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, 1994
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 Identification No.)
incorporation or organization)
215 S. CASCADE ST., BOX 496, FERGUS FALLS, MN 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. $369,437,525 as of March 1, 1995
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, 1995
Documents Incorporated by Reference:
1994 Annual Report to Shareholders - Portions incorporated by reference
into Part II
Proxy Statement dated March 8, 1995 - 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 1994 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 1994
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 69% of its
operating revenues from the sale of electric energy during 1994; 73% during
1993; and 85% during 1992. During 1994 the Company derived approximately
55.3% of its electric revenues from Minnesota, 37.5% from North Dakota, and
7.2% 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, 52.3% of 1994 electric revenues was
derived from commercial and industrial customers, 31.8% from residential
customers, and 15.9% from other sources, including municipalities, farms and
power pools.
The Company's two largest oil pipeline customers accounted for about
10.3% of total 1994 retail electric revenues compared to 10.4% of such
revenues in 1993. In 1994, retail kwh sales to these pipeline customers
increased by 5.1% from the previous year. Sales to a large wood products
customer accounted for 1.5% of total retail electric revenues in 1994 as
compared to 1.6% in 1993. Sales to a large barley malting plant accounted
for 1.3% of total retail electric revenues in 1994 as compared to 1.4% in
1993. Sales to a large diskette manufacturing plant accounted for about
1.1% of total retail electric revenues in 1994 as compared to 1% in 1993.
No other retail customer accounted for more than 1% of retail electric
revenues. Power pool sales to other utilities, which accounted for 26.1% of
total 1994 kwh sales, increased only slightly from 1993. Activity in
short-term energy sales is subject to change based on a number of factors
and the Company is unable to predict the 1995 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 1994 total customers had increased to 123,223. During 1994, the
Company experienced a net increase of 796 customers, with the majority of
growth in the number of residential and commercial customers.
Competition
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. The Company may also face competition as the restructuring of the
electric industry evolves. Proposals that are being considered by various
states and at the federal level, along with the National Energy Policy Act
of 1992 ("NEPA"), are expected to bring more competition into the electric
business. The NEPA reduces restrictions on operation and ownership of
independent power producers ("IPPs"). It also allows IPPs and other
wholesale suppliers and purchasers increased access to transmission lines.
The NEPA prohibits retail wheeling ordered by the Federal Energy Regulatory
Commission, but it does not address the states' authority to order retail
wheeling.
As the electric industry evolves, the Company may also have
opportunities to increase its market share. The Company's generation
capacity appears well positioned for competition due to unit heat rate
improvements and reductions in fuel and freight costs. A comparison of the
Company's electric retail rates to the rates of other investor-owned
utilities, cooperatives, and municipals in the states the Company serves
indicates that the Company's rates are competitive. In addition, the
Company would attempt more flexible pricing strategies under an open,
competitive environment.
Rate Matters
The Company is subject to electric rate regulation as follows:
Year Ended
December 31, 1994
% of
Electric % of kwh
Rates Regulation Revenues Sales
MN retail sales MN Public Utilities
Commission 46.5% 39.2%
ND retail sales ND Public Service
Commission 36.5 28.9
SD retail sales SD Public Utilities
Commission 7.1 5.5
Transmission & sales Federal Energy Regulatory
for resale Commission ("FERC") 9.9 26.4
_____ _____
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, 1990:
Increase
(Decrease) Granted
Commission Date Amount %
(Thousands)
Minnesota Last Proceeding was July 1, 1987
North Dakota (1)June 1, 1990 ($ 315) (0.5%)
(2)September 9, 1992 ($1,000) (1.5%)
(3)September 22, 1993 ($ 449) (0.6%)
South Dakota Last Proceeding was November 1, 1987
FERC Last Proceeding was July 1, 1987
__________
(1) 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 economic development
efforts in North Dakota.
(2) 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.
(3) 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 $449,000 resulting
from sharing earnings above this benchmark for 1993, was returned to
customers in 1994.
