, commercial and industrial customers located in 140
communities and adjacent rural areas as of December 31, 1994, and
provides natural gas transportation services to certain customers
on its system. These services are provided through a natural gas
distribution system aggregating nearly 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 14 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, 1994, Montana-Dakota's net gas and propane
distribution plant investment approximated $83.4 million.
The natural gas 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 1994 natural gas and propane
utility operating revenues by jurisdiction is as follows: North
Dakota -- 44%; Montana -- 31%; South Dakota -- 18% and Wyoming --
7%.
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 their 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 volumes
sold depend on weather patterns.
During 1993 and 1994, Montana-Dakota extended natural gas
service to 11 north-central South Dakota communities at a cost of
$8.3 million. This extension has the potential of adding
approximately 1.6 million decatherms (MMdk) to annual natural gas
sales.
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 1994 1993 1992 1991 1990
and Propane Throughput Mdk (thousands of decatherms)
Sales:
Residential. . . . . . 19,039 19,565 17,141 18,904 16,486
Commercial . . . . . . 12,403 11,196 9,256 10,865 11,382
Industrial . . . . . . 398 386 284 305 410
Total Sales. . . . . 31,840 31,147 26,681 30,074 28,278
Transportation:
Commercial . . . . . . 2,011 3,461 3,450 3,582 2,982
Industrial . . . . . . 7,267 9,243 10,292 8,679 8,824
Total Transporta-
tion . . . . . . . 9,278 12,704 13,742 12,261 11,806
Total Throughput . . . . 41,118 43,851 40,423 42,335 40,084
The restructuring of the natural gas industry, as described
under "Interstate Natural Gas Transmission Operations and Property
(Williston Basin)", has resulted in additional competition in
retail natural gas markets. In response to this increased
competition, 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.
However, certain of Montana-Dakota's customers have the
potential of bypassing its distribution system by directly
accessing Williston Basin's or other pipelines' facilities. In
early 1994, two oil refineries located in Montana bypassed Montana-
Dakota through an interconnection with another company's
transportation facilities. Montana-Dakota continues to provide
limited services to these customers. The future utilization of
Montana-Dakota's facilities by these customers will be dependent
upon the competitiveness of its services.
The Company has been targeting small and large fleet vehicle
owners for the use of compressed natural gas (CNG) as a vehicle
fuel. CNG is a more environmentally sound fuel than gasoline,
dramatically reducing carbon monoxide and other emissions, and
costs substantially less than gasoline.
In recent years, Montana-Dakota has obtained the majority of
its annual natural gas requirements from Williston Basin, with the
balance being provided by various producers under firm contracts.
However, commensurate with Williston Basin's unbundling of its
various services as a result of its implementation of the FERC's
Order 636 in November 1993, as further described under "Interstate
Natural Gas Transmission Operations and Property (Williston Basin)"
Montana-Dakota elected to acquire approximately 85 percent of its
system requirements directly from producers and processors with the
balance still being provided by Williston Basin from its owned
natural gas reserves. Such natural gas is supplied under firm
contracts varying in length from less than one year to over five
years and is transported under firm transportation agreements by
Williston Basin 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 nearly 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 has implemented an integrated resource plan
which is used in planning for a reliable future supply of natural
gas which will coincide with anticipated customer demand. 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. Other supply alternatives
being evaluated are the installation of peak shaving facilities,
the acquisition of storage gas inventories and deliverability, and
the interconnection with other pipelines. On the demand side,
Montana-Dakota is evaluating the use of various conservation
programs which include energy audits, weatherization programs and
incentives for the installation of high efficiency appliances such
as boilers, furnaces and water heaters. The development and
evaluation of other economically feasible strategic marketing
programs continues.
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. The
various commissions' current regulatory practices allow
Montana-Dakota to recover increases or refund decreases in such
costs within 24 months from the time such changes occur.
Montana-Dakota filed a general natural gas rate case with the
South Dakota Public Utilities Commission (SDPUC) in September 1993,
requesting increased revenues of approximately $1.3 million, or 5
percent. On January 19, 1994, Montana-Dakota and the SDPUC reached
a settlement of this proceeding which provides for additional
revenues of $605,000, or 47 percent of the original amount
requested, effective January 19, 1994. However, the issue related
to Montana-Dakota's request that the SDPUC authorize accrual
accounting for postretirement benefits, representing 26 percent of
the amount originally requested, was deferred. A rehearing was
held March 24, 1994, on the recovery of SFAS No. 106 costs. On
July 21, 1994, the Commission issued an order rejecting the
Company's request, determining that the pay-as-you-go method must
be used for ratemaking purposes.
On June 29, 1994, Montana-Dakota filed a general natural gas
rate application with the SDPUC requesting increased revenues of
approximately $1.1 million, or 3.7 percent. The filing also
included the recovery of SFAS No. 106 costs, which at the time of
the filing was still pending in the previous South Dakota general
natural gas rate application discussed above. Montana-Dakota and
the SDPUC reached a settlement of this proceeding on December 6,
1994, providing for a $500,000 annual increase effective
December 7, 1994. In addition, on December 22, 1994, Montana-
Dakota and the SDPUC reached a settlement granting Montana-Dakota's
request for accrual accounting for postretirement benefits and that
such costs should be recovered through general rates. The
settlement, which became effective January 1, 1995, allows Montana-
Dakota to collect $254,000 annually for ongoing postretirement
benefit costs including the recovery of deferred 1994 costs over an
18-year period.
On April 1, 1994, Montana-Dakota filed a general natural gas
rate increase application with the Montana Public Service
Commission (MPSC) requesting an increase of $2.6 million or 5.3%,
with 25% requested on an interim basis to be effective within 30
days. On October 26, 1994, the MPSC issued an order approving a
settlement of this proceeding which provided for additional annual
revenues of $900,000, or 35 percent of the original amount
requested. Also included as a part of the settlement was the
favorable resolution of outstanding purchased gas cost adjustment
filings dating back to December 1989, as well as proceedings
concerning the prudency of Montana-Dakota's decision not to
implement its 1990 and 1991 gas supply conversion options. The
settlement also included the expensing and recovery of current and
previously deferred SFAS No. 106 costs. The rate change became
effective November 1, 1994.
