SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One) (X) Annual Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 (fee required)
For the fiscal year ended December 31, 1993
OR
( ) Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 (no fee required)
For the transition period from to
Commission File Number 0-368
OTTER TAIL POWER COMPANY
(Exact name of registrant as specified in its charter)
MINNESOTA 41-0462685
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.
215 SOUTH CASCADE STREET, BOX 496, FERGUS FALLS, MINNESOTA 56538-0496
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (218) 739-8200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
NONE NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON SHARES, par value $5.00 per share
CUMULATIVE PREFERRED SHARES, without par value.
(Title of class)
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. ( )
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 )
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. $347,339,216 as of March 1, 1994
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of the latest practicable date: 11,180,136 Common Shares
($5 par value) as of March 1, 1994
Documents Incorporated by Reference:
1993 Annual Report to Shareholders - Portions incorporated by reference into
Part II
Proxy Statement dated March 9, 1994 - Portions incorporated by reference into
Part III
PART I
Item 1. BUSINESS
(a) General Development of Business
Otter Tail Power Company (the "Company") is an operating public utility
which was incorporated in 1907 under the laws of the State of Minnesota. Its
principal executive office is located at 215 South Cascade Street, Box 496,
Fergus Falls, Minnesota 56538-0496; and its telephone number is (218) 739-
8200.
The Company's primary business is the production, transmission,
distribution and sale of electric energy. The Company, through its
subsidiaries, is also engaged in other businesses which are referred to as
Health Services Operations and Diversified Operations. Health Services
Operations consists of certain businesses acquired in 1993, including a
diagnostic medical imaging company, a management company for a number of
diagnostic medical imaging companies, and a medical imaging company that sells
and services diagnostic medical imaging equipment and associated supplies and
accessories. Diversified Operations consists of businesses diversified in
such areas as manufacturing (fabricated metal parts and agricultural
equipment), electrical and telephone contracting, radio broadcasting, waste
incinerating, and telephone/cable TV utility.
For a discussion of the Company's results of operations, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," which is incorporated by reference to pages 24 through 31 of the
Company's 1993 Annual Report to Shareholders, filed as an Exhibit hereto.
(b) Financial Information About Industry Segments
The Company and its subsidiaries are engaged in businesses that have been
classified into three segments: Electric Operations, Health Services
Operations, and Diversified Operations. Financial information about the
Company's industry segments is incorporated by reference to note 2 of "Notes
to Consolidated Financial Statements" on page 39 of the Company's 1993 Annual
Report to Shareholders, filed as an Exhibit hereto.
(c) Narrative Description of Business
ELECTRIC OPERATIONS
General
On a fully consolidated basis, the Company derived 73% of its operating
revenues from the sale of electric energy during 1993; 85% during 1992; and
90% during 1991. During 1993 the Company derived approximately 54.5% of its
electric revenues from Minnesota, 38.4% from North Dakota, and 7.1% from South
Dakota.
The territory served by the Company is predominantly agricultural,
including a part of the Red River Valley. Although there are relatively few
large customers, sales to commercial and industrial customers are significant.
By customer category, 51.7% of 1993 electric revenues was derived from
commercial and industrial customers, 32.6% from residential customers, and
15.7% from other sources, including municipalities, farms and power pools.
The Company's two largest oil pipeline customers accounted for about
10.4% of total 1993 retail electric revenues compared to 10.5% of such
revenues in 1992. In 1993, retail kwh sales to these pipeline customers
increased by 4.2% from the previous year. Sales to a large wood products
customer accounted for 1.6% of total retail electric revenues in 1993 as
compared to 1.7% in 1992. Sales to a large barley malting plant accounted for
1.4% of total retail electric revenues in 1993 as compared to 1.7% in 1992.
No other retail customer accounted for more than 1% of retail electric
revenues. Power pool sales to other utilities, which accounted for 26.8% of
total 1993 kwh sales, increased 72.9% from 1992. The increase in power pool
sales in 1993 can be attributed to the weather, which resulted in low water
conditions in the spring in Manitoba and widespread summer flooding in the
Midwest. Activity in short-term energy sales is subject to change based on a
number of factors and the Company is unable to predict the 1994 level of
activity. The Company's other sales of electricity for resale are
insignificant.
The aggregate population of the Company's retail service area is
approximately 230,000. In this service area of 423 communities and adjacent
rural areas and farms, approximately 123,600 people lived in communities
having a population of more than 1,000, according to the 1990 census. The
only communities served which have a population in excess of 10,000 are
Jamestown, North Dakota, (15,571); Fergus Falls, Minnesota (12,362); and
Bemidji, Minnesota (11,245). Since 1990 when the customer count was at a low
of 121,287, the Company has experienced an increase in customers. By year end
1993 total customers had increased to 122,427. During 1993, the Company
experienced a net increase of 430 customers, with growth in the number of
residential and commercial customers, notwithstanding the loss of 243
customers to the city of Detroit Lakes, Minnesota as a result of annexation of
a portion of the Company's service territory.
The Company's electric sales are subject to competition in some areas
from municipally owned systems, rural cooperatives and, in certain respects,
from on-site generators and cogenerators. The Company's electricity also
competes with other forms of energy. The degree of competition may vary from
time to time depending on relative costs and supplies of other forms of
energy. Although the Company cannot predict the precise extent to which its
future business may be affected by supply, relative cost or promotion of other
electricity or energy suppliers, the Company believes that it will be in a
position to compete favorably with other suppliers.
Rate Matters
The Company is subject to electric rate regulation as follows:
Year Ended
December 31, 1993
% of
Electric % of kwh
Rates Regulation Revenues Sales
Minnesota retail sales Minnesota Public Utilities
Commission 46.4% 38.7%
North Dakota retail sales North Dakota Public Service
Commission 36.7 28.9
South Dakota retail sales South Dakota Public Utilities
Commission 7.0 5.4
Transmission and sales Federal Energy Regulatory
for resale Commission ("FERC") 9.9 27.0
100.0% 100.0%
The following table summarizes the electric rate proceedings with the
Minnesota and the South Dakota Public Utilities Commissions, the North Dakota
Public Service Commission, and the Federal Energy Regulatory Commission since
January 1, 1989:
Increase
% Increase Increase (Decrease) Granted
Request (Decrease) (Decrease)
Commission Filed Requested Effective Amount %
(Thousands)
Minnesota Last Proceeding was July 1, 1987
North Dakota (1). . . . . January 15, 1989 ($1,000) (1.5%)
(2). . . . . June 1, 1990 ($ 315) (0.5%)
(3). . . . . September 9, 1992 ($1,000) (1.5%)
(4). . . . . September 22, 1993 ($ 300) (0.4%)
South Dakota Last Proceeding was November 1, 1987
FERC Last Proceeding was July 1, 1987
___________
(1) A voluntary settlement agreement reached between the Company and the
North Dakota Commission decreased North Dakota retail rates by $1,000,000
annually (or approximately 1.5%) effective January 15, 1989. In
addition, the settlement agreement provided for the Company to spend
$315,000 annually on additional North Dakota economic development, which
expenditures will be offset by reduced North Dakota depreciation expense.
(2) This voluntary rate adjustment decreased North Dakota retail rates by
$315,000 annually to recognize the positive effect on the Company's
customer base in North Dakota as a result of the economic development
expenditures referred to in note (1) above.
(3) A voluntary settlement agreement reached between the Company and the
North Dakota Commission pursuant to which the Company made a refund of
$1,000,000 to its North Dakota customers. This settlement does not
require a permanent reduction in rates charged by the Company to
customers in North Dakota.
(4) An agreement for incentive regulation reached between the Company and the
North Dakota Commission provides for sharing equally between ratepayers
and shareholders any amount earned in 1993 over or under a benchmark
overall rate of return. A liability of $300,000 for the Company to its
North Dakota customers resulted from sharing earnings above this
benchmark for 1993. The status of this liability will be considered in
future incentive agreements between the Company and the North Dakota
Commission for the years 1994 and following.
Under Minnesota law, the Minnesota Commission must allow implementation
of an interim rate increase, subject to refund with interest, 60 days after
the initial filing date of a rate increase request, except that the Commission
is not required to allow implementation of the interim rate increase until
four months after the effective date of a previous rate order. The amount of
the interim rate increase will be calculated using the proposed test year cost
of capital, the rate of return on common equity most recently granted to the
Company by the Commission, and rate base and expense items allowed by a
currently effective Commission order. In addition, if the Commission fails to
make a final determination regarding any rate request within ten months after
the initial request is filed, then the requested rate is deemed to be
approved, except if (i) an extension of the procedural schedule (in case of a
contested rate increase request) has been granted, in which case the schedule
of rates will be deemed to have been approved by the Commission on the last
day of the extended period of suspension of the rate increase, or (ii) a
settlement has been submitted to and rejected by the Commission, and the
Commission does not make a final determination concerning the schedule of
rates, in which case the schedule of rates will be deemed to have been
approved 60 days after the initial or, if applicable, the extended period of
suspension of the rate increase.
Rate requests filed with the North Dakota Public Service Commission
become effective 30 days after the date of filing unless suspended by the
Commission. Within seven months after the date of suspension, the North
Dakota Commission must act on the request, and during the period of
consideration by the Commission a suspended rate can be implemented only with
the approval of the Commission.