In 1994 the Company filed a petition with the Minnesota Public
Utilities Commission for approval of an annual recovery mechanism for
demand-side management related costs, under Minnesota's Conservation
Improvement Programs. See "General Regulation". An intervenor, on behalf
of the Large General Service Group, filed comments against the petition and
requested the Commission to order a general rate case to review the
Company's earnings levels. In the interest of rate stability the Company
reached an agreement, which was approved by the Commission, resulting in
costs of approximately $2,000,000 each year for three years which must be
absorbed in current rates starting in 1995.
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 South Dakota Public Utilities 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, 1994, the Company had base load net plant capability
totaling 557,825 kw, consisting of 248,775 kw from the Big Stone Plant (the
Company's 53.9% share), 154,175 kw from the Hoot Lake Plant, 149,450 kw from
the Coyote Plant (the Company's 35% share), and 5,425 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 89,202 kw, and 4,375 kw of hydroelectric
capability. During 1994, the Company generated about 74% 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 1994-1995 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 1995-1996 winter
season. The Company has agreements with Manitoba Hydro Electric Board to
purchase 110,000 kw of capacity for the summer seasons of 1994 through 1996
and 50,000 kw of year-round capacity for the May 1, 1997 through April 30,
2005 period. 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 49 members representing investor-owned utilities, rural
cooperatives, municipal utilities, and other power suppliers (including
power marketers) 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 traditionally experiences its peak system demand during
the winter season. For the calendar year 1994, the Company established a
peak demand of 580,374 kw on January 7, 1994. Taking into account additional
capacity available to it in January 1994 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 744,092 kw. The highest sixty-minute peak demand ever
experienced by the Company was 589,239 kw on January 8, 1993. In 1995 the
Company expects moderate growth in peak demand as compared to 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 1995 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 1994 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 . . . . . . . . . . . . . 2,329,831 82.3%
Subbituminous Coal . . . . . . . . . . 475,607 16.8
Hydro . . . . . . . . . . . . . . . . . 25,055 .9
Oil . . . . . . . . . . . . . . . . . . 1,533 -
_________ _____
Total . . . . . . . . . . . . . . . 2,832,026 100.0%
The Company's supply of lignite coal, all of which comes from North
Dakota, is furnished by Knife River Coal Mining Company (an affiliate of
Montana-Dakota Utilities Co., which is 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 May 1995. The Company has negotiated a new
coal supply agreement with Westmoreland Resources Inc. of Billings, Montana
for supply of subbituminous coal to Big Stone Plant from mid-1995 through
1999. The coal will come from the Absaloka mine near Hardin, Montana. The
Company has also entered into a spot coal agreement with Kennecott Energy
Company of Gillette, Wyoming for subbituminous coal from Spring Creek mine
to replace the Big Stone Plant's coal stockpile in 1995. 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
also 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 May
1995. The Company negotiated a new coal transportation agreement with
Burlington Northern Railroad for transportation services to the Big Stone
Plant. This contract begins in 1995 and runs through 1999. These new coal
and freight agreements will result in significantly lower delivered coal
prices at the Big Stone Plant.
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 1995 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. Therefore,
there are no coal transportation costs, giving Coyote Plant the lowest
delivered fuel costs as 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 1994, 1993
and 1992, was 100.3 cents, 100.7 cents and 100.5 cents, respectively. The
average cost of coal consumed (including handling charges to the plant
sites) per ton for each of the three years 1994, 1993 and 1992 was $13.62,
$13.75 and $13.33, 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 1994 (1.5% of total fuel burned at the
Big Stone Plant), and expected to be burned in 1995, is insignificant when
compared to the 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 1994 (.5%
of total fuel burned at the Big Stone Plant) and expected to be burned in
1995 is insignificant when compared to Big Stone Plant's 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 belong to 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, 1993
and 1994.
