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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, 1996
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
PREFERRED SHARE PURCHASE RIGHTS
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. (X)
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.
$365,961,842 as of February 28, 1997
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of the latest practicable date:
11,417,647 Common Shares ($5 par value) as of February 28, 1997
Documents Incorporated by Reference:
1996 Annual Report to Shareholders - Portions incorporated by reference into
Parts I and II
Proxy Statement dated March 14, 1997 - 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
incorporated in 1907 under the laws of the State of Minnesota. The Company's
principal executive office is located at 215 South Cascade Street, Box 496,
Fergus Falls, Minnesota 56538-0496; 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, Manufacturing and Other Business Operations. Health Services
Operations consists of certain businesses acquired beginning in 1993, that
sell, service, lease and operate diagnostic medical imaging equipment and
associated supplies and accessories. Manufacturing Operations includes
businesses acquired beginning in 1990 in such areas as metal parts stamping
and fabrication, agricultural equipment, and plastic pipe extrusion. Other
Business Operations include businesses involved in such areas as electrical
and telephone construction contracting, radio broadcasting, waste
incinerating, and telephone/cable TV utility.
The Company continues to investigate acquisitions of additional
non-electric businesses and expects continued growth in this area. In
February 1996, the Company's subsidiary, Mid-States Development, Inc.
("Mid-States"), acquired a Montana-based supplier of X-ray supplies and
accessories. In April 1996, Mid-States acquired a mobile medical diagnostic
services company located in Bemidji, Minnesota. In 1996, Mid-States also
acquired four radio stations in the Fargo, North Dakota/Moorhead, Minnesota,
market. The Company's telecommunications subsidiary, North Central
Utilities, Inc. ("NCU"), acquired two small cable TV systems in 1996 that
serve the communities of Milbank, South Dakota, and Carlos, Minnesota. The
total acquisition price for all these businesses was $11,060,000.
On January 2, 1997, NCU acquired The Peoples Telephone Co. of Bigfork
("Peoples") to be accounted for under the pooling-of-interests method.
Peoples, with 1,903 access lines serving five communities in Northern
Minnesota, had 1996 revenues of $1.6 million.
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 25 through 32 of the
Company's 1996 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 four segments: Electric, Health Services, Manufacturing,
and Other Business Operations. Financial information about the Company's
industry segments is incorporated by reference to note 2 of "Notes to
consolidated financial statements" on page 41 of the Company's 1996 Annual
Report to Shareholders, filed as an Exhibit hereto.
(c) Narrative Description of Business
---------------------------------
ELECTRIC OPERATIONS
-------------------
General
- -------
The Company derived 55% of its consolidated operating revenues from the
electric segment during 1996; 62% during 1995; and 69% during 1994. During
1996 the Company derived approximately 53.0% of its electric revenues from
Minnesota, 39.3% from North Dakota, and 7.7% 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, 35.5% of 1996 electric revenue was derived from
commercial customers, 33.5% from residential customers, 18.8% from industrial
customers, and 12.2% from other sources, including municipalities, farms and
power pools.
No customer accounted for more than 10% of electric revenues in 1996.
Power pool sales to other utilities, which accounted for 15.3% of total 1996
kwh sales, decreased from 25.3% in 1995. Activity in short-term energy sales
is subject to change based on a number of factors and the Company is unable to
predict the 1997 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 121,277, the Company has experienced an increase in customers. By year end
1996 total customers had increased to 124,782. During 1996, the Company
experienced a net increase of 711 customers, with the majority of growth in
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.
In 1996 the Federal Energy Regulatory Commission ("FERC") issued two
closely related final rules and a Notice of Proposed Rulemaking ("NOPR").
Order No. 888 opened wholesale power sales to competition by requiring public
utilities who own, control, or operate transmission lines, to file
nondiscriminatory proforma open access tariffs that offer others the same
transmission service they provide themselves. Order 889 requires utilities to
obtain information about their transmission system for their own wholesale
power transactions, such as capacity availability, by the same means as their
competitors would--via an Open Access Same-time Information System ("OASIS"),
as well as separate the wholesale marketing and transmission operation
functions. The NOPR proposes that each public utility will replace the Open
Access rule proforma tariff with a capacity reservation tariff by December 31,
1997. As of year-end 1996, the company had taken the necessary steps to
comply with these orders.