South Dakota law provides that a requested rate increase can be
implemented 30 days after the date of filing, unless its effectiveness is
suspended by the Commission. The Commission may suspend the effectiveness of
the proposed rate change for a period not longer than 90 days beyond the time
when the rate change would otherwise go into effect, unless the Commission
finds that a longer time is required, in which case the Commission may extend
the suspension for a period not to exceed a total of 12 months. A public
utility may not put a proposed rate change into effect until at least 45 days
after the Commission has made a determination concerning any previously filed
rate change. In the event that a requested rate change is suspended by the
Commission, such requested rate change can be implemented by the public
utility six months after the date of filing (unless previously authorized by
the Commission), subject to refund with interest.
The Company's wholesale power sales and transmission rates are subject to
the jurisdiction of the Federal Energy Regulatory Commission under the Federal
Power Act of 1935. Filed rates are effective after a one-day suspension
period, subject to ultimate approval by the FERC. Power pool sales are
conducted continuously through the Mid-Continent Area Power Pool ("MAPP") on
the basis of generating costs, in accordance with schedules filed by MAPP with
the FERC.
In rate cases, a forward test year procedure enables cost increases to be
recovered more promptly than use of an historic test year. The Minnesota
Public Utilities Commission has established by regulation a forward test year
procedure. The North Dakota Public Service Commission has not formally
established a test year procedure; however, it accepted a forward test year in
the Company's most recent rate case. The South Dakota Public Utilities
Commission uses an historic test year with adjustments for known and
measurable changes occurring within 24 months of the last month of the test
year.
The Company has obtained approval from the regulatory commissions in all
three states which it serves for lower rates for residential demand control
and controlled service, and in North Dakota and South Dakota for bulk
interruptible rates. Each of these special rates is designed to improve
efficient use of Company facilities, while encouraging use of electricity
instead of other fuels and giving customers more control over the size of
their electric bill.
All of the Company's electric rate schedules now in effect, except for
wheeling, certain municipal and area lighting services and certain
interruptible rates, provide for adjustments in rates based upon the cost of
fuel delivered to the Company's generating plants, as well as for adjustments
based upon the cost of the energy charge for electric power purchased by the
Company. Such adjustments are presently based upon a two-month moving average
in Minnesota and under the FERC, a three-month moving average in South Dakota,
and a four-month moving average in North Dakota and are applied to the next
billing after becoming applicable.
Capability and Demand
At December 31, 1993, the Company had base load net plant capability
totaling 550,869 kw, consisting of 242,874 kw from the Big Stone Plant (the
Company's 53.9% share), 153,175 kw from the Hoot Lake Plant, 149,450 kw from
the Coyote Plant (the Company's 35% share), and 5,370 kw from the Potlatch Co-
generation Plant near Bemidji, Minnesota (the Company's 50% share). In
addition to its base load capability, the Company has internal combustion
units and small diesel units, used chiefly for peaking and standby purposes,
with a total capability of 87,993 kw, and 4,030 kw of hydroelectric
capability. During 1993, the Company generated about 76% of its total kwh
sales and purchased the balance.
The Company has made arrangements to help meet its future base load
requirements, and continues to investigate other means for meeting such
requirements. The Company has an agreement with Northern States Power Company
("NSP") for the annual exchange of 75,000 kw of seasonal diversity capacity.
Pursuant to this agreement, NSP began providing the Company with 75,000 kw of
capacity for winter seasons on November 1, 1990, and the Company started
providing NSP with 75,000 kw of summer capacity on May 1, 1991. This is a
fifteen-year agreement which provides the Company a means of increasing the
capacity of its winter peaking system and better coordinates use of its
generating facilities with no additional investment. In addition, for the
1993-1994 winter season, the Company purchased 20,000 kw of capacity from
Lincoln Electric System ("LES"). The Company has extended its winter season
agreement with LES through the 1994-1995 winter season. The Company has an
agreement with Manitoba Hydro Electric Board to purchase 110,000 kw of
capacity for the summer seasons of 1994 through 1996. The Company also has a
direct control load management system which provides some flexibility to the
Company to effect reductions of peak load.
The Company is a member of the Mid-Continent Area Power Pool ("MAPP"),
which includes 46 investor-owned utilities, rural cooperatives, municipal
utilities, and other power suppliers in the North Central region of the United
States and in two Canadian provinces. The objective of MAPP is to coordinate
planning and operation of generating and interconnecting transmission
facilities to provide reliable and economic electric service to members'
customers. Customers served by MAPP members may, therefore, benefit from the
regional high voltage interconnections which are capable of transferring large
blocks of energy between systems. Also, high voltage interconnections permit
companies to buy and sell power among each other according to differing peak
demands.
The Company is a winter peaking utility and traditionally experiences its
peak system demand during the winter season. For the calendar year 1993, the
Company established a new record sixty-minute peak demand of 589,239 kw on
January 8, 1993. Taking into account additional capacity available to it in
January 1993 under power purchase contracts (including short-term
arrangements), as well as its own generating capacity, the Company's
capability of then meeting system demand, including reserve requirements
computed in accordance with accepted industry practice, amounted to
741,623 kw. In 1994 the Company expects moderate growth in peak demand as
compared to 1993. Due to very cold temperatures it is likely that a new
record sixty-minute peak demand was set early in 1994. The Company's
additional capacity available under power purchase contracts (as described
above), combined with the Company's generating capability and load management
control capabilities, are expected to meet 1994 system demand, including
industry reserve requirements.
Fuel Supply
Lignite coal is the principal fuel burned by the Company at its Big Stone
and Coyote generating plants. The majority of coal burned at the Hoot Lake
Plant since 1988 has been western subbituminous coal. The following table
shows for 1993 the sources of energy used to generate the Company's net output
of electricity:
Net
Kilowatt % of Total
Hours Kilowatt
Generated Hours
Sources (Thousands) Generated
Lignite Coal . . . . . . . . . . . . . 2,251,572 82.1%
Subbituminous Coal . . . . . . . . . . 466,458 17.0
Hydro . . . . . . . . . . . . . . . . . 25,719 .9
Oil . . . . . . . . . . . . . . . . . . 673 -
Total . . . . . . . . . . . . . . . 2,744,422 100.0%
The Company's supply of lignite coal (all of which comes from North
Dakota) is furnished by Knife River Coal Mining Company (a subsidiary of
Montana-Dakota Utilities Co., a co-owner of the Big Stone and Coyote Plants).
The Company has a contract for sufficient lignite coal to supply the Big Stone
Plant until 1995, with an option to renew for an additional 20 years subject
to certain contingencies. In 1992 the parties reached an agreement which
resulted in lower coal costs for the life of the contract. The Company has a
contract running through 1999 with Knife River Coal Mining Company for
sufficient lignite coal to operate its Hoot Lake Plant. The Company has
negotiated purchase agreements for fixed quantities of subbituminous coal as
needed for Hoot Lake Plant. The lignite coal contract with Knife River Coal
Mining Company for the Coyote Plant expires in 2016, with a 15-year renewal
option subject to certain contingencies, and is expected to provide the
plant's lignite coal requirements during the term of the contract.
It is the Company's practice to maintain minimum 30-day inventories (at
full output) of coal at the Big Stone and Coyote Plants, and a 10-day
inventory at the Hoot Lake Plant.
The lignite coal used at Big Stone Plant is transported in unit train
cars belonging to the plant owners. The coal transportation contract for the
Big Stone Plant with the Burlington Northern Railroad expires in 1995. A
freight rate reduction was negotiated for lignite deliveries to the Big Stone
Plant, effective in March 1990.
Transportation costs of lignite coal to Hoot Lake Plant are governed by
tariffs established pursuant to authority of the Interstate Commerce
Commission. The existing contract with Burlington Northern Railroad for
subbituminous coal deliveries at Hoot Lake was amended in 1993 and will remain
in effect for 1994 with annual renewals by mutual agreement. The Company also
has a subbituminous coal transportation agreement with Northern Coal
Transportation Company effective January 1993 covering coal moved from
Kennecott Energy's Spring Creek Mine to Hoot Lake Plant. This agreement
expires January, 1996. Freight rates were reduced in 1993 under both
agreements.
The Coyote Plant is a mine-mouth plant located in western North Dakota,
near the source of lignite coal used for generation. Because there are no
coal transportation costs, this plant has a relatively low fuel cost compared
to other Company units.
The average cost of coal consumed (including handling charges to the
plant sites) in cents per million BTU for each of the three years 1993, 1992
and 1991, was 100.7 cents, 100.5 cents and 104.1 cents, respectively. The
average cost of coal consumed (including handling charges to the plant sites)
per ton for each of the three years 1993, 1992 and 1991 was $13.75, $13.33 and
$13.60, respectively.
North Dakota imposes a severance tax on lignite at a flat rate of $ .75
per ton, plus an additional $ .02 per ton which is deposited in a lignite
research fund. The lignite coal used by the Company at its plants is surface
mined. The North Dakota laws relating to surface mining and the Federal
Surface Mining Control and Reclamation Act will continue to adversely affect
the price of lignite to the Company. Any increased costs of lignite would be
substantially recovered through the provisions in the Company's rate schedules
for adjustments in rates based upon the cost of fuel delivered to the
Company's generating plants. See "Rate Matters."