Montana-Dakota filed a general natural gas rate case with the
NDPSC on May 13, 1994, requesting increased revenues of
approximately $945,000, or 1.3 percent. On November 9, 1994,
Montana-Dakota and the NDPSC reached a settlement of this
proceeding which provided for additional revenues of $565,000, or
60 percent of the original amount requested, effective November 15,
1994.
Capital Requirements --
In 1994, Montana-Dakota expended $13.2 million for natural gas
and propane distribution facilities and currently anticipates
expending approximately $8.5 million, $9.4 million and $9.6 million
in 1995, 1996 and 1997, 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 United States Environmental Protection Agency (EPA) in
January 1991. Montana-Dakota and Williston Basin believe the PCBs
entered the system from a valve sealant. Both Montana-Dakota and
Williston Basin have initiated testing, monitoring and remediation
procedures, in accordance with applicable regulations and the work
plan submitted to the EPA and the appropriate state agencies. On
January 31, 1994, Montana-Dakota, Williston Basin and Rockwell
International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell will 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 that future environmental
assessment and remediation costs that will be incurred range from
$3 million to $15 million. This estimate depends upon a number of
assumptions concerning the scope of remediation that will be
required at certain locations, the cost of remedial measures to be
undertaken and the time period over which the remedial measures are
implemented. Both Montana-Dakota and Williston Basin consider
unreimbursed environmental remediation costs to be recoverable
through rates, since they are prudent costs incurred in the
ordinary course of business. Accordingly, Montana-Dakota and
Williston Basin have sought and will continue to seek recovery of
such costs through rate filings. Based on the estimated cost of
the remediation program and the expected recovery from third
parties and ratepayers, Montana-Dakota and Williston Basin believe
that the ultimate costs related to these matters will not be
material to Montana-Dakota's or Williston Basin's financial
position 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, current
estimates of the total cleanup costs for all parties, including
oversight costs, at this site range from approximately $3.7 million
to $4.8 million. Montana-Dakota believes that it was not a
material contributor to this contamination and, therefore, further
believes that its share of the liability for such cleanup will not
have a material effect on its results of operations.
CENTENNIAL ENERGY HOLDINGS, INC.
INTERSTATE NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY
(WILLISTON BASIN)
General --
Williston Basin owns and operates approximately 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, 1994, the net interstate natural gas transmission
plant investment was approximately $159.0 million.
Under the Natural Gas Act (NGA), as amended, Williston Basin is
subject to the jurisdiction of the FERC regarding certificate, rate
and accounting matters applicable to natural gas purchases,
wholesale 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 volumes 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 other 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
serves 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.
See "Regulatory Matters and Revenues Subject to Refund -- Order
636" for a further discussion on Williston Basin's implementation
of Order 636.
For additional information regarding Williston Basin's sales
and transportation for 1992 through 1994, 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 nearly uniform daily volumes throughout the year and
thus, facilitate meeting winter peak requirements.
In April 1993, Williston Basin filed an application with the
FERC for authority to increase its certificated storage withdrawal
capacity by 95 MMcf per day, which the FERC approved in September
1993. This increase will allow Williston Basin to expand and
enhance the storage services it offers to its customers. Williston
Basin has expended $9.5 million related to this enhancement, which
is essentially complete.
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 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 and 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 1994 is as follows:
1994
Production (MMcf). . . . . . . . . . . . . . . . . . . . 4,932
Average sales price. . . . . . . . . . . . . . . . . . . $1.37
Production costs, including taxes,
per Mcf. . . . . . . . . . . . . . . . . . . . . . . . $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, 1994, are as follows:
Gross Net
Productive Wells . . . . . . . . . . . . 504 452
Developed Acreage (000's). . . . . . . . 228 204
Undeveloped Acreage (000's). . . . . . . 54 48
The following table shows the results of natural gas development
wells drilled and tested during 1994:
1994
Productive . . . . . . . . . . . . . . . . . . . . . . . 13
Dry Holes. . . . . . . . . . . . . . . . . . . . . . . . ---
Total. . . . . . . . . . . . . . . . . . . . . . . . . 13
At December 31, 1994, there were no wells in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 99.3 Bcf at December 31, 1994.
These amounts are supported by a report dated January 31, 1995,
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 18 of Notes to Consolidated Financial
Statements.
Pending Litigation --
W. A. Moncrief --
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 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 November 1, 1993, (the date when
Williston Basin implemented FERC Order 636 and abandoned its natural
gas sales merchant function, see "Regulatory Matters and Revenues
Subject to Refund -- Order 636" for a further discussion of
Williston Basin's implementation of Order 636) to mid-1996, the
remaining period of the contract.
On June 9, 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. On July 13, 1994, the Court denied Moncrief's
motion to amend its complaint.
However, on July 15, 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 its damage
calculations which total approximately $18 million or, under its
alternative pricing theory, $38 million. Trial is scheduled for
June 12, 1995.
Moncrief's damage claims in Williston Basin's opinion, are
grossly overstated. Williston Basin further believes it has
meritorious defenses and intends to vigorously defend such suit.
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 --
General Rate Proceedings --
Williston Basin had pending with the FERC two general natural
gas rate change applications implemented in 1989 and 1992. On
May 3, 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 on July 20, 1994, Williston Basin refunded
$47.8 million to its customers, including $33.4 million to Montana-
Dakota, all of which had been reserved. Williston Basin's requested
rehearing is currently pending as is the issuance of an initial
order by the FERC with respect to the 1992 rate change application.
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, as discussed below, 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.