The Company is taking a number of steps to position itself for success
in a competitive marketplace. It has initiated the process of functionally
unbundling its generation, transmission, distribution and energy services
operations by setting up distinct separate business units in each of these
areas. The Company is developing the necessary accounting systems to capture
costs and determine the profitability of each of these units and to identify
areas for improvement and opportunities for increased profitability. The
Company is establishing an energy services business unit to promote the energy
related products and services that have always been offered to its customers
and to develop new products and services to be offered to current and
potential customers in order to distinguish itself from the competition.
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.
Capability and Demand
- ---------------------
At December 31, 1996, the Company had base load net plant capability
totaling 552,134 kw, consisting of 241,256 kw from the Big Stone Plant (the
Company's 53.9% share), 156,203 kw from the Hoot Lake Plant, 149,450 kw from
the Coyote Plant (the Company's 35% share), and under contract 5,225 kw from
the Potlatch Co-generation Plant near Bemidji, Minnesota. In addition to its
base load capability, the Company has combustion turbine and small diesel
units, used chiefly for peaking and standby purposes, with a total capability
of 91,123 kw, and 4,353 kw of hydroelectric capability. During 1996, the
Company generated about 61% 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 exchange agreement with another utility for
the annual exchange of 75,000 kw of seasonal diversity capacity which runs
through 2004. In addition, for the 1996-1997 winter season, the Company has
50,000 kw capacity available for purchase from other utilities. The Company
also has agreements to purchase 60,000 kw of capacity for the summers of 1997-
1999 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").
On November 1, 1996, the MAPP Agreement expired and was replaced by the MAPP
Restated Agreement which resulted in a new organization. A Regional
Transmission Group ("RTG") and power and energy market functions were added.
RTGs, as proposed by the FERC, coordinate planning of transmission grids on
regional levels. Through its Restated Agreement, MAPP opened its membership to
organizations outside the Upper Midwest boundaries first established in 1972.
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 engage in power transactions with
each other.
The Company traditionally experiences its peak system demand during the
winter season. For the calendar year 1996, the Company established a new
system peak demand of 614,961 kw on February 1, 1996. The highest previous
sixty-minute peak demand was 594,350 kw on December 11, 1995. Taking into
account additional capacity available to it in February 1996 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 723,875 kw. In 1997 the Company expects moderate growth
in peak demand as compared to 1996. 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,
is expected to meet 1997 system demand, including industry reserve
requirements.
Fuel Supply
- -----------
Coal is the principal fuel burned by the Company at its Big Stone,
Coyote, and Hoot Lake generating plants. Hoot Lake has burned primarily
western subbituminous coal since 1988, and Big Stone switched from North Dakota
lignite to western subbituminous coal in August of 1995. The following table
shows for 1996 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 . . . . . . . . . . . . . 1,630,601 61.9%
Subbituminous Coal . . . . . . . . . . 981,841 37.3
Hydro . . . . . . . . . . . . . . . . . 21,890 .8
Oil . . . . . . . . . . . . . . . . . . 1,073 -
--------- -----
Total . . . . . . . . . . . . . . . . . 2,635,405 100.0%
========= =====
The Company has a 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 comes from the Absaloka Mine near Hardin,
Montana. The Company replaced the Big Stone Plant's coal stockpile in 1995
with subbituminous coal from Kennecott Energy's Spring Creek Mine. The Company
has purchase agreements for fixed quantities of subbituminous coal with
Kennecott Energy 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.
Knife River Coal Mining Company is an affiliate of Montana-Dakota Utilities
Co., which is a co-owner of the Big Stone and Coyote Plants.
In September 1996 three of the four co-owners of the Coyote generating
plant filed a Demand and Notice of Arbitration complaint against Knife River
Coal Mining Company and MDU Resources Group, Inc. The three co-owners contend
that the 14-year-old pricing mechanism outlined in the original coal supply
contract has been abandoned by all parties over the past 7 years and no longer
results in fair, equitable, and competitive prices for the lignite coal used to
generate electricity at the plant.