During 1990, the Company conducted test burns of tire-derived fuel
("TDF") at the Big Stone Plant and has received approval from the South Dakota
Department of Environment and Natural Resources to burn TDF. The quantity of
TDF burned as fuel during 1993 (1.6% of total fuel burned at the Big Stone
Plant), and expected to be burned in 1994, is insignificant when compared to
the lignite coal consumption at the Big Stone Plant. During 1991, test burns
of refuse derived fuel ("RDF") were conducted at Big Stone Plant and approval
to burn RDF as fuel was granted by the South Dakota Department of Environment
and Natural Resources. The quantity of RDF burned in 1993 (.8% of total fuel
burned at the Big Stone Plant) and expected to be burned in 1994 is
insignificant when compared to Big Stone Plant's lignite coal consumption.
General Regulation
Under the Minnesota Public Utilities Act, the Company is subject to the
jurisdiction of the Minnesota Public Utilities Commission ("MPUC") with
respect to rates, issuance of securities, public utility services,
construction of major utility facilities, establishment of exclusive assigned
service areas, contracts and arrangements with subsidiaries and other
affiliated interests, and other matters. The MPUC has the authority to assess
the need for large energy facilities and to issue or deny certificates of
need, after public hearings, within six months of an application to construct
such a facility.
The Minnesota Department of Public Service ("DPS") is responsible for
investigating all matters subject to the jurisdiction of the DPS or the MPUC,
and for the enforcement of MPUC orders. Among other things, the DPS is
authorized to collect and analyze data on energy and the consumption of
energy, develop recommendations as to energy policies for the Governor and the
Legislature of Minnesota and evaluate policies governing the establishment of
rates and prices for energy as related to energy conservation. The DPS acts
as state advocate in matters heard before the MPUC. The DPS also has the
power to prepare and adopt regulations to conserve and allocate energy in the
event of energy shortages and on a long term basis.
Under Minnesota law, every public utility that furnishes electric service
must make annual investments and expenditures in energy conservation
improvements, or make a contribution to the State's energy and conservation
account, in an amount equal to at least 1.5% of its gross operating revenues
from service provided in Minnesota. The DPS may require the Company to make
investments and expenditures in energy conservation improvements whenever it
finds that the improvement will result in energy savings at a total cost to
the utility less than the cost to the utility to produce or purchase an
equivalent amount of a new supply of energy. Such DPS orders are appealable
to the MPUC. Investments made pursuant to such orders generally are
recoverable costs in rate cases, even though ownership of the improvement may
be in the property owner rather than the utility. The Company is required to
submit, and the MPUC has approved, the Company's incentive mechanism for
recovery of conservation related expenditures for 1992 and 1993. The MPUC
requires the submission of a 15-year advance integrated resource plan by
jurisdictional utilities. The Company submitted its first plan in 1992, which
was approved by the MPUC in 1993, and will be required to submit its next plan
in 1994.
Pursuant to the Minnesota Power Plant Siting Act, the Minnesota
Environmental Quality Board ("EQB") has been granted the authority to regulate
the siting in Minnesota of large electric power generating facilities in an
orderly manner compatible with environmental preservation and the efficient
use of resources. To that end, the EQB is empowered, after study, evaluation,
and hearings, to select or designate in Minnesota sites for new electric power
generating plants (50,000 kw or more) and routes for transmission lines
(200 kv or more) and to certify such sites and routes as to environmental
compatibility.
The Company is subject to the jurisdiction of the Public Service
Commission of North Dakota with respect to rates, services, certain issuances
of securities and other matters. The North Dakota Energy Conversion and
Transmission Facility Siting Act grants the North Dakota Commission the
authority to approve sites in North Dakota for large electric generating
facilities and high voltage transmission lines. This Act is similar to the
Minnesota Power Plant Siting Act described above and affects new electric
power generating plants of 50,000 kw or more and new transmission lines of
115 kv or more.
The South Dakota Public Utilities Act subjects the Company to the
jurisdiction of the South Dakota Public Utilities Commission with respect to
rates, public utility services, establishment of assigned service areas, and
other matters. The Company is currently exempt from the jurisdiction of the
Commission with respect to the issuance of securities. Under the South Dakota
Energy Facility Permit Act, the South Dakota Commission has the authority to
approve sites in South Dakota for large energy conversion facilities
(100,000 kw or more) and transmission lines of 115 kv or more.
The Company is also subject to regulation by the Federal Energy
Regulatory Commission, successor to the Federal Power Commission, created
pursuant to the Federal Power Act of 1935, as amended. The FERC is an
independent agency which has jurisdiction over rates for sales for resale,
transmission and sale of electric energy in interstate commerce,
interconnection of facilities, and accounting policies and practices.
The Company is subject to various federal and state laws, including the
Federal Public Utility Regulatory Policies Act and the Energy Policy Act of
1992, which are intended to promote the conservation of energy and the
development and use of alternative energy sources.
The Company is unable to predict the impact on its operations resulting
from future regulatory activities by any of the above agencies, from any
future legislation or from any future tax which may be imposed upon the source
or use of energy.
Environmental Regulation
Impact of Environmental Laws The Company's existing generating plants
are subject to stringent standards and regulations regarding, among other
things, air, water and solid waste pollution, by agencies of the federal
government and the respective states where the Company's plants are located.
The Company estimates that it has expended in the five years ended December
31, 1993, approximately $9,700,000 for environmental control facilities
(excluding allowance for funds used during construction). Included in the
1994-1998 construction budget are approximately $980,000 for environmental
improvements for existing and new facilities, including $500,000 for 1994.
Air Quality Pursuant to the Federal Clean Air Act of 1970, the Clean Air
Act Amendments of 1990 and other amendments thereto (collectively the "Act"),
the United States Environmental Protection Agency ("EPA") has promulgated
national primary and secondary standards for certain air pollutants.
All primary fuel burned by the Company at its steam generating plants is
North Dakota lignite or western subbituminous coal with sulfur content
averaging less than one percent. Electrostatic precipitators have been
installed at the Company's principal units at the Hoot Lake Plant and at the
Big Stone Plant. A fabric filter to collect particulates from stack gases has
been installed on a smaller unit at Hoot Lake Plant. As a result, the
Company's units at Big Stone and Hoot Lake currently meet all federal and
state air quality and emission standards presently applicable.
The Coyote Plant is substantially the same design as the Big Stone Plant,
except for site-related items and the inclusion of sulfur dioxide removal
equipment. The removal equipment--referred to as a dry scrubber--consists of
a spray dryer, followed by a fabric filter, and is designed to desulphurize
hot gases from the stack without producing sludge, an unwanted by-product of
the conventional wet scrubber system. The Coyote Plant is currently operating
within all presently applicable federal and state air quality and emission
standards.
The Clean Air Act Amendments of 1990, in addressing acid deposition, will
impose new requirements on power plants in an effort to reduce national
emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx).
The national SO2 emission reduction goals are to be achieved through a
new market-based system under which power plants are to be allocated
"emissions allowances" that will require plants to either reduce their
emissions or acquire allowances from others to achieve compliance. The SO2
emission reduction requirements will be imposed in two phases, the first to
take effect in 1995 and the second in 2000.
The phase one requirements do not apply to any of the Company's plants.
The phase two standards apply to the Company's plants in the year 2000. The
Company believes that its current use of low sulfur coal at the Hoot Lake
Plant and the dry scrubbers installed at the Coyote Plant will enable the
facilities to comply with anticipated phase two limitations with regards to
SO2. Although the Big Stone Plant's current annual SO2 emissions meet
presently applicable standards, they are higher than the levels that will be
allowed by the phase two requirements. The Big Stone Plant can maintain
current levels of operation and meet the phase two requirements by using
allowances (alloted and/or purchased), by installing scrubbers and/or by
switching to subbituminous coal which is lower in sulfur emissions than
lignite which the plant currently uses. Big Stone Plant's lignite contract
expires in 1995. The cost of switching to subbituminous coal from lignite
would not adversely affect the Company's power plant operations based upon
current market price. In the unlikely event the Company decides to continue
to burn lignite, the Company's share of the cost of installing scrubbers at
its Big Stone Plant by the year 2000 is estimated to be approximately $54
million.
The national NOx emission reduction goals are to be achieved by imposing
mandatory emissions standards on individual sources. The standards will not
apply to the Company's plants until the year 2000. Based on the NOx emissions
limitations set forth in regulations recently issued by the EPA for boilers
such as those used at the Company's Hoot Lake Plant, but subject to an
evaluation of the results of continuous emission monitoring expected to begin
at Hoot Lake in 1994, the Company currently anticipates that the cost of
complying with the limitations to be applicable to Hoot Lake will not be
material. The Act requires EPA to specify before January 1, 1997 the NOx
limitations for cyclone boilers such as those used at Big Stone and Coyote.
Because the EPA has not yet issued such regulations, the Company is unable to
determine the NOx emissions limitations that will be applicable to those
plants in the year 2000 or the cost to comply with such limitations.