Producer Settlement Cost Recovery --
In August 1993, Williston Basin filed to recover 75 percent of
$28.7 million ($21.5 million) in buy-out/buy-down costs paid to Koch
Hydrocarbon Company (Koch) as part of a lawsuit settlement under the
alternate take-or-pay cost recovery mechanism embodied in Order 500.
As permitted under Order 500, Williston Basin elected to recover 25
percent or $7.2 million of such costs through a direct surcharge to
sales customers, substantially all of which has been received. In
addition, through reserves previously provided, Williston Basin has
absorbed an equal amount. Williston Basin elected to recover the
remaining 50 percent ($14.3 million) through a throughput surcharge
applicable to both sales and transportation. Williston Basin began
collecting these costs, subject to refund, in October 1993, pending
final approval by the FERC. On August 17, 1994, the FERC issued an
order granting Williston Basin's request to collect such costs.
Order 636 --
In 1992, the FERC issued Order 636, which required fundamental
changes in the way natural gas pipelines operate. Under Order 636,
pipelines are required to offer unbundled sales, transportation,
storage and other services. Customers now have the option of
purchasing gas from other suppliers and pipelines are required to
provide "equivalent" services for all customers regardless from whom
they are purchasing gas. This order provides for the use of the
straight fixed variable rate design, under which all fixed storage
and transmission costs, including return on equity and associated
taxes, are included in a demand charge and all variable costs are
recovered through a commodity charge based on volumes. Order 636
allows pipelines to recover 100 percent of prudently incurred costs
(transition costs) resulting from implementation of the order.
Williston Basin had previously filed a tariff with the FERC
designed to comply with Order 636. In September 1993, the FERC
issued its order authorizing Williston Basin's implementation of
Order 636 tariffs effective November 1, 1993. Also included in the
order was the requirement that Williston Basin's excess storage gas
inventories must be offered for sale at Williston Basin's cost, as
opposed to fair market value. Williston Basin requested rehearing
of this issue on the grounds that the FERC's order constitutes a
confiscation of its assets. This matter is currently on appeal.
Williston Basin has also filed tariff sheets with the FERC
requesting recovery of certain gas supply realignment (GSR) costs.
On January 9, 1995, the FERC issued an order approving Williston
Basin's request to collect $13.4 million of GSR costs related to
payments made to Koch as part of a lawsuit settlement effective
December 1, 1993. In addition, on February 10, 1995 the FERC issued
an order approving Williston Basin's request to collect $925,000 of
GSR costs effective February 1, 1995, paid as part of a settlement
agreement with a natural gas producer which terminated all natural
gas contracts effective with the implementation of Order 636.
Montana-Dakota has also received approval for revised gas cost
tariffs from each of its four state regulatory commissions
reflecting the effects of Williston Basin's November 1, 1993
implementation of Order 636.
The financial effect of implementing Order 636 was not material
to the company's financial position or results of operations.
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 4 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 and not recover any loss on
its sale from customers.
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 $4.6 million, $3.9 million and
$5.8 million in 1994, 1993 and 1992, 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, 1994, 17.4 MMdk of this natural gas had been sold and
transported by Williston Basin to both on- and off-system markets.
Williston Basin will continue to aggressively market the remaining
43.3 MMdk of this natural gas whenever market conditions are
favorable. In addition, it will continue to seek long-term sales
contracts.
Other Information --
In March and May 1993, Williston Basin was directed by the
United States Minerals Management Service (MMS) to pay approximately
$3.5 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 December 1, 1978, through February 29, 1988. Williston
Basin had filed appeals with both the MMS and the Courts regarding
this issue.
On July 16, 1994, Williston Basin and the MMS reached a
settlement which terminated the litigation and all administrative
proceedings. The settlement provided that Williston Basin make a
cash payment of $2.1 million, including interest, in satisfaction
of all claimed royalty underpayments. Williston Basin had
previously provided reserves adequate to cover the costs of the
settlement.
Additionally, on December 2, 1994, the MMS directed Williston
Basin to pay approximately $1.9 million, plus interest, in claimed
royalty underpayments for the period March 1, 1988, through
December 31, 1991 related to the aforementioned federal leases.
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
1994 actual and 1995 through 1997 anticipated construction
expenditures applicable to Williston Basin's operations:
Actual Estimated
1994 1995 1996 1997
Production and Gathering . $ 2.1 $ 5.8 $10.7 $ 6.6
Underground Storage. . . . 7.7 .2 .7 .8
Transmission . . . . . . . 2.3 3.4 10.3 7.0
General. . . . . . . . . . 2.3 2.4 1.2 1.2
$14.4 $11.8 $22.9 $15.6
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.
In mid-1992, Williston Basin discovered that several of its
natural gas compressor stations had been operating without air
quality permits. As a result, in late 1992, applications for
permits were filed with the Montana Air Quality Bureau (Bureau),
the agency for the state of Montana which regulates air quality.
In March 1993, the Bureau cited Williston Basin for operating the
compressors without the requisite air quality permits and further
alleged excessive emissions by the compressor engines of certain
air pollutants, primarily oxides of nitrogen and carbon monoxide.
Williston Basin is currently engaged in discussions with the
Bureau regarding test results and requirements in meeting these
air emissions standards. Because the permitting process is not
complete at this time, Williston Basin is unable to determine the
costs that will be incurred to remedy the situation although such
costs are not expected to be material to its financial position or
results of operations.
MINING AND CONSTRUCTION MATERIALS 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 and Gascoyne, North Dakota and Savage, Montana.