It is the Company's practice to maintain minimum 30-day inventories (at
full output) of coal at Big Stone, a 20-day inventory at Coyote Plant, and a
10-day inventory at Hoot Lake Plant.
In November 1996, Big Stone Plant put new aluminum coal cars, leased by
the three plant owners, into service transporting coal to the plant. The steel
coal cars owned by the plant's joint owners were sold in September 1996. The
Company has a coal transportation agreement with Burlington Northern Railroad
for transportation services to the Big Stone Plant. This contract began in
1995 and runs through 1999. The new coal cars and new coal and freight
agreements result in lower delivered coal prices at the Big Stone Plant being
returned to the Company's retail customers through the Cost of Energy
Adjustment clause.
The Company 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. That
agreement was renewed in January 1996 for an additional three years.
Coyote Plant is a mine-mouth plant located in western North Dakota.
There are no coal transportation costs, giving Coyote Plant the lowest
delivered fuel costs on a per tonnage basis as compared to other Company units.
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 changes in fuel costs result in
adjustments to retail rates through the provisions in the Company's rate
schedules.
The average cost of coal consumed (including handling charges to the
plant sites) per million BTU for each of the three years 1996, 1995, and 1994,
was $.944, $.969, and $1.003, respectively.
The Company is permitted by the State of South Dakota to burn some
alternative fuels, including tire and refuse derived fuel, at its Big Stone
Plant. The quantity of alternative fuel burned during 1996, 3.0% of total fuel
burned at Big Stone Plant, and expected to be burned in 1997, is insignificant
when compared to the total annual coal consumption at Big Stone Plant.
General Regulation
- ------------------
The Company is subject to electric rate regulation as follows:
Year Ended
December 31, 1996
---------------------
% of
Electric % of kwh
Rates Regulation Revenues Sales
----- ---------- -------- --------
MN retail sales MN Public Utilities
Commission 48.6% 45.2%
ND retail sales ND Public Service
Commission 38.3 32.7
SD retail sales SD Public Utilities
Commission 7.6 6.5
Transmission & sales FERC
for resale 5.5 15.6
----- -----
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, 1992:
Increase (Decrease)
Granted
-------------------
Commission Date Amount %
- ---------- ---- ---------- ------
(Thousands)
Minnesota Last Proceeding was July 1, 1987
North Dakota (1)September 9, 1992 ($1,000) (1.5%)
(2)September 22, 1993 ($ 449) (0.6%)
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 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.
(2) An agreement for incentive regulation reached between the Company and the
North Dakota Commission provided 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.
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 $2,200,000 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. North Dakota law allows a forward test year. 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.
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, depreciation rates, 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
a 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. In 1995 the MPUC approved an automatic recovery
mechanism which allows the Company to begin collecting from customers any
conservation-related expenditures not included in base rates.
The MPUC requires the submission of a 15-year advance integrated resource
plan by jurisdictional utilities. The most recent plan was submitted to the
MPUC in 1996. The Company is presently awaiting a decision on that 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. The environmental
externality law requires the MPUC, to the extent practicable, 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 first and coal and
nuclear ranked fifth, 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 Company is required to submit a ten-year plan to the North Dakota
Commission annually.
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 state utility commissions in Minnesota and North Dakota are currently
investigating the impact of electric utility industry restructuring and the
prospects for reregulation and retail competition in their respective
jurisdictions. To date, the MPUC and the NDPSC have issued no new policies or
rulemakings regarding this issue. The South Dakota PUC has not taken any
action with regards to industry restructuring or retail competition.
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, 1996, approximately $3,059,000 for environmental control facilities
(excluding allowance for funds used during construction). Included in the
1997-2001 construction budget are approximately $3,079,000 for environmental
improvements for existing and new facilities, including $504,000 for 1997.