The Clean Air Act Amendments of 1990 contain a list of toxic air
pollutants to be regulated. The list includes certain substances believed to
be emitted by the Company's plants. The Act calls for EPA studies of the
effects of emissions of the listed pollutants by electric utility steam
generating plants. Because promulgation of rules by the EPA has not been
completed however, it is not possible to assess at this time whether, or to
what extent, this legislation will ultimately impact the Company.
Water Quality The Federal Water Pollution Control Act Amendments of
1972, and amendments thereto, provide for, among other things, the imposition
of effluent limitations to regulate discharges of pollutants, including
thermal discharges, into the water of the United States, and the EPA has
established effluent guidelines for the steam electric power generating
industry. Discharges must also comply with state water quality standards.
The Company has all federal and state water permits presently necessary
for the operation of its Big Stone Plant. A water discharge permit for the
Hoot Lake Plant was renewed in 1992 for a five year term. A renewal permit
for the Coyote Plant was renewed in 1993 also for a five year term. The
Company owns five small dams on the Otter Tail River which are subject to FERC
licensing requirements. A license for all five dams was issued on December 5,
1991. Total nameplate rating of the five dams is 3,450 kw (net unit capability
of 3,480 kw at December 31, 1993).
Solid Waste Permits for disposal of ash and other solid wastes have been
issued for the Company's Big Stone and Coyote Plants. A renewal permit is
pending for the Company's Hoot Lake Plant and the Company anticipates that it
will obtain this renewal in due course. The EPA has promulgated various solid
and hazardous waste regulations and guidelines pursuant to, among other laws,
the Resource Conservation and Recovery Act of 1976, the Solid Waste Disposal
Act Amendments of 1980, and the Hazardous and Solid Waste Amendments of 1984,
which provide for, among other things, the comprehensive control of various
solid and hazardous wastes from their generation to final disposal. The
states of Minnesota, North Dakota and South Dakota have also adopted rules and
regulations pertaining to solid and hazardous waste. The total impact on the
Company of the various solid and hazardous waste statutes and regulations
enacted by the Federal Government or the states of Minnesota, North Dakota and
South Dakota is not certain at this time. To date, the Company has incurred
no significant costs as a result of these laws.
In 1980, the United States enacted the Comprehensive Environmental
Response, Compensation and Liability Act, commonly known as the Federal
Superfund law, and in 1986, reauthorized and amended the 1980 Act. In 1983,
Minnesota adopted the Minnesota Environmental Response and Liability Act,
commonly known as the Minnesota Superfund law. In 1988, South Dakota enacted
the Regulated Substance Discharges Act, commonly called the South Dakota
Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost
Recovery Act. Among other requirements, the federal and state acts establish
environmental response funds to pay for remedial actions associated with the
release or threatened release of certain regulated substances into the
environment. These federal and state Superfund laws also establish liability
for cleanup costs and damage to the environment resulting from such releases
or threatened releases of regulated substances. The Minnesota Superfund law
also creates liability for personal injury and economic loss under certain
circumstances. The Company is unable to determine the total impact of the
Superfund laws on its operations at this time but has not incurred any
significant costs to date related to these laws.
The Federal Toxic Substances Control Act of 1976 regulates, among other
things, polychlorinated byphenyls (PCBs). The EPA has enacted regulations
concerning the use, storage and disposal of PCBs. The Company completed a
program for removal of all PCB filled transformers and capacitors by the end
of 1987 and received Certificates of Disposal in 1989. The Company completed
removal of PCB contaminated mineral oil dielectric fluid from all substation
transformers in 1991 and continues to remove such oil from voltage regulators
as well as other electrical equipment.
Health Effects of Electric and Magnetic Fields Although research
conducted to date has found no conclusive evidence that electric and magnetic
fields affect health, a few studies have suggested a possible connection with
cancer. The utility industry is funding studies. The ultimate impact, if
any, of this issue on the Company and the utility industry is impossible to
predict.
Franchises
At December 31, 1993, the Company had franchises in all of the 371
incorporated municipalities which it serves. All franchises are nonexclusive
and generally were obtained for 20-year terms, with varying expiration dates.
No franchises are required to serve unincorporated communities in any of the
three states which the Company serves. The Company believes that the
situation with regard to its franchises is satisfactory.
HEALTH SERVICES OPERATIONS
General
Health Services Operations consists of businesses involved in the sale,
service, rental, refurbishing and operation of medical imaging equipment and
the sale of related supplies and accessories to various medical institutions
primarily in the Midwest United States. All of these business were acquired
in 1993 by the Company's wholly-owned subsidiary Mid-States Development, Inc.
On a fully consolidated basis, the Company derived 12% of its operating
revenues from this segment in 1993.
Subsidiaries comprising Health Services Operations include the following:
Diagnostic Medical Systems, Inc. ("DMS"), located in Fargo, ND,
sells, services and refurbishes diagnostic medical imaging equipment
manufactured primarily by Philips Medical Systems ("Philips"),
including fluoroscopic, radiograhic and mammography equipment, along
with ultrasound, computerized tomography ("CT") scanners, magnetic
resonance imaging ("MRI") scanners, cardiac cath labs, and radiation
therapy equipment for the treatment of cancer. DMS recently entered
into a five year dealer agreement with Philips, which can be
terminated by Philips upon eighteen months notice and certain other
circumstances. DMS is also a supplier for Kodak, DuPont, and Fuji
in the medical film and accessory business. DMS markets mainly to
hospitals, clinics and mobile services in North Dakota, South
Dakota, Minnesota, Montana and Wyoming. Almost 80% of the hospitals
served by DMS have 50 or fewer beds. DMS also offers, through its
subsidiaries, mobile CT and MRI service in the Upper Midwest and
Central United States.
Mobile Imaging, Inc., located in Fargo, ND, and its subsidiaries are
engaged primarily in providing mobile CT and MRI services in the
Upper Midwest, and also provide interim scanner service on a
national basis.
Imaging Plus, Inc., located in Fargo, ND, provides management,
marketing and administrative services for diagnostic medical imaging
companies, including Mobile Imaging, Inc. and a subsidiary of DMS.
Combined, the Health Service subsidiaries cover the three basics of the
medical imaging industry: (1) operating technicians who do the imaging of
patients of hospitals and clinics; (2) the equipment function that researches,
buys, sells, owns, rents, refurbishes and maintains the imaging machines; and
(3) central office specialists who provide scheduling, billing personnel and
administrative support.
Due to the complex nature of the equipment, the diagnostic medical
imaging industry is both technology intensive and capital intensive. The
industry is highly competitive, with competition based primarily on the
quality of the equipment and the availability of service. The Company's
Health Services businesses compete with a number of other companies that make,
sell, rent and service diagnostic medical imaging equipment, including large
manufacturers other than Philips and their respective distributors. The
Company estimates that its market share is greater than fifty percent in the
Upper Midwest region.
The Company continues to investigate acquisitions of additional
businesses and expects continued growth in this area.
General Regulation
Operation of the Health Services subsidiaries will be subject to the
effects of pending health care legislation, the outcome of which cannot be
accurately assessed at this time. As an efficient, low-cost provider of
certain health services and equipment, management believes that the Health
Services businesses are in line with the goals of national health-care reform.
DIVERSIFIED OPERATIONS
General
The Company's Diversified Operations consists of business that are
diversified in such areas as manufacturing, electrical and telephone
contracting, radio broadcasting, waste incinerating, and telephone/cable TV
utility. On a fully consolidated basis, the Company derived 15% of its
operating revenues from these smaller diversified business during 1993 and
1992, and 10% during 1991.
The following is a brief description of each of these businesses:
Precision Machine of North Dakota, Inc., located in West Fargo, ND,
uses computer-controlled lathes and milling machines to produce
parts for manufacturers.
Moorhead Electric, Inc., located in Moorhead, MN, provides
commercial and industrial wiring of large buildings, constructs and
maintains telecommunications and power distribution systems, and
provides computer networking.
Aerial Contractors, Inc., with headquarters in West Fargo, ND,
constructs and maintains overhead and underground electric,
telephone, communications, and cable television lines.
Dakota Machine Tool, Inc., located in West Fargo, ND, is primarily
engaged in metal fabrication of large machines that handle and
refine sugar beets. Tec Steel, a division of Dakota Machine, cuts
metal parts for such machines and sells the same service to other
manufacturers.
Glendale Machining, Inc. of Pelican Rapids, MN, machines parts for
manufacturers.
KFGO Inc. operates both AM and FM commercial radio stations
broadcasting from Fargo, ND.
Quadrant Co. ("Quadrant") operates a municipal waste burning
facility located in Perham, MN. Pursuant to agreements which expire
in 1995, Quadrant receives a processing fee from five Minnesota
counties for disposal of mixed waste and sells the steam generated
from the incineration process to two customers. During 1994,
Quadrant's management will be evaluating its future business plans.
Midwest Information Systems, Inc.("MIS"), headquartered in Parkers
Prairie, MN, owns two operating telephone companies serving over
4000 customers and a cable television company serving approximately
600 customers. MIS is also involved in long-distance
transport, fiber-optic transmission facilities and the sale of
direct broadcast satellite television programming and equipment.