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 submitted its next
plan in 1994. The Company is currently awaiting a decision by the MPUC on
this latest plan. The Minnesota legislature has enacted a statute that
favors conservation over the addition of new resources. In addition it has
mandated the use of renewable resources where new supplies are needed,
unless the utility proves that a renewable energy facility is not in the
public interest. It has effectively prohibited the building of new nuclear
facilities. An environmental externality law requires the MPUC to quantify
the environmental costs of each type of generation, and to use such
monetized values in evaluating resource plans. The MPUC must disallow any
nonrenewable rate base additions (whether within or without the state) or
any rate recovery therefrom, and shall not approve any nonrenewable energy
facility in an integrated resource plan, unless the utility proves that a
renewable energy facility is not in the public interest. The state has
prioritized the acceptability of new generation with wind and solar ranked
one and coal and nuclear ranked five, the lowest ranking. Whether these
state policies are preempted by federal law has not been determined.
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 more than 115 kv.
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, 1994, approximately $9,400,000 for environmental control facilities
(excluding allowance for funds used during construction). Included in the
1995-1999 construction budget are approximately $3,130,000 for environmental
improvements for existing and new facilities, including $1,056,000 for 1995.
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, if plant operations are to
continue near current levels. The Company intends that the Big Stone Plant
will maintain current levels of operation and meet phase two requirements by
burning subbituminous coal which is much lower in sulfur emissions than the
current fuel, lignite. The Company has signed a new subbituminous coal
contract for Big Stone Plant which will run from mid-1995 through December
1999. The cost of burning subbituminous coal in 2000 and beyond would
probably be higher than current market price but would likely not adversely
affect the Company's power plant operations.
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. The NOx
emissions regulations that were issued by the EPA for boilers such as those
used at the Company's Hoot Lake Plant were overturned by the U. S. Circuit
Court of Appeals for the District of Columbia after a successful challenge
by electric utility representatives. The Company expects that the
regulations that are ultimately adopted will be less stringent than those
which were overturned. Subject to additional evaluation of the results of
continuous emission monitoring which began at Hoot Lake in 1994, the Company
currently anticipates that the cost of complying with the limitations
expected to be applicable to Hoot Lake will not be material. The Act
requires the 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 3,580 kw at December 31, 1994).
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, 1994, 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
businesses were acquired in 1993 by the Company's wholly-owned subsidiary
Mid-States Development, Inc. On a fully consolidated basis, the Company
derived 16% of its operating revenues from this segment in 1994 and 12% 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, radiographic 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. In 1994 DMS 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.
In January 1995 the Company acquired three small diagnostic imaging
companies which are part of Mobile Imaging, Inc. The Company continues to
investigate acquisitions of additional businesses and expects continued
growth in this area.
DIVERSIFIED OPERATIONS
General
The Company's Diversified Operations consists of businesses 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 businesses during 1994,
1993 and 1992.
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 these 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.
Western Minnesota Broadcasting Company, operates both AM and FM
commercial radio stations broadcasting from Morris, MN.
Quadrant Co. ("Quadrant") operates a municipal waste burning facility
located in Perham, MN. Pursuant to agreements which will expire in
September 1996, Quadrant receives a processing fee from five Minnesota
counties for disposal of mixed waste. Under agreements which expire in
June 1995 with two industrial customers, Quadrant sells the steam
generated from the incineration process. The Company has invested
approximately $4 million in plant and equipment in Quadrant. Quadrant
represented approximately $1.8 million in sales for 1994 and an
insignificant contribution to consolidated operating income for the
Company. Successful negotiation of the above contracts will be
necessary to provide for recovery of the amount the Company has
invested in Quadrant. See "Environmental Regulation" below.
Midwest Information Systems, Inc.("MIS"), headquartered in Parkers
Prairie, MN, owns two operating telephone companies serving over 4,000
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 business, BTD Manufacturing, Inc.(a metal parts manufacturer
located in Detroit Lakes, Minnesota) was acquired in January, 1995.