The average annual production from the Beulah, Gascoyne and Savage
mines approximates 2.5 million, 2.1 million and 300,000 tons,
respectively. Reserve estimates related to these mine locations
are discussed herein. During the last five years, Knife River
mined and sold the following amounts of lignite coal:
Years Ended December 31,
1994 1993 1992 1991 1990
(In thousands)
Tons sold:
Montana-Dakota generating
stations . . . . . . . . . 691 624 521 618 592
Jointly-owned generating
stations--
Montana-Dakota's share. . . 1,049 1,034 1,021 953 895
Others. . . . . . . . . . . 3,358 3,299 3,259 3,069 2,872
Industrial and other sales . 108 109 112 91 80
Total . . . . . . . . . . 5,206 5,066 4,913 4,731 4,439
Revenues . . . . . . . . . .$45,634 $44,230 $43,770 $41,201 $38,276
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 expires in mid-1995 and Knife
River anticipates closing the Gascoyne Mine upon the expiration of
the contract. The costs of closing the Gascoyne Mine are not
expected to have a significant effect on Knife River's results of
operations.
Knife River, subsequent to the loss of the Big Stone contract,
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 further
utilize 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 --
In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect,
wholly-owned subsidiary of Knife River, entered into the sand and
gravel business in north-central California through the purchase of
certain properties, including mining and processing equipment.
These operations, located near Lodi, California, surface mine,
process and market aggregate products to various customers,
including road and housing contractors, tile manufacturers and
ready-mix plants, with a market area extending approximately 60
miles from the mine.
The assets of Alaska Basic Industries, Inc. (ABI) and its
subsidiaries were purchased by KRC Aggregate in April 1993. ABI is
a vertically integrated construction materials business
headquartered in Anchorage, Alaska. ABI's nine divisions handle
the sale of its sand and gravel aggregates and related products
such as ready-mixed concrete, asphalt and finished aggregate
products.
In September 1993, KRC Aggregate, purchased the stock of LTM,
Incorporated (LTM), Rogue Aggregates, Inc. (Rogue Aggregates) and
Concrete, Inc., then construction materials subsidiaries of Terra
Industries. Headquartered in Medford, Oregon, LTM and Rogue
Aggregates are vertically integrated construction materials
businesses serving southern Oregon markets. Their products include
sand and gravel aggregates, ready-mixed concrete, asphalt and
finished aggregate products. Concrete, Inc., headquartered in
Stockton, California, operates four ready-mix plants in San Joaquin
County. These ready-mix plants became part of KRC Aggregate's
Lodi, California operations.
On January 1, 1994, KRC Holdings, Inc., (KRC Holdings), a newly
formed, wholly-owned subsidiary of Knife River acquired ownership
of the above construction materials operations from KRC Aggregate.
KRC Aggregate, ABI, LTM, Rogue Aggregates and Concrete, Inc.
continue to operate as subsidiaries of KRC Holdings.
The following table reflects sales volumes and revenues for the
construction materials operations during the last three years:
Years Ended December 31,
(In thousands)
1994 1993 1992
Aggregates (tons). . . . . . . . . . 2,688 2,391 263
Asphalt (tons) . . . . . . . . . . . 391 141 ---
Ready-mixed concrete (cubic yards) . 315 157 ---
Revenues . . . . . . . . . . . . . . $71,012 $46,167 $ 1,262
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. In addition, the seasonality of the construction
business in Knife River's market areas due to the influence of
weather is also a key factor affecting product demand.
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 1992, 1993 and 1994, no
single customer accounted for more than 10 percent of annual
construction materials revenues.
Consolidated Mining and Construction Materials Operations:
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
1994 actual and 1995 through 1997 anticipated construction
expenditures applicable to Knife River's consolidated mining and
construction materials operations:
Actual Estimated
1994 1995 1996 1997
Coal . . . . . . . . . . $ .9 $ 2.8 $ 5.2 $ 4.9
Construction Materials . 2.7 4.6 2.9 2.6
$ 3.6 $ 7.4 $ 8.1 $ 7.5
Knife River continues to seek out 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 processes. Any
capital expenditures related to other potential mining acquisitions
are not reflected in the above 1995 through 1997 capital needs.
Environmental Matters --
Knife River's mining and construction materials 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, 1994, Knife River had under ownership or
lease, reserves of approximately 236 million tons of recoverable
lignite coal at present mining locations. Such reserves estimates
were prepared by Paul Weir Company Incorporated, independent mining
engineers and geologists, in a report dated May 9, 1994, and have
been adjusted for 1994 production. Knife River estimates that
approximately 73 million tons of its reserves will be needed to
supply all of Montana-Dakota's existing generating 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, 1994, the combined construction materials
operations had under ownership approximately 71 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, 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.
Fidelity Oil undertakes ventures, through working-interest
agreements with selected partners, that 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.
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 1994, 1993 and 1992 are as follows:
1994 1993 1992
Oil:
Production (000's of barrels). . . . . 1,565 1,497 1,531
Average sales price. . . . . . . . . . $13.14 $14.84 $16.74
Natural Gas:
Production (MMcf). . . . . . . . . . . 9,228 8,817 5,024
Average sales price. . . . . . . . . . $1.84 $1.86 $1.53
Production costs, including taxes,
per net equivalent barrel. . . . . . . $4.04 $3.98 $4.81
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, 1994, are as follows:
Gross Net
Productive Wells:
Oil. . . . . . . . . . . . . . . . . . . . 3,524 173
Natural Gas . . . . . . . . . . . . . . . 540 30
Total. . . . . . . . . . . . . . . . . . 4,064 203
Developed Acreage (000's). . . . . . . . . . 541 51
Undeveloped Acreage (000's). . . . . . . . . 644 68
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1994, 1993 and 1992:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1994 4 3 7 6 1 7 14
1993 2 2 4 5 1 6 10
1992 --- 4 4 2 1 3 7
At December 31, 1994, there were 5 exploratory wells and 4
development wells in the process of drilling.