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 oxide ("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 phase
in 1995 and the second phase 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. The Company has a new subbituminous coal contract for Big Stone Plant
which runs through December 1999. The subbituminous coal replaced lignite,
which had been used since inception of plant operation in 1975 as the primary
fuel. The Company intends that the Big Stone Plant will maintain current
levels of operation and meet phase two requirements by burning low sulfur
subbituminous coal. The cost of subbituminous coal in 2000 and beyond may be
higher than the 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 NOx emissions
regulations that were issued by the EPA in 1995 apply to phase one boilers of
the same design as those used at the Company's Hoot Lake Plant units 2 and 3.
The Act allowed EPA to either retain the standard as it currently applies to
phase one boilers or adopt more stringent standards for such phase two boilers
by January 1, 1997. More stringent standards were adopted on December 19,
1996. The Company had the option to either comply with the phase one
standards beginning on January 1, 1997, under EPA's early opt-in provision, or
comply with any revised standard for phase two units. The Company elected the
early opt-in provision for Hoot Lake Plant unit 2. The unit is governed by
the phase one standard until January 1, 2008. The Company has not elected the
early opt-in provision for Hoot Lake Plant unit 3. The Company currently
anticipates that the cost of complying with the limitations applicable to Hoot
Lake Plant unit 3 will not be material.
On December 19, 1996, the EPA also adopted NOx emissions regulations
that would be applicable to cyclone-fired boilers such as those used at Big
Stone and Coyote. The regulations require that the emission standard be met
by cyclone boilers beginning on January 1, 2000. The Utility Air Regulatory
Group ("UARG") has filed a Petition for Review in the Court of Appeals for the
District of Columbia. As a member of UARG, the Company is participating in
the Petition. The Company is currently evaluating the Big Stone and Coyote
NOx emissions with respect to the December 19, 1996 rules. Existing emissions
monitoring data indicates that Coyote meets the emission requirements. At Big
Stone, emissions are currently above the required level. During 1997, the
Company will be conducting tests at Big Stone to determine if emissions can be
reduced through modifications to existing equipment. Future modifications may
be required at an undetermined cost, since compliance costs will depend on the
regulations that are ultimately adopted and the cost of available
technologies.
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, 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 waters 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 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
3,493 kw at December 31, 1996).
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 release or
threatened release 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 ("EMF"): In 1996 the
National Research Council of the National Academy of Sciences, after
evaluating more than 500 studies on the effects of EMF, found insufficient
evidence to consider electric and magnetic fields a threat to human health.
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 continues to fund
studies. The ultimate impact, if any, of this issue on the Company and the
utility industry is impossible to predict.
Capital Expenditures
- --------------------
The Company is continually expanding, replacing and improving its
electric utility facilities. During 1996 the Company invested approximately
$36,221,000 (including allowance for funds used during construction) for
additions to its electric utility properties. During the five years ended
December 31, 1996, the Company had gross electric property additions,
including construction work in progress, of approximately $135,666,000 and
gross retirements of approximately $36,859,000.
The Company estimates that during the five years 1997 through 2001 it
will invest for electric utility construction approximately $127,000,000
(including allowance for funds used during construction). The Company
continuously reviews options for increasing its generating capacity, but at
this time has no firm plans for additional base load generating plant
construction. The majority of electric utility expenditures for the five-year
period 1997 through 2001 will be for work related to the Company's
transmission and distribution system.
Franchises
- ----------
At December 31, 1996, 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.
HEALTH SERVICES OPERATIONS
--------------------------
General
- -------
Health Services Operations consists of businesses acquired beginning in
1993 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. Two
mobile diagnostic medical services companies were acquired in 1996.. The
Company derived 17% of its consolidated operating revenues from this segment
in 1996, 16% in 1995, and 16% in 1994.
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. DMS subsidiaries are DMS
Leasing, Inc. and Radiographic Supply, Inc. 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 service companies 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.
DMS Imaging, Inc., a subsidiary of DMS located in Fargo, ND and Bemidji
MN, provides mobile diagnostic medical services, including use of
diagnostic nuclear medicine, diagnostic ultrasound, diagnostic
mammography, computerized axial tomography, and magnetic resonance
imaging, and is a distributor of x-ray supplies and accessories to
health care facilities throughout the Midwest and Pacific Northwest.