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 utility 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
In recent years, facilities such as Quadrant that burn municipal solid
waste have been subjected to increasing state and federal environmental
regulation. The Minnesota Pollution Control Agency promulgated rules
relating to ash in 1993 and air emissions in 1994. Under a 1994 Supreme
Court ruling, ash from municipal solid waste combustors must be tested for
toxic characteristics prior to disposal in landfills. The EPA recently
proposed air emission regulations which, if adopted as proposed, will be
more stringent than state regulations. Quadrant currently is operating
under an expired air emission permit with the permission of the Minnesota
Pollution Control Agency and is required to submit its application for a new
air emission permit in April of 1995. Historically, the terms of Quadrant's
contacts with customers have enabled Quadrant to pass on to its customers
much of the cost of environmental compliance. The increasing cost of
environmental compliance may adversely affect Quadrant's ability to
successfully negotiate the renewal of the contracts discussed above.
CONSTRUCTION PROGRAM & FINANCING
The Company is continually expanding, replacing and improving its
electric utility facilities. During 1994, the Company invested
approximately $26,951,000 (including allowance for funds used during
construction) for additions to its electric utility properties. During the
five years ended December 31, 1994, the Company had gross electric property
additions, including construction work in progress, of approximately
$121,826,000 and gross retirements of approximately $29,171,000. During
1994, capital expenditures of approximately $2,000,000 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 1995-1999 are estimated to be approximately
$182,000,000. Of this $14,000,000 is for Health Services Operations and
$16,000,000 for Diversified Operations. The Company estimates that during
the five years 1995 through 1999 it will invest for electric utility
construction approximately $152,000,000 (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 1995 through 1999 will be for work related to the Company's
production plant and distribution system.
The Company estimates that funds internally generated, combined with
funds on hand, will be sufficient to provide for all sinking fund payments
for First Mortgage Bonds in the next five years and to provide for most of
its 1995-1999 construction program expenditures (including allowance for
funds used during construction). Additional short or long-term financing
will be required in the period 1995-1999 in connection with the Company's
construction program, 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.
As of December 31, 1994, the Company had unutilized net fundable
property available for the issuance of more than $24,000,000 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 any subsidiary
money or cosign on any of their borrowing.
The Company has access to short-term borrowing resources. At December
31, 1994, the Company and its subsidiaries had established bank lines of
credit totaling $27,650,000 of which $4,738,000 was used.
EMPLOYEES
The Company and its subsidiaries had approximately 1,290 full-time
employees at December 31, 1994. A total of 462 employees are represented by
local unions of the International Brotherhood of Electrical Workers, of
which 430 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, 1994, the Company's transmission facilities, which are
interconnected 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
4,272 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, 1994.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1995)
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 (55) 4/8/91 Present: Chairman, President and
Chief Executive Officer
Prior to
4/8/91 President and Chief Executive Officer
Dennis R. Emmen (61) 4/13/81 Present: Senior Vice President,
Finance, Treasurer and Chief
Financial Officer
Marlowe E. Johnson (50) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Prior to
4/12/93 Division Manager, Jamestown
Douglas L. Kjellerup (53) 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 (49) 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 (56) 1/1/78 Present: Vice President,
Corporate Services
Jay D. Myster (56) 4/12/82 Present: Vice President, Governmental
and Legal, and Corporate
Secretary
Earl D. Sjoberg (62) 4/10/89 Present: Vice President, Electrical
Ward L. Uggerud (45) 4/10/89 Present: Vice President, Operations
Andrew E. Anderson (55) 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 the
inside back cover, to "Selected Consolidated Financial Data" on page 23 and
to "Quarterly Information" on page 45, of the Company's 1994 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 1994
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 1994 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 1994 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 information under "Nominees for Election as Directors" in the
Company's definitive Proxy Statement dated March 8, 1995. 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 information under "Summary Compensation Table", "Pension and
Supplemental Retirement Plans", "Severance Agreements", and "Directors'
Compensation" in the Company's definitive Proxy Statement dated March 8,
1995.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference
from the information under "Outstanding Voting Shares" and "Security
Ownership of Management" in the Company's definitive Proxy Statement dated
March 8, 1995.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference
from the information under "Nominees for Election as Directors" in the
Company's definitive Proxy Statement dated March 8, 1995.
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 21 hereof.
(3) See Exhibit Index on Pages 22 through 30 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, 1994.