Capital Requirements --
The following summary reflects capital expenditures, including
those not subject to amortization, related to oil and natural gas
activities for the years 1994, 1993 and 1992:
1994 1993 1992
(In thousands)
Acquisitions . . . . . . . . . . . . . $ 5,542 $ 9,296 $ 9,976
Exploration. . . . . . . . . . . . . . 13,241 7,787 11,074
Development. . . . . . . . . . . . . . 19,739 7,836 4,715
Total Capital Expenditures . . . . . $38,522 $24,919 $25,765
Fidelity Oil plans additional commitments to oil and gas
investments and has budgeted approximately $36 million for each of
the years 1995 through 1997 for such activities. Such investments
are expected to be financed with a combination of funds on hand at
December 31, 1994, funds to be internally generated and the $20
million currently available under Fidelity Oil's long-term
financing arrangements, $3.0 million of which was outstanding at
December 31, 1994.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 12.5 million barrels and 54.9
Bcf, respectively, at December 31, 1994. Of these amounts, 8.6
million barrels and 2.2 Bcf, as supported by a report dated
January 10, 1995, 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 18 of Notes to Consolidated
Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
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 "Pending
Litigation". 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 1994.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
MDU Resources Group, Inc. common stock is listed on the New
York Stock Exchange and the Pacific Stock Exchange and uses the
symbol "MDU". The price range of the Company's common stock as
reported by the Wall Street Journal composite tape during 1994 and
1993 and dividends declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share
1994
First Quarter . . . . . . . . $32 1/4 $29 3/8 $ .39
Second Quarter. . . . . . . . 32 1/8 26 1/2 .39
Third Quarter . . . . . . . . 28 1/4 25 3/8 .40
Fourth Quarter. . . . . . . . 28 25 3/8 .40
$1.58
1993
First Quarter . . . . . . . . $29 1/4 $25 7/8 $ .37
Second Quarter. . . . . . . . 32 1/2 29 .37
Third Quarter . . . . . . . . 32 29 3/4 .39
Fourth Quarter. . . . . . . . 33 1/8 30 1/2 .39
$1.52
As of December 31, 1994, the Company's common stock was held by
approximately 14,600 stockholders.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to selected Financial Data on pages 52 and 53
of the Company's Annual Report which is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 1994 1993 1992
Utility --
Electric . . . . . . . . . . . . $11.7 $12.6 $13.3
Natural gas. . . . . . . . . . . .3 1.2 1.4
12.0 13.8 14.7
Natural gas transmission . . . . . 6.1 4.7 3.5
Mining and construction
materials. . . . . . . . . . . . 11.6 12.4 10.7
Oil and natural gas production . . 9.3 7.1 5.7
Earnings on common stock . . . . . $39.0 $38.0 $34.6
Earnings per common share. . . . . $2.06 $2.00 $1.82
Return on average common equity. . 12.1% 12.3% 11.6%
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.
________________________________
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 1992 and 1993 to conform to the 1994
presentation. Such reclassifications had no effect on net income
or common stockholders' investment as previously reported.
Montana-Dakota -- Electric Operations
Years ended December 31,
1994 1993* 1992
Operating revenues . . . . . . . . $133.9 $131.1 $123.9
Fuel and purchased power . . . . . 43.2 41.3 37.9
Operation and maintenance
expenses . . . . . . . . . . . . 41.0 37.4 34.2
Operating income . . . . . . . . . 27.6 30.5 30.2
Retail sales (kWh) . . . . . . . . 1,955.1 1,893.7 1,829.9
Power deliveries to MAPP (kWh) . . 444.5 511.0 352.6
Cost of fuel and purchased
power per kWh. . . . . . . . . . $ .017 $ .016 $ .016
Montana-Dakota -- Natural Gas Distribution Operations
Years ended December 31,
1994 1993* 1992
Operating revenues:
Sales. . . . . . . . . . . . . . $151.7 $151.7 $123.8
Transportation & other . . . . . 3.6 4.3 4.4
Purchased natural gas sold . . . . 111.3 114.0 89.5
Operation and maintenance
expenses . . . . . . . . . . . . 30.0 28.6 26.0
Operating income . . . . . . . . . 3.9 4.7 4.5
Volumes (dk):
Sales. . . . . . . . . . . . . . 31.8 31.2 26.7
Transportation . . . . . . . . . 9.3 12.7 13.7
Total throughput . . . . . . . . . 41.1 43.9 40.4
Degree days (% of normal). . . . . 96.7% 105.5% 87.1%
Cost of natural gas, including
transportation, per dk . . . . . $ 3.50 $ 3.66 $ 3.35
*See Note 1 of Notes to Consolidated Financial Statements for a
discussion of an accounting change to reflect unbilled revenues.