Northern Medical Imaging, Inc., acquired in April 1996 and Imaging Plus,
Inc. were combined in 1996 to form DMS Imaging, Inc.
Combined, the Health Service subsidiaries cover the three basics of the
medical imaging industry: (1) operating technologists who do the imaging of
patients of hospitals and clinics; (2) the equipment function that sells,
owns, rents, refurbishes and maintains the imaging machines; and (3) central
office specialists who provide scheduling, billing and administrative support.
Competition
- -----------
The market for selling, servicing and operating diagnostic imaging
services and imaging systems is highly competitive. In addition to direct
competition from other contract providers, the Company competes with free-
standing imaging centers and health care providers that have their own
diagnostic imaging systems and with equipment manufacturers that sell imaging
equipment to health care providers for full-time installation. Some of the
Company's direct competitors which provide contract MRI services have access
to greater financial resources than the Company. In addition, some of the
Company's customers are capable of providing the same services to their
patients directly, subject only to their decision to acquire a high-cost
diagnostic imaging system, assume the financial risk, and employ the necessary
technologies. The Company competes against other contract providers on the
basis of quality of services, quality and magnetic field strength of imaging
systems, price, availability and reliability.
Capital Expenditures
- --------------------
During 1996 capital expenditures of approximately $16,000,000 were made
in Health Services. These capital expenditures were primarily for diagnostic
imaging equipment purchased to service mobile imaging routes. Total capital
expenditures during the five-year period 1997-2001 are estimated to be
$18,000,000.
MANUFACTURING OPERATIONS
------------------------
General
- -------
Manufacturing Operations consists of businesses involved in the
production of agricultural equipment, plastic pipe extrusion, and metal parts
stamping and fabrication. Initial acquisitions of businesses in this segment
were made in 1990. No additional companies were acquired in 1996. The Company
derived 16% of its consolidated operating revenues from this segment in 1996,
12% in 1995, and 5% in 1994.
The following is a brief description of each of these businesses:
Precision Machine of North Dakota, Inc., located in West Fargo, ND, uses
computer numerically controlled lathes and milling machines to produce
parts for manufacturers.
Dakota Machine, Inc., located in West Fargo, ND, is primarily engaged in
metal fabrication of large equipment that handles or processes sugar
beets. Dakota Engineering, Inc., a subsidiary of Dakota Machine, Inc.,
was formed in 1995 and is engaged in design engineering and construction
management, primarily in the sugar industry.
Glendale Machining, Inc., located in Pelican Rapids, MN, uses computer
numerically controlled lathes and milling machines to produce parts for
manufacturers.
BTD Manufacturing, Inc. ("BTD"), located in Detroit Lakes, MN, is a
metal stamping and tool and die manufacturer. BTD stamps, machines, and
assembles metal parts according to manufacturers' specifications.
Northern Pipe Products, Inc., located in Fargo, ND, manufactures poly-
vinyl-chloride (PVC) pipe for municipal, rural water, irrigation and
other uses in a sixteen-state area.
Each of the subsidiaries described above under Health Services and
Manufacturing Operations are owned by Mid-States Development, Inc., which is a
wholly owned subsidiary of Minnesota Dakota Generating Company ("MDG"). MDG
is a wholly owned subsidiary of the Company.
Competition
- -----------
The markets in which the Company's manufacturing entities compete are
characterized by intense competition. The various markets the companies
compete in have many established manufacturers with broader product lines,
greater distribution capabilities, greater capital resources and larger
marketing, research and development staffs and facilities than the Company.
The Company believes the principal competitive factors in its manufacturing
segment are product performance, quality, price, ease of use, technical
innovation, cost effectiveness, customer service and breadth of product line.
The Company intends to continue to compete on the basis of its high
performance products, innovative technologies, cost effective manufacturing
techniques, close customer relations and support and its strategy to increase
offerings of products.
Capital Expenditures
- --------------------
During 1996 capital expenditures of approximately $4,600,000 were made
in Manufacturing. Total capital expenditures for Manufacturing during the
five-year period 1997-2001 are estimated to be approximately $12,000,000.