With the exception of Quadrant, which was founded by the Company in 1985,
each of these businesses was acquired by the Company since 1989. An
additional acquisition (a radio broadcasting company located in Morris, MN)
was finalized in January, 1994. Quadrant is a wholly-owned subsidiary of
Minnesota Dakota Generating Company ("MDG"), which in turn is a wholly-owned
subsidiary of the Company. MIS is a wholly-owned subsidiary of North Central
Utilities, Inc., a subsidiary of MDG formed for the purpose of acquiring
regulated telephone companies. Each of the other subsidiaries described above
are owned by Mid-States Development, Inc., which is also a wholly-owned
subsidiary of MDG.
Each of the businesses in Diversified Operations is subject to competition, as
well as the effects of general economic conditions, in their respective
industries.
The Company continues to investigate acquisitions of additional
businesses (both utility and nonutility) and expects continued growth in this
area.
General Regulation
The Company's operating telephone subsidiaries are subject to the
regulatory authority of the MPUC regarding rates and charges for telephone
services, as well as other matters. The operating telephone subsidiaries must
keep on file with the Minnesota DPS schedules of such rates and charges, and
any requests for changes in such rates and charges must be filed for approval
by the MPUC. The telephone industry is also subject generally to rules and
regulations of the Federal Communications Commission ("FCC"). The Company's
operating cable television subsidiary is regulated by federal and local
authorities. The Company's radio broadcasting subsidiaries are regulated by
the FCC.
Environmental Regulation
The Minnesota Pollution Control Agency issued an air emission facility
permit, authorizing the incineration of up to 116 tons of municipal solid
waste per day at Quadrant's facility in addition to the incineration of other
allowable wastes and petroleum derived used oil. The permit expired in May
1990; however the facility has been granted permission by the Minnesota
Pollution Control Agency to operate under the conditions of the expired permit
until operating rules for incinerators are fully developed (see discussion
below). The subsidiary has formally requested a renewal of the permit.
The state of Minnesota has recently promulgated rules relating to
storage, transport, testing and disposal of ash from municipal solid waste
combustors, which are not expected to have a material adverse effect on the
operations of Quadrant. The state of Minnesota has proposed, and the EPA is
expected to propose, rules covering air emissions from municipal waste
combustors of this size. Although the effects of such regulations
on Quadrant's operations cannot be accurately predicted at this time,
additional costs are expected to result if the regulations take effect.
CONSTRUCTION PROGRAM & FINANCING
The Company is continually expanding, replacing and improving its
electric utility facilities. During 1993, the Company invested approximately
$23,781,000 (including allowance for funds used during construction) for
additions to its electric utility properties. During the five years ended
December 31, 1993, the Company had gross electric property additions,
including construction work in progress, of approximately $114,189,000 and
gross retirements of approximately $27,934,000. During 1993, capital
expenditures of approximately $3,000,000 were also made in each of Health
Services Operations and Diversified Operations.
Total capital expenditures for the Company and its subsidiaries during
the five-year period 1994-1998 are estimated to be approximately $146,000,000.
Of this $14,000,000 is for Health Services Operations and $9,000,000 for
Diversified Operations. The Company estimates that during the five years 1994
through 1998 it will invest for electric utility construction approximately
$123,000,000 (including allowance for funds used during construction). The
Company has no firm plans for additional base load construction. The majority
of electric utility expenditures for the five-year period 1994 through 1998
will be for work related to the Company's transmission and distribution
system.
The Company estimates that funds internally generated, combined with
funds on hand, will be sufficient to provide for all of its 1994-1998 electric
construction program expenditures (including allowance for funds used during
construction) and to meet all sinking fund payments for First Mortgage Bonds
in the next five years. Additional short or long-term financing will be
required in the period 1994-1998 in connection with the maturity of First
Mortgage Bonds and a Long-Term Lease Obligation ($21,000,000), in the event
the Company decides to refund or retire early any of its presently outstanding
debt or Cumulative Preferred Shares, to complete its Common Share repurchase
program or for other corporate purposes.
The foregoing estimates of capital expenditures and funds internally
generated may be subject to substantial changes due to unforeseen factors,
such as changed economic conditions, competitive conditions, technological
changes, new environmental and other governmental regulations, changed tax
laws and rate regulation.
On October 13, 1993, the Company sold $4,000,000 of a new series of $6.75
Cumulative Preferred Shares. The proceeds were used for the redemption on
November 12, 1993, of the Company's outstanding $9.50 Cumulative Preferred
Shares at an aggregate redemption price of $4,080,000, plus accrued dividends
to the redemption date. On November 1, 1993, the Company retired $4,970,000
of First Mortgage Bonds, 4.625% Series of 1993.
The Company sold on December 7, 1993, $3,010,000 of Industrial
Development Refunding Revenue Bonds, 5% Series of 2002, and on December 15,
1993, $10,400,000 of Pollution Control Refunding Revenue Bonds, Variable
Series of 2012. The proceeds were used for the redemption of the Company's
First Mortgage Bonds, 7.10% Series of 2003 and 5.90% Series of 2004 in the
aggregate principal amount of $13,445,000.
As of December 31, 1993, the Company had unutilized net fundable property
available for the issuance of more than $13,000,000 principal amount of
additional First Mortgage Bonds and also was entitled to issue in excess of
$102,000,000 principal amount of additional Bonds on the basis of Bonds
theretofore retired.
The Company's operating subsidiaries are responsible for obtaining their
own financing after the Company's initial equity investment and have developed
financing arrangements with various banks. The Company does not intend to
make or guarantee loans to its subsidiaries, lend a subsidiary money or cosign
on any borrowing.
The Company has access to short-term borrowing resources and has
authority from the Minnesota Public Utilities Commission to have outstanding
during 1994 such borrowings in an amount not to exceed $50,000,000. The
Company and its subsidiaries currently have established bank lines of credit
totaling $19,050,000 of which $4,437,000 was used at December 31, 1993.
EMPLOYEES
The Company and its subsidiaries had approximately 1,124 full-time
employees at December 31, 1993. A total of 465 employees are represented by
local unions of the International Brotherhood of Electrical Workers, of which
429 are employees of the Electrical Operations segment and are covered by a
three-year labor contract expiring November 1, 1996. The Company has never
experienced any strike, work stoppage, or strike vote, and regards its present
relations with employees as very good.
Item 2. PROPERTIES
The Coyote Station, which commenced operation in 1981, is a 414,000 kw
(nameplate rating) mine-mouth plant located in the lignite coal fields near
Beulah, North Dakota and is jointly owned by the Company, Northern Municipal
Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service
Company. The Company has a 35% interest in the plant and was the project
manager in charge of construction. Montana-Dakota Utilities Co., in whose
service territory the plant is located, is the operating manager of the plant.
The Company, jointly with Northwestern Public Service Company and
Montana-Dakota Utilities Co., owns the 414,000 kw (nameplate rating) Big Stone
Plant in northeastern South Dakota which commenced operation in 1975. The
Company, for the benefit of all three utilities, was in charge of construction
and is now in charge of operations. The Company owns 53.9% of the plant.
Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of
three separate generating units with a combined rating of 127,000 kw. The
oldest Hoot Lake Plant generating unit was constructed in 1948 (7,500 kw
nameplate rating) and a subsequent unit was added in 1959 (53,500 kw nameplate
rating). A third unit was added in 1964 (66,000 kw nameplate rating) and
later modified during 1988, to provide cycling capability, allowing this unit
to be more efficiently brought on-line from a standby mode.
At December 31, 1993, the Company's transmission facilities, which are
inter-connected with lines of other public utilities, consisted of 48 miles of
345 kv lines; 363 miles of 230 kv lines; 567 miles of 115 kv lines; and 4,268
miles of lower voltage lines, principally 41.6 kv. The Company owns the
uprated portion of the 48 miles of the 345 kv line, with Minnkota Power
Cooperative retaining title to the original 230 kv construction.
All of the Company's electric utility properties, with minor exceptions,
are subject to the lien of the Company's Indenture of Mortgage dated July 1,
1936, as amended and supplemented, securing its First Mortgage Bonds.
Item 3. LEGAL PROCEEDINGS
Not Applicable.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the three
months ended December 31, 1993.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1994)
Set forth below is a summary of the principal occupations and business
experience during the past five years of executive officers of the Company:
DATES ELECTED
NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE
John C. MacFarlane (54) 4/8/91 Present: Chairman, President and
Chief Executive Officer
Prior to
4/8/91 President and Chief Executive
Officer
Dennis R. Emmen (60) 4/13/81 Present: Senior Vice President,
Finance,Treasurer and Chief
Financial Officer
Marlowe E. Johnson (49) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Prior to
4/12/93 Division Manager, Jamestown
Douglas L. Kjellerup (52) 4/12/93 Present: Vice President, Marketing
and Development
4/8/91 Vice President, Planning and
Development
Prior to
4/8/91 Director, Strategic Planning and
Productivity
LeRoy S. Larson (48) 4/12/93 Present: Vice President, Customer
Service, Minnesota and South Dakota
4/13/92 Vice President, Division
Operations, Minnesota and South
Dakota
Prior to
4/13/92 Division Manager, Morris
Richard W. Muehlhausen (55) 1/1/78 Present: Vice President, Corporate
Services
Jay D. Myster (55) 4/12/82 Present: Vice President,
Governmental and Legal, and
Corporate Secretary
Earl D. Sjoberg (61) 4/10/89 Present: Vice President,
Electrical
Prior to
4/10/89 Manager, Division Engineering
Ward L. Uggerud (44) 4/10/89 Present: Vice President,
Operations
Prior to
4/10/89 Director, System Operations
Andrew E. Anderson (54) 1/1/78 Present: Controller
The term of office of each of the officers is one year, and there are no
arrangements or understanding between individual officers or any other persons
pursuant to which he was selected as an officer.