Williston Basin
Years ended December 31,
1994 1993 1992
Operating revenues:
Sales for resale. . . . . . . . . $ --- $51.3* $63.5*
Transportation & other. . . . . . 70.9* 40.0* 35.5*
Purchased natural gas sold . . . . --- 20.6 33.6
Operation and maintenance
expenses . . . . . . . . . . . . 38.8** 39.0** 33.0**
Operating income . . . . . . . . . 21.3 20.1 21.3
Volumes (dk):
Sales for resale--
Montana-Dakota. . . . . . . . . --- 13.0 16.5
Other . . . . . . . . . . . . . --- .2 .3
Transportation--
Montana-Dakota. . . . . . . . . 33.0 18.5 11.2
Other . . . . . . . . . . . . . 30.9 40.9 53.3
Total throughput . . . . . . . . . 63.9 72.6 81.3
_________________________________
* Includes recovery of deferred
natural gas contract
buy-out/buy-down costs. . . . . $ 8.3 $13.0 $ 5.8
** Includes amortization of
deferred natural gas contract
buy-out/buy-down costs. . . . . $ 9.3 $11.8 $ 6.2
Knife River
Years ended December 31,
1994 1993 1992
Operating revenues:
Coal. . . . . . . . . . . . . . . $45.6 $44.2 $43.8
Construction materials. . . . . . 71.0 46.2 1.2
Operation and maintenance
expenses . . . . . . . . . . . . 84.5 59.6 21.2
Reclamation expense. . . . . . . . 3.8 3.1 3.0
Severance taxes. . . . . . . . . . 4.5 4.4 4.3
Operating income . . . . . . . . . 16.6 17.0 11.5
Sales (000's):
Coal (tons) . . . . . . . . . . . 5,206 5,066 4,913
Aggregates (tons) . . . . . . . . 2,688 2,391 263
Asphalt (tons). . . . . . . . . . 391 141 ---
Ready-mixed concrete
(cubic yards) . . . . . . . . . 315 157 ---
Fidelity Oil
Years ended December 31,
1994 1993 1992
Operating revenues . . . . . . . . $38.0 $39.1 $33.8
Operation and maintenance
expenses. . . . . . . . . . . . . 12.0 11.6 12.0
Depreciation, depletion and
amortization. . . . . . . . . . . 13.5 12.0 8.8
Operating income . . . . . . . . . 8.8 11.8 9.5
Production (000's):
Oil (barrels) . . . . . . . . . 1,565 1,497 1,531
Natural gas (Mcf). . . . . . . . 9,228 8,817 5,024
Average sales price:
Oil (per barrel) . . . . . . . . $13.14 $14.84 $16.74
Natural gas (per Mcf). . . . . . 1.84 1.86 1.53
1994 compared to 1993
Montana-Dakota--Electric Operations
The decline in operating income reflects increased fuel and
purchased power costs, principally higher demand charges associated
with the pass-through from Basin of periodic maintenance costs and
the purchase of an additional five megawatts of firm capacity
through a participation power contract. Increased operation
expenses, primarily higher payroll and benefit-related costs,
largely the accrual of SFAS No. 106 costs, also negatively affected
operating income. In addition, decreased deliveries to the MAPP,
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 December 1993, January 1994, November 1994, and December 1994 in
North Dakota, South Dakota, Wyoming and Montana and the addition of
nearly 5,000 customers improved operating income. Also
contributing operating income was a Wyoming Supreme Court order
granting recovery 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 natural gas storage inventory
(included in Other Income--Net) somewhat mitigated the decline in
earnings.
Williston Basin
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.
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. Income from company production decreased due to lower
average prices, partially offset by higher production.
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 investable funds stemming from a
regulatory refund made in mid-1994.
Knife River
Coal Operations --
Operating income for the coal operations decreased primarily
due to increased operation and reclamation expenses. Higher
overburden removal costs at the Beulah Mine and costs associated
with an early retirement program stemming from the planned closing
of the Gascoyne Mine in mid-1995 were the primary factors
increasing operation expense. Reclamation expense increased as a
result of higher costs associated with the planned Gascoyne Mine
closure. An improvement in sales, primarily 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.
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 increase in construction materials
operating income. Somewhat offsetting this improvement was 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 a year ago.
Consolidated --
Earnings decreased due to the decline in coal operating income
and reduced investment income, primarily lower investable funds due
to the aforementioned acquisitions. The improvement in
construction materials operating income somewhat mitigated the
earnings decline.
Fidelity Oil
Operating income for the oil and natural gas production
business declined as a result of lower average oil prices and a
volume-related increase in operation expenses and depreciation,
depletion and amortization. Partially offsetting the operating
income decline was an improvement in oil and natural gas
production.
Earnings for this business improved due to the realization of
investment gains related to the sale of an equity investment in
General Atlantic Resources, Inc., which were $3.3 million (after-
tax) more than corresponding gains realized in 1993. The decline
in operating income partially offset the earnings increase.
1993 compared to 1992
Montana-Dakota--Electric Operations
Operating income for the electric business increased due to an
improvement in retail sales to residential and commercial markets,
primarily the result of colder weather in the first quarter of
1993. Also, improving operating income was an increase in
deliveries into the MAPP, the result of water conservation efforts
by hydroelectric generators and the temporary shutdown of a nuclear
generating station in Iowa. Increased fuel and purchased power
costs, largely higher demand charges associated with the purchase
of an additional five megawatts of firm capacity through a
participation power contract partially offset the improvement in
operating income. Higher operation and maintenance expenses also
negatively affected operating income. Employee benefit-related
costs increased operation expense while higher costs associated
with repairs made at the Heskett, Big Stone and Coyote stations
accounted for the increase in maintenance expense.
Earnings from this business unit declined as a result of a
decrease in Other Income--Net, reflecting the on-going effects of
adopting SFAS No. 106, and increased federal income taxes. A
decrease in interest expense due to lower interest rates stemming
from long-term debt refinancing in 1992 and lower average short-
term borrowings and interest rates, and the aforementioned
improvement in operating income, somewhat offset the earnings
decline.
Montana-Dakota--Natural Gas Distribution Operations
Sales increases of 4.5 MMdk, due to significantly colder
weather than 1992 and the addition of over 3,500 residential and
commercial customers, improved operating income for the natural gas
distribution business. However, partially offsetting this
improvement were the 1992 refinement of the estimated amount of
delivered but unbilled natural gas volumes and increased operation
and depreciation expenses. Employee benefit-related costs and
distribution and sales expenses related to the system expansion
into north-central South Dakota accounted for the majority of the
operation expense increase. A Wyoming rate decrease effective in
the second quarter of 1992 also reduced the operating income
improvement.
Gas distribution earnings decreased due to higher financing
costs related to increased capital expenditures and carrying
charges being accrued on natural gas costs refundable through rate
adjustments, offset in part by interest savings resulting from 1992
long-term debt refinancing. The operating income change and
increased Other Income--Net, primarily due to the return being
earned on deferred storage costs and increased interest income
earned on natural gas costs recoverable through rate adjustments in
Montana, reduced the earnings decline.
Williston Basin
Operating income declined at the natural gas transmission
business as a result of decreased transportation volumes reflecting
the effects of bypasses by two major transportation customers.