OTHER BUSINESS OPERATIONS
-------------------------
General
- -------
The Company's Other Business Operations consists of businesses that are
diversified in such areas as electrical and telephone construction
contracting, radio broadcasting, waste incinerating, and telephone/cable TV
utility. In 1996 Mid-States Development, Inc. acquired four radio stations in
the Fargo, North Dakota/Moorhead, Minnesota market area. The Company's
telecommunications subsidiary, North Central Utilities, Inc. ("NCU"), acquired
two small cable TV systems. On January 2, 1997, NCU acquired The Peoples
Telephone Co. of Bigfork in a pooling-of-interests transaction. The Company
derived 12% of its consolidated operating revenues from these diversified
businesses during 1996, 10% in 1995, and 10% during 1994.
The following is a brief description of each of these businesses:
Moorhead Electric, Inc., located in Moorhead, MN, provides commercial
and industrial wiring of large buildings, constructs and maintains
telecommunications and power distribution systems, and installs computer
network cable.
Aerial Contractors, Inc., located in West Fargo, ND, constructs and
maintains overhead and underground electric, telecommunications, and
cable television lines.
KFGO, Inc., located in Fargo, ND, operates an AM and FM commercial radio
station.
MSB, Inc., located in Fargo, ND, operates one AM and three FM commercial
radio stations along with a video production facility.
Western Minnesota Broadcasting Company, located in Morris, MN, operates
an AM and FM commercial radio station.
Quadrant Co. ("Quadrant") operates a municipal waste burning facility
located in Perham, MN. Quadrant continues to provide primary service to
one of its two steam customers under an agreement which can be
terminated by either party upon one year's prior written notice, and is
currently providing backup service to its other steam customer under an
agreement that commenced on June 1, 1996 and terminates on May 31, 1998,
subject to earlier termination by either party upon 90 days' written
notice. Quadrant also continues to burn municipal solid waste for three
Minnesota counties under a contract extension which expires April 1,
1997. Two Minnesota counties, representing about 40% of Quadrant's
processing capacity, did not renew or extend their contracts for waste
incineration which expired in September 1996. Quadrant is in the
process of negotiating new waste incineration agreements with the
remaining counties and is pursuing additional incineration contracts.
The Company has invested approximately $3.2 million in plant and
equipment in Quadrant. Quadrant represented approximately $2.5 million
in sales for 1996 and an insignificant impact on consolidated operating
income for the Company. The outcome of current incineration contract
negotiations could result in an impairment issue under SFAS 121. The
Company is working to obtain prospects for new incineration contracts.
The price ranges being considered for the contracts result in a wide
variance in estimates of future cash flows, making it difficult to
accurately calculate an impairment value at this time. 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.
Quadrant is a wholly owned subsidiary of 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.
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. In late 1996, the U.S. Court of
Appeals for the District of Columbia Circuit vacated air emission regulations
recently adopted by the EPA. EPA has petitioned for a rehearing of the case.
Quadrant continues to operate under an expired air emission permit with the
permission of the Minnesota Pollution Control Agency and submitted 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.
Competition
- -----------
Each of the businesses in Other Business Operations is subject to
competition, as well as the effects of general economic conditions, in their
respective industries.
Capital Expenditures
- --------------------
During 1996 capital expenditures of approximately $5,000,000 were made in
Other Business Operations. Capital expenditures during the five-year period
1997-2001 are estimated to be approximately $12,000,000 for Other Business
Operations.
FINANCING
---------
The Company estimates that funds internally generated, combined with
funds on hand will be sufficient to meet all sinking fund payments for First
Mortgage Bonds in the next five years and to provide for the majority of its
estimated 1997-2001 consolidated capital project expenditures. Additional
short-term or long-term financing will be required in the period 1997-2001 in
connection with a portion of the Company's estimated capital project
expenditures, maturity of First Mortgage Bonds ($18,800,000 in 1997) and a
Long-Term Lease Obligation ($2,200,000 in 1998), in the event the Company
decides to refund or retire early any of its presently outstanding debt or
Cumulative Preferred Shares, 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, tax law
changes, and rate regulation.