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 27, 1995
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 )
Controller ) By D. R. Emmen
(principal accounting officer) ) D. R. Emmen
) Pro Se and Attorney-in-Fact
) Dated March 27, 1995
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, 1994
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,
1994:
Page in
Annual
Report to
Shareholders
Financial Statements:
Independent Auditors' Report. . . . . . . . . . . . . . . . . . 33
Consolidated Balance Sheets, December 31, 1994 and 1993 . .32 & 33
Consolidated Statements of Income for the Three Years
Ended December 31, 1994 . . . . . . . . . . . . . . . . . . . . 34
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1994 . . . . . . . . . . . . . . . . . . . . 35
Consolidated Statements of Retained Earnings for the
Three Years Ended December 31, 1994 . . . . . . . . . . . . . . 35
Consolidated Statements of Capitalization, December 31, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Notes to Consolidated Financial Statements. . . . . . . . . 37-45
Selected Consolidated Financial Data for the Five Years
Ended December 31, 1994 . . . . . . . . . . . . . . . . . . . . 23
Quarterly Data for the Two Years Ended
December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . 45
Schedules 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.
Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 1994
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 10-K for year 10-C-6 --Amendment No. 4 dated
ended 12/31/93 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 10-K for year 10-E-7 --Supplement No. Six, dated
ended 12/31/93 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
ownership 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
ownership 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 Agrmnt
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 10-A --Big Stone Plant Coal Agrmnt
ended 9/30/94 by and between the Company,
Montana-Dakota Utilities Co.,
Northwestern Public Service
Company, and Westmoreland
Resources, Inc. (dated as of
June 30, 1994).
10-G-3 10-Q for quarter 19-A --Big Stone Coal Transp.
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-4 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-5 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-6 10-Q for quarter 10-B --Big Stone Coal Transp.
ended 9/30/94 Agreement by and between the
Company, Montana-Dakota
Utilities, Northwestern Public
Service Co., and Burlington
Northern Railroad Company
(dated as of July 18, 1994).
10-G-7 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-8 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
Ownership 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 Sept.
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
ended 12/31/92 Pool 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 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 Agreement
ended 12/31/92 by and between Company and
Manitoba Electric Hydro Board
(dated as of 12/29/92).
10-K-2 10-K for year 10-K-3 --Firm Power Serv. Agreements
ended 12/31/93 by and between Company and
Manitoba Electric Hydro Board
(dated as of 02/08/94).
10-K-3 10-Q for quarter 10 --Purchased Power and
ended 6/30/94 Interconnection Agreement
between the Company and
Potlatch Corporation dated
as of June 8, 1994.
10-K-4 --Capacity & Energy Agreement
by and between the Company
and Minnkota Power Coop.
Inc. dated as of May 27, 1994.
10-K-5 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-6 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-7 10-Q for quarter 19-B --Interchange Agreement by and
ended 6/30/93 between the Company and
Wisconsin Public Service Corp
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 10-K for year 10-M-10 --Supplement Seven dated as of
ended 12/31/93 November 22, 1993 to Hoot Lake
Coal Transportation Agreement.
10-M-11 10-K for year 10-M-10 --Hoot Lake Coal Transp.
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 --Executive Survivor and Sup-
plemental Retirement Plan,
as amended.*
10-N-3 10-K for year 10-P --Form of Severance Agrmnt.*
ended 12/31/92
10-N-4 10-K for year 10-N-5 --Nonqualified Profit Sharing
ended 12/31/93 Plan.*
10-N-5 10-K for year 10-N-6 --Nonqualified Retirement
ended 12/31/93 Savings Plan.*
10-O 10-K for year 10-O --Dealer Agreement by and
ended 12/31/93 between DMS and Philips
Medical Systems North
America Company dated
January 18, 1994.
13-A --Portions of 1994 Annual
Report to Shareholders
incorporated by reference
in this Form 10-K.
21-A --Subsidiaries of Registrant
23-A --Independent Auditors'
Consent.
24-A --Powers of Attorney.
27 --Financial Data Schedule.
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* Management contract or compensatory plan or arrangement
required to be filed pursuant to Item 601(b)(10)(iii)(A) of
Regulation S-K.