Partially offsetting the effects of these bypasses were the
increased movement of 3.4 MMdk of natural gas held under the
repurchase commitment, due to favorable natural gas prices, and
higher volumes transported on the November 1992 interconnection
with NSP (1.8 MMdk), although at lower average rates than those
replaced. Operating income was also negatively affected by the
delay in the implementation of Order 636 until November 1, 1993.
See Items 1 and 2 for Williston Basin for further discussions on
the implementation of Order 636. Operation expenses increased
slightly due to additional reserves related to the Koch settlement,
increased transmission expenses and higher employee benefit-related
costs. Largely offsetting the increased operation expenses are
lower contract restructuring amortizations, an out-of-period
adjustment to take-or-pay surcharge amortizations and a 1992
accrual for retroactive company production royalties. An
adjustment to regulatory reserves reflected in operating revenues
offset the effects of the additional reserves provided for the Koch
settlement. Maintenance expenses increased as a result of
compressor overhauls at several compressor station facilities. A
weather-related sales improvement of 3.3 MMdk combined with
increased general rates implemented in November 1992, partially
offset the operating income decline. Income from company
production improved due to increased production, but at lower
average prices.
Earnings for this business unit increased due to reduced
interest expense on long-term debt, the result of debt refinancing
in mid-1993, and lower carrying costs associated with the natural
gas repurchase commitment, primarily the result of both lower
borrowings and decreased average rates, offset in part by the
decline in operating income discussed above.
Knife River
Coal Operations --
Operating income decreased due to reduced selling prices at the
Gascoyne Mine, effective June 1, 1992, following an amendment to
the current coal supply agreement, and increased operation
expenses. Higher overburden removal costs at the Beulah Mine and
the accrual of SFAS No. 106 costs were the primary reasons for the
operation expense increase. An improvement in tons sold at all
mines, mainly the result of increased demand by electric generation
customers, somewhat reduced the coal operating income decline.
Construction Materials Operations --
Increased sales from the Alaskan and Oregon construction
materials businesses acquired in April and September 1993,
respectively, was the primary reason for the significant increase
in construction materials operating income.
Consolidated --
Earnings improved due to the construction materials operating
income improvement. These increased earnings were somewhat reduced
by lower coal operating income, decreased investment income
(included in Other Income--Net), primarily resulting from lower
investable funds due to the 1993 acquisitions and lower earned
returns, and increased federal income taxes.
Fidelity Oil
Operating income for the oil and natural gas production
business increased as a result of higher natural gas production and
prices. In addition, decreased operation and maintenance expenses
per equivalent barrel were somewhat offset by volume-related
increases in such costs. Partially offsetting the operating income
improvement was a decline in oil production and prices and
increased depreciation, depletion and amortization, reflecting both
increased production and higher rates.
The increase in operating income was further improved by the
realization of certain investment gains resulting in the earnings
improvement for this business. Increased interest expense,
stemming from both higher average borrowings and rates, and
increased federal income taxes, somewhat reduced earnings.
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 on the effects of these competitive forces on each of
the Company's businesses.
The operating results of the Company's utility and pipeline
businesses are significantly influenced by the weather, the general
economies of their respective service territories, and the ability
to recover costs through the regulatory process.
In January 1995, Montana-Dakota, in an effort to increase the
efficiency of its electric and natural gas operations, announced
plans to close 45 district offices throughout its service area
during 1995 and early 1996. The closure of these offices will
reduce Montana-Dakota's workforce by approximately 90 employees.
Beginning 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. Williston
Basin will continue to aggressively market this natural gas
whenever market conditions are favorable. In addition, it will
continue to seek long-term sales contracts. See Items 1 and 2
under Williston Basin for additional information on the natural gas
held under this repurchase agreement.
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 would not be renewed. The current
contract expires in mid-1995 and Knife River anticipates closing
the Gascoyne Mine upon the expiration of the contract. The costs
of closing the Gascoyne Mine are not expected to have a significant
effect on Knife River's results of operations.
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. See
Items 1 and 2 under Knife River for a discussion of acquisitions
made during 1992 and 1993.
See Items 1 and 2 for Montana-Dakota and Note 15 of Notes to
Consolidated Financial Statements contained in the 1994 Annual
Report for a further discussion on the Company's 1993 adoption of
SFAS No. 106, "Employers' Accounting for Postretirement Benefits
Other than Pensions" and the Company's efforts regarding regulatory
recovery.
Liquidity and Capital Commitments
The Company's construction costs and additional investments in
mining and construction materials, and oil and natural gas
activities (in millions of dollars) for 1992 through 1994 and as
anticipated for 1995 through 1997 are summarized in the following
table, which also includes the Company's capital needs for the
retirement of maturing long-term securities.
Estimated
1992 1993 1994 Company/Description 1995 1996 1997
Montana-Dakota:
$ 13.2 $ 16.2 $14.2 Electric $ 17.1 $ 20.4 $ 16.9
6.5 15.0 13.2 Natural Gas Distribution 8.5 9.4 9.6
19.7 31.2 27.4 25.6 29.8 26.5
9.4 5.4 14.4 Williston Basin 11.8 22.9 15.6
16.3 46.5 3.6 Knife River 7.4 8.1 7.5
25.8 24.9 38.6 Fidelity 36.0 36.0 36.0
--- 1.0 1.0 Prairielands 4.6 .1 .8
71.2 109.0 85.0 85.4 96.9 86.4
Retirement/Repurchase
131.6 3.2 22.8 of Securities 20.6 17.5 16.5
$202.8 $112.2 $107.8 Total $106.0 $114.4 $102.9
In 1994 the Company's regulated businesses operated by Montana-
Dakota and Williston Basin provided all of the funds needed for
construction purposes. The Company's 1994 capital needs to retire
maturing long-term securities were $22.8 million.