As of December 31, 1996, the Company had unutilized net fundable
property available for the issuance of more than $36,000,000 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 have been responsible for obtaining
their own financing after the Company's initial equity investment and have
developed financing arrangements with various banks. Historically, the
Company has not made or guaranteed loans to its subsidiaries, loaned any
subsidiary money or cosigned on any of their borrowing.
The Company has access to short-term borrowing resources. As of December
31, 1996, the Company and subsidiaries had unused credit lines totaling
$21,700,000. The Company had $25,600,000 in short-term borrowings as of
December 31, 1996. The subsidiary companies had $7,000,000 of credit lines in
use at December 31, 1996, a portion classified as current maturities and a
portion classified as long-term debt depending on the terms and nature of use.
EMPLOYEES
---------
The Company and its subsidiaries had approximately 1,629 full-time
employees at December 31, 1996. A total of 505 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 that was renewed in 1996 and expires November 1,
1999. The Company has never experienced any strike, work stoppage, or strike
vote, and regards its present relations with employees as very good.
Forward Looking Information - Safe Harbor Statement
Under the Private Securities Litigation Reform Act of 1995
- ----------------------------------------------------------
In connection with the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995 (the "Act"), the Company has filed cautionary
statements identifying important factors that could cause the Company's actual
results to differ materially from those discussed in forward-looking
statements made by or on behalf of the Company. When used in this Form 10-K
and in future filings by the Company with the Securities and Exchange
Commission, in the Company's press releases and in oral statements, words such
as "may", "will", "expect", "anticipate", "continue", "estimate", "project",
"believes" or similar expressions are intended to identify forward-looking
statements within the meaning of the Act. Factors that might cause such
differences include, but are not limited to, the factors discussed under
"Factors affecting future earnings" on pages 30 through 32 of the Company's
1996 Annual Report to Shareholders, filed as an exhibit hereto. These factors
are in addition to any other cautionary statements, written or oral, which may
be made or referred to in connection with any such forward-looking statement
or contained in any subsequent filings by the Company with the Securities and
Exchange Commission.
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, 1996, 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; 573 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, 1996.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1997)
----------------------------------------------------------
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 (57) 4/8/91 Present: Chairman, President and Chief
Executive Officer
Andrew E. Anderson (57) 4/8/96 Present: Vice President, Finance and
Treasurer
4/10/95 Vice President, Finance
Prior to
4/10/95 Controller
Marlowe E. Johnson (52) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Prior to
4/12/93 Division Manager, Jamestown
Douglas L. Kjellerup (55) 4/12/93 Present: Vice President, Marketing and
Development
Prior to
4/12/93 Vice President, Planning and Development
LeRoy S. Larson (51) 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 (58) 4/8/96 Present: Senior Vice President,
Corporate Services
Prior to
4/8/96 Vice President, Corporate Services
Jay D. Myster (58) 4/8/96 Present: Senior Vice President,
Governmental and Legal,
and Corporate Secretary
Prior to
4/8/96 Vice President, Governmental and Legal,
and Corporate Secretary
Rodney C.H. Scheel (47) 4/10/95 Present: Vice President, Electrical
Prior to
4/10/95 Director, Information Services
Ward L. Uggerud (47) 4/10/89 Present: Vice President, Operations
Jeffrey J. Legge(40) 4/10/95 Present: Controller
Prior to
4/10/95 Manager, Tax Department
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
the first sentence under "Stock listing" on Page 52, to "Selected consolidated
financial data" on Page 24 and to "Quarterly information" on Page 49, of the
Company's 1996 Annual Report to Shareholders, filed as an Exhibit hereto.
In the April 1, 1996, acquisition of Northern Medical Imaging, Inc.
("NMI"), a Company subsidiary exchanged 107,633 shares of the Company's common
stock acquired on the open market and $1,000,000 for all of the outstanding
voting common shares of NMI. The issuance of shares of common stock did not
involve a public offering and therefore was exempt from registration pursuant
to Section 4(2) of the Securities Act of 1933, as amended.