No family relationships exist between any officers of the Company.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The information required by this Item is incorporated by reference to
Dividends" on page 48, to first sentence under "Buying and Selling" on
page 48, to "Selected Consolidated Financial Data" on page 23 and to
"Quarterly Information" on page 45, of the Company's 1993 Annual Report to
Shareholders, filed as an Exhibit hereto.
Item 6. SELECTED FINANCIAL DATA
The information required by this Item is incorporated by reference to
"Selected Consolidated Financial Data" on Page 23 of the Company's 1993 Annual
Report to Shareholders, filed as an Exhibit hereto.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information required by this Item is incorporated by reference to
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" on Pages 24 through 31 of the Company's 1993 Annual Report to
Shareholders, filed as an Exhibit hereto.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item is incorporated by reference to
"Quarterly Information" on Page 45 and the Company's audited financial
statements on Pages 32 through 45 of the Company's 1993 Annual Report to
Shareholders excluding "Report of Management" on page 32, filed as an Exhibit
hereto.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is incorporated by reference from
the in-formation under "Nominees for Election as Directors" in the Company's
definitive Proxy Statement dated March 9, 1994. The information regarding
executive officers is set forth in Item 4A hereto.
Item 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from
the in-formation under "Summary Compensation Table", "Pension and Supplemental
Retirement Plans", "Severance Agreements", "Directors' Compensation", and
"Compensation Committee Interlocks and Insider Participation" in the
Company's definitive Proxy Statement dated March 9, 1994.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference from
the in-formation under "Outstanding Voting Shares" and "Security Ownership of
Management" in the Company's definitive Proxy Statement dated March 9, 1994.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from
the in-formation under "Nominees for Election as Directors" in the Company's
definitive Proxy Statement dated March 9, 1994.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) List of documents filed:
(1) and (2) See Table of Contents on Page 20 hereof.
(3) See Exhibit Index on Pages 25 through 33 hereof.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of
certain instruments defining the rights of holders of certain
long-term debt of the Company are not filed, and in lieu
thereof, the Company agrees to furnish copies thereof to the
Securities and Exchange Commission upon request.
(b) Reports on Form 8-K:
No reports on Form 8-K have been filed during the quarter ended
December 31, 1993.
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.
OTTER TAIL POWER COMPANY
By D. R. Emmen
D. R. Emmen
Senior Vice President,
Finance, Treasurer
and Chief Financial
Officer
Dated: March 25, 1994
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 and in the capacities and on the dates indicated:
Signature and Title
John C. MacFarlane )
Chairman, President and )
Chief Executive Officer )
(principal executive officer) )
and Director )
)
D. R. Emmen )
Senior Vice President, Finance, )
Treasurer and Chief Financial Officer )
(principal financial officer) )
and Director )
)
Andrew E. Anderson ) By D. R. Emmen
Controller ) D. R. Emmen
(principal accounting officer) ) Pro Se and Attorney-in-Fact
) Dated March 25, 1994
Thomas M. Brown, Director )
)
Dayle Dietz, Director )
)
Maynard D. Helgaas, Director )
)
Kenneth L. Nelson, Director )
)
Nathan I. Partain, Director )
)
Robert N. Spolum, Director )
)
James L. Stengel, Director )
OTTER TAIL POWER COMPANY
TABLE OF CONTENTS
FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL
SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED
DECEMBER 31, 1993
The following items are included in this annual report by reference to the
registrant's Annual Report to Shareholders for the year ended December 31,
1993:
Page in
Annual
Report to
Shareholders
Financial Statements:
Independent Auditors' Report . . . . . . . . . . . . . . . . . 33
Consolidated Balance Sheets, December 31, 1993 and 1992 . . . 32 & 33
Consolidated Statements of Income for the Three Years
Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 34
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 35
Consolidated Statements of Retained Earnings for the
Three Years Ended December 31, 1993 . . . . . . . . . . . . 35
Consolidated Statements of Capitalization, December 31, 1993
and 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Notes to Consolidated Financial Statements . . . . . . . . . . 37-45
Selected Consolidated Financial Data for the Five Years
Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . 23
Quarterly Data for the Two Years Ended
December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . 45
The following supplemental financial data included herein should be read in
conjunction with the financial statements referenced above:
Page in
Form 10-K
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . 21
Supplemental Financial Schedules:
V - Property, Plant and Equipment . . . . . . . . . . . . . . 22
VI - Accumulated Provision for Depreciation and
Amortization of Property, Plant and Equipment . . . . . 23
IX - Short-Term Borrowings . . . . . . . . . . . . . . . . . . . 24
Schedules other than those listed above are omitted because of the absence of
the conditions under which they are required or because the information
required is included in the financial statements or the notes thereto.
INDEPENDENT AUDITORS' REPORT
Otter Tail Power Company:
We have audited the consolidated balance sheets and statements of
capitalization of Otter Tail Power Company and its subsidiaries as of December
31, 1993 and 1992, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended
December 31, 1993, and have issued our report thereon dated January 31 1994;
such consolidated financial statements and report are included in your 1993
Annual Report to Shareholders and are incorporated herein by reference. Our
audits also included the financial statement schedules of Otter Tail Power
Company and its subsidiaries for each of the three years in the period ended
December 31, 1993, as listed in the accompanying Table of Contents. These
financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion based on our audits.
In our opinion, such financial statement schedules, when considered in
relation to the basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
DELOITTE & TOUCHE
Deloitte & Touche
Minneapolis, Minnesota
January 31, 1994
SCHEDULE V
OTTER TAIL POWER COMPANY
PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1991, 1992, AND 1993
- -----------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
RETIREMENTS OR OTHER CHANGES
STRAIGHT-LINE BALANCE AT SALES--AT ORIGINAL AND RECLASSI- BALANCE
DEPRECIATION BEGINNING ADDITIONS AT COST, ESTIMATED FICATIONS - AT END
CLASSIFICATION RATES OF YEAR COST IF NOT KNOWN ADD (DEDUCT) OF YEAR
- -------------------------------- -------------- ---------------- ----------------- ------------------- ----------------- ----------
December 31, 1993: (THOUSANDS OF DOLLARS)
Electric Utility Plant:
Plant In Service:
Steam Production 2.57% 284,003 3,344 732 0 286,615
Hydro Production Plant 0.39% 1,870 58 0 0 1,928
Other Production Plant 2.66% 10,058 13 0 0 10,071
Transmission 1.97% 123,225 4,487 564 250 127,398
Distribution 3.30% 180,998 9,837 1,719 (252) 188,864
General 5.77% 61,901 4,512 2,008 1 64,406
Construction Work In Progress 6,812 1,529 0 0 8,341
---------------- ----------------- ------------------- ----------------- ----------
Total Electric Utility Plant 668,867 23,780 5,023 (1) 687,623
Other Property 22,700 12,651 1,485 760 34,626
---------------- ----------------- ------------------- ----------------- ----------
Total 691,567 36,431 6,508 759 722,249
================ ================= =================== ================= ==========
December 31, 1992:
Electric Utility Plant:
Plant In Service:
Steam Production 2.85% 281,691 4,468 2,156 0 284,003
Hydro Production Plant 1.19% 1,810 69 9 0 1,870
Other Production Plant 2.60% 10,053 8 3 0 10,058
Transmission 1.87% 120,213 3,525 621 108 123,225
Distribution 2.76% 174,026 8,547 1,465 (110) 180,998
General 5.87% 57,642 6,359 2,082 (18) 61,901
Construction Work In Progress 9,400 (2,588) 0 0 6,812
---------------- ----------------- ------------------- ----------------- ----------
Total Electric Utility Plant 654,835 20,388 6,336 (20) 668,867
Other Property 14,903 8,059 202 (60) 22,700