It is anticipated that Montana-Dakota will continue to provide
all of the funds required for its construction requirements for the
years 1995 through 1997 from internal sources and through the use
of its $30 million revolving credit and term loan agreement, $17
million of which is outstanding at December 31, 1994, 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 1995 through 1997 with a
combination of internally generated funds and lines of credit
aggregating $35 million, none of which is outstanding at
December 31, 1994, 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. 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,
1994, $17.5 million is outstanding under the term loan agreement.
Knife River's 1994 capital needs were met through funds on hand
and funds generated from internal sources. It is anticipated that
funds on hand, funds generated from internal sources and lines of
credit aggregating $11 million, none of which is outstanding at
December 31, 1994, will continue to meet the needs of this business
unit for 1995 through 1997, excluding funds which may be required
for future acquisitions.
Fidelity Oil's 1994 capital needs related to its oil and
natural gas acquisition, development and exploration program were
met through funds generated from internal sources and a $20 million
line of credit. It is anticipated that Fidelity's 1995 through
1997 capital needs will be met from internal sources and its line
of credit. At December 31, 1994, $3.0 million is outstanding under
the line 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' 1994 capital needs were met through funds
generated internally and lines of credit aggregating $5.4 million,
$680,000 of which is outstanding at December 31, 1994. It is
anticipated that Prairieland's 1995 through 1997 capital needs will
be met from internal sources and its lines of credit.
The Company utilizes its 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, 1994, under the 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, 1994, the Company could have issued
approximately $114 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.9 and 3.0 times for 1994 and 1993, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 3.3 times in 1994 compared to 3.4 times in 1993. Stockholders'
equity as a percent of total capitalization was 58% and 56% at
December 31, 1994 and 1993, 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 27 through 51 of the Annual Report.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is made to Pages 2 through 5 and 12 and 13 of the
Company's Proxy Statement dated March 6, 1995 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 6 through 11 of the Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 13 of the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits.
Index to Financial Statements and Financial Statement
Schedules.
Page
1. Financial Statements:
Report of Independent Public Accountants. . . . . *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 1994 . . . . . . . . . . . . . . . *
Consolidated Balance Sheets at December 31,
1994, 1993 and 1992 . . . . . . . . . . . . . . *
Consolidated Statements of Capitalization at
December 31, 1994, 1993 and 1992. . . . . . . . *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1994 . . . . . . . . . . . . . . . *
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 1994 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 1994 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 . . . . . . . . . . . . . . . . . . **
3(b) By-laws of MDU Resources Group, Inc.,
as amended to date. . . . . . . . . . . . . **
4(a) Indenture of Mortgage, dated as of
May 1, 1939, as restated in the
Forty-Fifth Supplemental Indenture,
dated as of April 21, 1992, and the
Forty-Sixth through Forty-Eighth
Supplements thereto between the Company
and the New York Trust Company
(The Bank of New York, successor
Corporate Trustee) and A. C.
Downing (W. T. Cunningham, successor
Co-Trustee), filed as Exhibit 4(a)
in Registration No. 33-66682; and
Exhibits 4(e), 4(f) and 4(g)
in Registration No. 33-53896. . . . . . . . *
+ 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 . . . . . . . . . . . . . . **
+ 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. . . . . . . . . . . . . . . . *
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1994 . . . . . . . . . . . **
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 . . . . . . . . . . **
(b) Reports on Form 8-K.
None.
____________________
* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement required
to be filed as an exhibit to this form pursuant to Item 14(c)
of this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
MDU RESOURCES GROUP, INC.
By: /s/ Harold J. Mellen, Jr.
Harold J. Mellen, Jr. (President
and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the registrant in the capacities and on the date indicated.
Signature Title Date
/s/ Harold J. Mellen, Jr. Chief Executive March 2, 1995
Harold J. Mellen, Jr. Officer
(President and Chief Executive Officer)and Director
/s/ Douglas C. Kane Chief Operating March 2, 1995
Douglas C. Kane (Executive Vice Officer and
President and Chief Operating Officer) Director
/s/ Warren L. Robinson Chief Financial March 2, 1995
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting March 2, 1995
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director March 2, 1995
John A. Schuchart (Chairman of the Board)
/s/ Richard L. Muus Director March 2, 1995
Richard L. Muus
/s/ Robert L. Nance Director March 2, 1995
Robert L. Nance
/s/ John L. Olson Director March 2, 1995
John L. Olson
/s/ San W. Orr, Jr. Director March 2, 1995
San W. Orr, Jr.
/s/ Charles L. Scofield Director March 2, 1995
Charles L. Scofield
/s/ Homer A. Scott, Jr. Director March 2, 1995
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director March 2, 1995
Joseph T. Simmons
/s/ Stanley F. Staples, Jr. Director March 2, 1995
Stanley F. Staples, Jr.
/s/ Sister Thomas Welder Director March 2, 1995
Sister Thomas Welder
EXHIBIT INDEX
Exhibit No.
3(a) Composite Certificate of Incorporation
of MDU Resources Group, Inc., as amended
to date. . . . . . . . . . . . . . . . . . . . **
3(b) By-laws of MDU Resources Group, Inc.,
as amended to date . . . . . . . . . . . . . . **
4(a) Indenture of Mortgage, dated as of
May 1, 1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of April 21,
1992, and the Forty-Sixth through Forty-
Eighth Supplements thereto between the
Company and the New York Trust Company
(The Bank of New York, successor Corporate
Trustee) and A. C. Downing (W. T.
Cunningham, successor Co-Trustee), filed
as Exhibit 4(a) in Registration No. 33-66682;
and Exhibits 4(e), 4(f) and 4(g) in
Registration No. 33-53896. . . . . . . . . . . *
+ 10(a) Management Incentive Compensative 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. . . . . . . . . . . . . . . . **
+ 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 . . . . . . . . . . . . . . . . . *
13 Selected financial data, financial
statements and supplementary data
contained in the Annual Report to
Stockholders for 1994. . . . . . . . . . . . . **
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.