Item 6. SELECTED FINANCIAL DATA
-----------------------
The information required by this Item is incorporated by reference to
"Selected consolidated financial data" on Page 24 of the Company's 1996 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 25 through 32 of the Company's 1996 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 49 and the Company's audited financial
statements on Pages 33 through 49 of the Company's 1996 Annual Report to
Shareholders excluding "Report of Management" on Page 33, 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 14, 1997. 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 14, 1997.
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 14, 1997.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
----------------------------------------------
None.
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 22 hereof.
(3) See Exhibit Index on Pages 23 through 29 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, 1996.
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 A. E. Anderson
-------------------------------
A. E. Anderson
Vice President, Finance
and Treasurer
Dated: March 28, 1997
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 )
)
A. E. Anderson )
Vice President, Finance and Treasurer )
(principal financial officer) )
)
Jeffrey J. Legge )
Controller ) By A. E. Anderson
(principal accounting officer) ) ---------------------------
) A. E. Anderson
) Pro Se and Attorney-in-Fact
) Dated March 28, 1997
Thomas M. Brown, Director )
)
Dayle Dietz, Director )
)
Dennis R. Emmen, Director )
)
Maynard D. Helgaas, Director )
)
Arvid R. Liebe, Director )
)
Kenneth L. Nelson, Director )
)
Nathan I. Partain, Director )
)
Robert N. Spolum, 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, 1996
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,
1996:
Page in
Annual
Report to
Shareholders
------------
Financial Statements:
Independent Auditors' Report ........................................ 33
Consolidated Balance Sheets, December 31, 1996 and 1995 ........ 34 & 35
Consolidated Statements of Income for the Three Years
Ended December 31, 1996 ............................................. 36
Consolidated Statements of Retained Earnings for the
Three Years Ended December 31, 1996 ................................. 36
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1996 ............................................. 37
Consolidated Statements of Capitalization,
December 31, 1996 and 1995 .......................................... 38
Notes to Consolidated Financial Statements ....................... 39-49
Selected Consolidated Financial Data for the Five Years
Ended December 31, 1996 ............................................. 24
Quarterly Data for the Two Years Ended
December 31, 1996 ................................................... 49
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, 1996
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
4-D-10 8-A dated 1 --Rights Agreement, dated as of
1/28/97 January 28, 1997, between the
Company and Norwest Bank Minnesota,
National Association
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 Association
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 Integrated
Transmission Agreement between
Cooperative Power Association
and the Company.
10-C-1 2-55813 5-E --Contract dated July 1, 1958,
between Central Power Electric
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 superseded
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 Supplement
Seven.
10-C-5 10-K for year 10-C-5 --Amendment No. 3 dated
ended 12/31/92 June 18, 1992, to Supplement
Seven.
10-C-6 10-K for year 10-C-6 --Amendment No. 4 dated
ended 12/31/93 January 18, 1994, to Supplement
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
Northwestern Public Service
Company (dated as of
January 7, 1970).
10-F-1 10-K for year 10-F-1 --Letter of Intent for purchase
ended 12/31/89 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 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-1 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-2 10-K for year 10-G-2 --Amendment No. 1, dated as of
ended 12/31/95 December 27, 1995, to Big
Stone Coal Transportation
Agreement (dated as of
July 18, 1994).
10-G-3 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-4 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. 5, 1985,
ended 12/31/92 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
ended 12/31/92 March 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-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-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-2 10-K for year 10-K-4 --Capacity & Energy Agreement
ended 12/31/94 by and between the Company
and Minnkota Power Coop.
Inc. dated as of May 27, 1994.
10-K-3 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-4 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-5 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-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-4 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-M-5 --Second Amendment dated as of
May 21, 1996 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-N-2 --Executive Survivor and
ended 12/31/94 Supplemental 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 1996 Annual
Report to Shareholders
incorporated by reference
in this Form 10-K.
21-A --Subsidiaries of Registrant
23 --Consent of Deloitte & Touche LLP
24-A --Powers of Attorney.
27 --Financial Data Schedule.
- ------------
*Confidential information has been omitted from such Exhibit and filed
separately with the Commission pursuant to a confidential treatment request
under Rule 24b-2.
** Management contract or compensatory plan or arrangement required to be
filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.