---------------- ----------------- ------------------- ----------------- ----------
Total 669,738 28,447 6,538 (80) 691,567
================ ================= =================== ================= ==========
December 31, 1991: Electric Utility Plant:
Plant In Service:
Steam Production 2.93% 271,881 11,284 1,474 0 281,691
Hydro Production Plant .092% 1,765 46 1 0 1,810
Other Production Plant 2.60% 10,050 3 0 0 10,053
Transmission 1.85% 117,479 3,047 330 17 120,213
Distribution 2.85% 168,179 7,783 1,937 1 174,026
General 5.87% 54,571 7,013 3,924 (18) 57,642
Construction Work In Progress 14,349 (4,949) 0 0 9,400
---------------- ----------------- ------------------- ---------------- ------------
Total Electric Utility Plant 638,274 24,227 7,666 0 654,835
Other Property 13,116 1,787 0 0 14,903
---------------- ----------------- ------------------- ---------------- ------------
Total 651,390 26,014 7,666 0 669,738
================ ================= =================== ================ ============
OTTER TAIL POWER COMPANY SCHEDULE VI
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1991, 1992, AND 1993
- -----------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
DEPRECIATION AND
AMORTIZATION CHARGED: DEDUCTIONS: OTHER
BALANCE AT TO CLEARING CHANGES BALANCE
BEGINNING TO ACCOUNTS PROPERTY NET AND RECLAS- AT END
CLASSIFICATION OF YEAR EXPENSE AND OTHER RETIRED SALVAGED SIFICATIONS OF YEAR
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 1993: (THOUSANDS OF DOLLARS)
Electric Utility Plant:
Steam production 125960 7105 151 732 470 0 132014
Hydro production 1452 6 0 0 0 0 1458
Other production plan 4472 267 0 0 0 0 4739
Transmission 38543 2445 0 542 141 -10 40295
Distribution 58257 6046 0 1578 404 -5 62316
General 19571 2201 1325 2008 -191 -34 21246
---------- ---------- ---------- ---------- ---------- ---------- ---------
Total 248255 18070 1476 4860 824 -49 262068
Other Property 4408 4031 0 122 0 0 8317
---------- ---------- ---------- ---------- ---------- ---------- ---------
TOTAL 252663 22101 1476 4982 824 -49 270385
========== ========== ========== ========== ========== ========== =========
December 31, 1992:
Electric Utility Plant:
Steam production 120222 7865 180 2156 151 0 125960
Hydro production 1443 19 0 9 1 0 1452
Other production pla 4214 261 0 3 0 0 4472
Transmission 36990 2262 0 621 88 0 38543
Distribution 55335 4854 0 1465 499 32 58257
General 18302 2116 1258 2082 -154 -177 19571
---------- ---------- ---------- ---------- ---------- ---------- ---------
Total 236506 17377 1438 6336 585 -145 248255
Other Property 2821 1618 0 31 0 0 4408
---------- ---------- ---------- ---------- ---------- ---------- ---------
TOTAL 239327 18995 1438 6367 585 -145 252663
========== ========== ========== ========== ========== ========== =========
December 31, 1991:
Electric Utility Plant:
Steam production 114087 7865 180 1271 639 0 120222
Hydro production 1429 15 0 1 0 0 1443
Other production pla 3954 260 0 0 0 0 4214
Transmission 35207 2191 0 330 78 0 36990
Distribution 52340 4850 0 1938 178 261 55335
General 18522 1891 1266 3924 -350 197 18302
---------- ---------- ---------- ---------- ---------- ---------- ---------
Total 225539 17072 1446 7464 545 458 236506
Other Property 1933 888 0 0 0 0 2821
---------- ---------- ---------- ---------- ---------- ---------- ---------
TOTAL 227472 17960 1446 7464 545 458 239327
========== ========== ========== ========== ========== ========== =========
OTTER TAIL POWER COMPANY
SCHEDULE IX
SHORT-TERM BORROWINGS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
MAXIMUM AMOUNT
OUTSTANDING AVERAGE AMOUNT WEIGHTED
BALANCE WEIGHTED AVERAGE DURING THE OUTSTANDING AVERAGE INTEREST
CATEGORY OF AGGREGATE AT END INTEREST RATE PERIOD DURING RATE DURING
SHORT-TERM BORROWINGS OF PERIOD (at December 31) (at Month End) THE PERIOD (1) THE PERIOD (2)
(in thousands) (in thousands) (in thousands)
Year Ended December 31, 1993
Notes Payable -- -- $1,200 $ 28 3.78%
Year Ended December 31, 1992
Notes Payable -- -- -- -- --
Year Ended December 31, 1991
Notes Payable -- -- $2,500 $ 176 7.12%
(1) Average amount outstanding during the period is computed by dividing the total of daily outstanding principal
balances by 365.
(2) Average interest rate for the year is computed by dividing the actual short-term interest by the average short-
term debt outstanding.
[TEXT]
Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 1993
Previously Filed
As
Exhibit
File No. No.
3-A --Restated Articles of
Incorporation, as amended
(including resolutions
creating outstanding series
of Cumulative Preferred
Shares).
3-C 33-46071 4-B --Bylaws as amended through
April 11, 1988.
4-D-1 2-14209 2-B-1 --Twenty-First Supplemental
Indenture from the Company to
First Trust Company of Saint
Paul and Russel M. Collins, as
Trustees, dated as of July 1,
1958.
4-D-2 2-14209 2-B-2 --Twenty-Second Supplemental
Indenture dated as of
July 15, 1958.
4-D-3 33-32499 4-D-6 --Thirty-First Supplemental
Indenture dated as of
February 1, 1973.
4-D-4 33-32499 4-D-7 --Thirty-Second Supplemental
Indenture dated as of
January 18, 1974.
4-D-5 2-66914 2-L-13 --Thirty-Ninth Supplemental
Indenture dated as of
October 15, 1979.
4-D-6 33-46070 4-D-11 --Forty-Second Supplemental
Indenture dated as of
December 1, 1990.
4-D-7 33-46070 4-D-12 --Forty-Third Supplemental
Indenture dated as of
February 1, 1991.
4-D-8 33-46070 4-D-13 --Forty-Fourth Supplemental
Indenture dated as of
September 1, 1991
4-D-9 8-K dated 4-D-15 --Forty-Fifth Supplemental
7/24/92 Indenture dated as of
July 1, 1992
10-A 2-39794 4-C --Integrated Transmission
Agreement dated August 25,
1967, between Cooperative
Power Association and the
Company.
10-A-1 10-K for year 10-A-1 --Amendment No. 1, dated as
ended 12/31/92 of September 6, 1979, to
Integrated Transmission
Agreement, dated as of
August 25, 1967, between
Cooperative Power Associa-
tion and the Company.
10-A-2 10-K for year 10-A-2 --Amendment No. 2, dated as of
ended 12/31/92 November 19, 1986, to Integ-
rated Transmission Agreement
between Cooperative Power
Association and the Company.
10-C-1 2-55813 5-E --Contract dated July 1, 1958,
between Central Power Elec-
tric Corporation, Inc.,
and the Company.
10-C-2 2-55813 5-E-1 --Supplement Seven dated
November 21, 1973.
(Supplements Nos. One
through Six have been super-
seded and are no longer in
effect.)
10-C-3 2-55813 5-E-2 --Amendment No. 1 dated
December 19, 1973, to
Supplement Seven.
10-C-4 10-K for year 10-C-4 --Amendment No. 2 dated
ended 12/31/91 June 17, 1986, to Supple-
ment Seven.
10-C-5 10-K for year 10-C-5 --Amendment No. 3 dated
ended 12/31/92 June 18, 1992, to Supple-
ment Seven.
10-C-6 --Amendment No. 4 dated
January 18, 1994, to Supple-
ment Seven.
10-D 2-55813 5-F --Contract dated April 12,
1973, between the Bureau of
Reclamation and the Company.
10-E-1 2-55813 5-G --Contract dated January 8,
1973, between East River
Electric Power Cooperative
and the Company.
10-E-2 2-62815 5-E-1 --Supplement One dated
February 20, 1978.
10-E-3 10-K for year 10-E-3 --Supplement Two dated
ended 12/31/89 June 10, 1983.
10-E-4 10-K for year 10-E-4 --Supplement Three dated
ended 12/31/90 June 6, 1985.
10-E-5 10-K for year 10-E-5 --Supplement No. Four, dated
ended 12/31/92 as of September 10, 1986.
10-E-6 10-K for year 10-E-6 --Supplement No. Five, dated
ended 12/31/92 as of January 7, 1993.
10-E-7 --Supplement No. Six, dated
as of December 2, 1993.
10-F 10-K for year 10-F --Agreement for Sharing
ended 12/31/89 Ownership of Generating
Plant by and between the
Company, Montana-Dakota
Utilities Co., and North-
western Public Service
Company (dated as of
January 7, 1970).
10-F-1 10-K for year 10-F-1 --Letter of Intent for pur-
ended 12/31/89 chase of share of Big Stone
Plant from Northwestern
Public Service Company
(dated as of May 8, 1984).
10-F-2 10-K for year 10-F-2 --Supplemental Agreement No. 1
ended 12/31/91 to Agreement for Sharing
Ownership of Big Stone Plant
(dated as of July 1, 1983).
10-F-3 10-K for year 10-F-3 --Supplemental Agreement No. 2
ended 12/31/91 to Agreement for Sharing Owner-
ship of Big Stone Plant
(dated as of March 1, 1985).
10-F-4 10-K for year 10-F-4 --Supplemental Agreement No. 3
ended 12/31/91 to Agreement for Sharing Owner-
ship of Big Stone Plant
(dated as of March 31, 1986).
10-F-5 10-K for year 10-F-5 --Amendment I to Letter of
ended 12/31/92 Intent dated May 8, 1984, for
purchase of share of Big Stone
Plant.
10-G 2-50382 5-F --Big Stone Plant Coal Agreement
by and between the Company,
Montana-Dakota Utilities Co.,
Northwestern Public Service
Company, and Knife River Coal
Mining Company (dated as of
January 1, 1972).
10-G-1 10-Q for quarter 19-A --Amendment, dated as of
ended 6/30/92 June 25, 1992, to Big Stone
Plant Coal Agreement (dated
as of January 1, 1972).
10-G-2 10-Q for quarter 19-A --Big Stone Coal Transportation
ended 3/31/89 Agreement by and between the
Company, Northwestern Public
Service Company, Montana-
Dakota Utilities Co. and
Burlington Northern Railroad
Company (dated as of
October 5, 1983).
10-G-3 10-Q for quarter 19-A --Amendment No. 1, dated as of
ended 6/30/90 May 30, 1990, to Big Stone Coal
Transportation Agreement (dated
as of October 5, 1983).
10-G-4 10-K for year 10-G-3 --Amendment No. 2, dated as of
ended 12/31/91 February 4, 1991, to Big Stone
Coal Transportation Agreement
(dated as of October 5, 1983).
10-G-5 10-Q for quarter 19-D --Big Stone Plant Tire Derived
ended 6/30/93 Fuel Agreement by and between
the Company and BFI Tire
Recyclers of Minnesota (dated
as of November 2, 1992).
10-G-6 10-Q for quarter 19-E --Big Stone Plant Tire Derived
ended 6/30/93 Fuel Agreement by and between
the Company and National Tire
Services (dated as of November
2, 1992).
10-H 2-61043 5-H --Agreement for Sharing Owner-
ship of Coyote Station
Generating Unit No. 1 by and
between the Company, Minnkota
Power Cooperative, Inc.,
Montana-Dakota Utilities Co.,
Northwestern Public Service
Company, and Minnesota Power
& Light Company (dated as of
July 1, 1977).
10-H-1 10-K for year 10-H-1 --Supplemental Agreement No.
ended 12/31/89 One dated as of November 30,
1978, to Agreement for Sharing
Ownership of Coyote Generating
Unit No. 1.
10-H-2 10-K for year 10-H-2 --Supplemental Agreement No.
ended 12/31/89 Two dated as of March 1, 1981,
to Agreement for Sharing Owner-
ship of Coyote Generating Unit
No. 1 and Amendment No. 2
dated March 1, 1981, to Coyote
Plant Coal Agreement.
10-H-3 10-K for year 10-H-3 --Amendment dated as of
ended 12/31/89 July 29, 1983, to Agreement
for Sharing Ownership of
Coyote Generating Unit No. 1.
10-H-4 10-K for year 10-H-4 --Agreement dated as of September
ended 12/31/92 5, 1985, containing Amendment
No. 3 to Agreement for Sharing
Ownership of Coyote Generating
Unit No. 1, dated as of July 1,
1977, and Amendment No. 5 to
Coyote Plant Coal Agreement,
dated as of January 1, 1978.
10-I 2-63744 5-I --Coyote Plant Coal Agreement
by and between the Company,
Minnkota Power Cooperative,
Inc., Montana-Dakota
Utilities Co., Northwestern
Public Service Company,
Minnesota Power & Light
Company, and Knife River
Coal Mining Company (dated
as of January 1, 1978).
10-I-1 10-K for year 10-I-1 --Addendum, dated as of March
ended 12/31/92 10, 1980, to Coyote Plant
Coal Agreement.
10-I-2 10-K for year 10-I-2 --Amendment (No. 3), dated as
ended 12/31/92 of May 28, 1980, to Coyote
Plant Coal Agreement.
10-I-3 10-K for year 10-I-3 --Fourth Amendment, dated as
ended 12/31/92 of August 19, 1985, to
Coyote Plant Coal Agreement.
10-I-4 10-Q for quarter 19-A --Sixth Amendment, dated as of
ended 6/30/93 February 17, 1993, to Coyote
Plant Coal Agreement.
10-J-1 10-K for year 10-J-1 --Mid-Continent Area Power Pool
ended 12/31/92 Agreement dated March 31,
1972 (amended through May 1,
1985).
10-J-2 2-66914 5-J-1 --Memorandum of Understanding
between Mid-Continent Area
Power Pool Parties (dated
as of December 1979).
10-K 10-K for year 10-K --Diversity Exchange Agreement
ended 12/31/91 Agreement by and between the
Company and Northern States
Power Company, (dated as of
May 21, 1985) and amendment
thereto (dated as of August
12, 1985).
10-K-1 10-K for year 10-K-2 --Firm Power Service Agreements
ended 12/31/91 by and between Company and
Manitoba Electric Hydro Board
(dated as of January 27, 1992).
10-K-2 10-K for year 10-K-2 --Firm Power Service Agreement
ended 12/31/92 by and between Company and
Manitoba Electric Hydro Board
(dated as of December 29,1992).
10-K-3 --Firm Power Service Agreements
by and between Company and
Manitoba Electric Hydro Board
(dated as of February 8, 1994).
10-K-4 10-Q for quarter 19-B --Purchased Power and
ended 6/30/92 Interconnection Agreement
between the Company and
Potlatch Corporation dated
as of June 3, 1992.
10-K-5 10-K for year 10-K-4 --Capacity and Energy Agreement
ended 12/31/92 by and between the Company
and Minnkota Power Cooperative,
Inc. dated as of May 4, 1992.
10-K-6 10-K for year 10-K-5 --Interchange Agreement by and
ended 12/31/92 between the Company and
Wisconsin Power and Light
Company dated as of February
21, 1992.
10-K-7 10-K for year 10-K-6 --Interchange Agreement by and
ended 12/31/92 between the Company and
Wisconsin Electric Power Co.
dated as of June 26, 1992.
10-K-8 10-K for year 10-K-7 --Firm Power Service Agreement
ended 12/31/92 by and between the Company and
Lincoln Electric System dated
as of September 11, 1992.
10-K-9 10-Q for quarter 19-B --Interchange Agreement by and
ended 6/30/93 between the Company and
Wisconsin Public Service
Corporation dated as of January
20, 1993.
10-L 10-K for year 10-L --Integrated Transmission
ended 12/31/91 Agreement by and between the
Company, Missouri Basin
Municipal Power Agency and
Western Minnesota Municipal
Power Agency (dated as of
March 31, 1986).
10-L-1 10-K for Year 10-L-1 --Amendment No. 1, dated as
ended 12/31/88 of December 28, 1988, to
Integrated Transmission
Agreement (dated as of
March 31, 1986).
10-M-1 10-K for year 10-M-1 --Hoot Lake Plant Coal
ended 12/31/89 Agreement dated as of
October 1, 1980, by and
between the Company and
Knife River Coal Mining
Company.
10-M-2 10-K for year 10-M-2 --First Amendment dated as of
ended 12/31/89 August 14, 1985, to Hoot
Lake Plant Coal Agreement.
10-M-3 10-K for year 10-M-3 --Hoot Lake Coal Transporta-
ended 12/31/89 tion Agreement dated as of
September 2, 1988 by and
between the Company and
Burlington Northern Rail-
road Company.
10-M-4 10-K for year 10-M-4 --Supplement One dated as of
ended 12/31/89 December 16, 1988, to Hoot
Lake Coal Transportation
Agreement.
10-M-5 10-K for year 10-M-5 --Supplement Two dated as of
ended 12/31/89 April 5, 1989, to Hoot Lake
Coal Transportation
Agreement.
10-M-6 10-K for year 10-M-6 --Supplement Three dated as
ended 12/31/89 of December 18, 1989, to
Hoot Lake Coal Transporta-
tion Agreement.
10-M-7 10-K for year 10-M-7 --Supplement Four dated as of
ended 12/31/91 May 10, 1991, to Hoot Lake
Coal Transportation Agreement.
10-M-8 10-K for year 10-M-8 --Supplement Five dated as of
ended 12/31/92 December 11, 1992 to Hoot Lake
Coal Transportation Agreement.
10-M-9 10-K for year 10-M-9 --Supplement Six dated as of
ended 12/31/92 January 11, 1993 to Hoot Lake
Coal Transportation Agreement.
10-M-10 --Supplement Seven dated as of
November 22, 1993 to Hoot Lake
Coal Transportation Agreement.
10-M-11 10-K for year 10-M-10 --Hoot Lake Coal Transportation
ended 12/31/92 Agreement dated January 15,
1993 by and between the
Company and Northern Coal
Transportation Co.
10-M-12 10-Q for quarter 19-C --First Amendment dated as of
ended 6/30/93 January 20, 1993 to Hoot Lake
Coal Transportation Agreement
dated January 15, 1993.
10-N-1 10-K for year 10-N --Deferred Compensation Plan
ended 12/31/91 for Directors, dated
April 9, 1984.*
10-N-2 10-K for year 10-O --Executive Survivor and Sup-
ended 12/31/92 plemental Retirement Plan,
as amended.*
10-N-3 10-K for year 10-P --Form of Severance Agreement.*
ended 12/31/92
10-N-4 --Nonqualified Pension Plan*
10-N-5 --Nonqualified Profit Sharing
Plan.*
10-N-6 --Nonqualified Retirement
Savings Plan.*
10-O --Dealer Agreement by and between
DMS and Philips Medical Systems
North America Company dated
January 18, 1994.
13-A --Portions of 1993 Annual
Report to Shareholders
incorporated by reference
in this Form 10-K.
21-A --Subsidiaries of the Registrant
23-A --Independent Auditors'
Consent.
24-A --Powers of Attorney.
- ------------
* Management contract or compensatory plan or arrangement required to be filed
pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.