OTTER TAIL POWER CO - 10-K Annual Report

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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, 1995
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. $411,315,199 as of March 1, 1996

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, 1996

Documents Incorporated by Reference:
1995 Annual Report to Shareholders-Portions incorporated by reference into
Part II Proxy Statement dated March 8, 1996-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, Manufacturing and Other Business Operations. Health
Services Operations consists of certain businesses acquired beginning in
1993, including the 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. 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
February 1996, Mid-States entered into an agreement to acquire three radio
stations in the Fargo, ND-Moorhead, MN market, subject to FCC approval. Also
in February 1996, Mid-States entered into a letter of intent to acquire a
mobile medical diagnostic services company located in Bemidji, Minnesota,
subject to the negotiation of a definitive purchase agreement and other
conditions to closing. In 1995, the total combined revenues for all these
businesses was approximately $29,000,000. If consummated, the total
acquisition price for all these businesses will be approximately $10,000,000.

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 1995 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 39 of the Company's 1995
Annual Report to Shareholders, filed as an Exhibit hereto.

(c) Narrative Description of Business

ELECTRIC OPERATIONS

General

The Company derived 62% of its consolidated operating revenues from the
sale of electric energy during 1995; 69% during 1994; and 73% during 1993.
During 1995 the Company derived approximately 55.4% of its electric revenues
from Minnesota, 37.4% 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, 52.2% of 1995 electric revenues was
derived from commercial and industrial customers, 31.9% from residential
customers, and 15.9% from other sources, including municipalities, farms and
power pools.

No customer accounted for more than 10% of electric revenues. Power
pool sales to other utilities, which accounted for 25.3% of total 1995 kwh
sales, decreased only slightly from 1994. Activity in short-term energy sales
is subject to change based on a number of factors and the Company is unable
to predict the 1996 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
1995 total customers had increased to 124,082. During 1995, the Company
experienced a net increase of 859 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 1995, the Federal Energy Regulatory Commission ("FERC") issued a
Notice of Proposed Rulemaking ("NOPR") to promote competition and
deregulation in wholesale electric markets by requiring owners of
transmission facilities to offer nondiscriminatory open-access transmission
and ancillary services to wholesale sellers and purchasers of electric energy
in interstate commerce. This NOPR, referred to as the Mega-NOPR, requires
the establishment of tariffs by all owners of transmission facilities for
point to point and network transmission services, to which the owners of the
facilities will also be subject. The NOPR also addresses the issue of
recovery of stranded investment costs which may result when a utility's
customer is lost to another supplier of electric energy. The FERC is
currently receiving comments on the NOPR and final rules have not been
issued. The FERC has not established tariffs for transmitting utilities.
The Company has preliminarily determined that the NOPR, in its current form,
would not likely result in the Company having any stranded investment costs
due to the Company's competitively low generation costs.

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, 1995
% of
Electric % of kwh
Rates Regulation Revenues Sales
MN retail sales MN Public Utilities
Commission 46.4% 39.7%

ND retail sales ND Public Service
Commission 36.8 29.1

SD retail sales SD Public Utilities
Commission 7.1 5.6

Transmission & sales FERC
for resale 9.7 25.6
_____ _____
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, 1991:

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

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
$2,200,000 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
__________

(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.

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.

Capability and Demand

At December 31, 1995, the Company had base load net plant capability
totaling 551,594 kw, consisting of 241,256 kw from the Big Stone Plant (the
Company's 53.9% share), 155,800 kw from the Hoot Lake Plant, 149,450 kw from
the Coyote Plant (the Company's 35% share), and under contract 5,088 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 90,968 kw, and 4,193 kw of hydroelectric capability. During 1995 the
Company generated about 71% 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 1995-1996 winter season, the Company has
50,000 kw capacity available for purchase from other utilities. The Company
also has agreements to purchase 110,000 kw of capacity for the summer of 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, which
includes 29 full participans, 30 associate participants, and 1 liaison
participant 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 engage in power transactions with
each other.

The Company traditionally experiences its peak system demand during the
winter season. For the calendar year 1995, the Company established a new
system peak demand of 594,350 kw on December 11, 1995. The highest previous
sixty-minute peak demand was 589,239 kw on January 8, 1993. Taking into
account additional capacity available to it in December 1995 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 773,755 kw. In 1996 the Company expects moderate growth
in peak demand as compared to 1995. 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 1996 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 1995 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 . . . . . . . . . . . . . 2,011,566 70.0%
Subbituminous Coal . . . . . . . . . . 837,960 29.1
Hydro . . . . . . . . . . . . . . . . . 25,474 .9
Oil . . . . . . . . . . . . . . . . . . 1,219 -
_________ _____
Total . . . . . . . . . . . . . . . 2,876,219 100.0%

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. Big
Stone's long-term lignite supply contract with Knife River Coal Mining Company
ended in 1995. 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 November 1995 three of the four co-owners of the Coyote generating
plant filed a summons and 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 the Big Stone and Coyote Plants, and a 10-day
inventory at the Hoot Lake Plant.

The coal used at Big Stone Plant is transported in coal cars belonging
to the plant owners. The Company has entered into an agreement to acquire new
aluminum coal cars for transporting coal to the Big Stone Plant beginning in
September of 1996. The Company has a new 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 and
freight agreements resulted in significantly lower delivered coal prices at
the Big Stone Plant which will be returned to the Company's retail customers
through the Cost of Energy Adjustment clause.

Transportation costs of coal to Hoot Lake Plant are governed by tariffs
established pursuant to authority of the Interstate Commerce Commission. 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 the Hoot Lake Plant. That agreement
was set to expire in January 1996, but is expected to be renewed for an
additional three years.

The 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 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 1995, 1994,
and 1993, was .969 cents, 100.3 cents and 100.7 cents, 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."

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 1995, 2.3% of total
fuel burned at the Big Stone Plant, and expected to be burned in 1996, is
insignificant when compared to the coal consumption at the Big Stone Plant.

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, 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 Company submitted its first
plan in 1992, which was approved by the MPUC in 1993, and submitted its next
plan in 1994, which was approved in 1995. 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 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, 1995, approximately $8,900,000 for environmental control facilities
(excluding allowance for funds used during construction). Included in the
1996-2000 construction budget are approximately $1,680,000 for environmental
improvements for existing and new facilities, including $390,000 for 1996.

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 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. 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 sulfer
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 standards will not
apply to the Company's plants until the year 2000. 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 allows 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. The Company has 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. If the
Company elects the early opt-in provision, the Company would be governed by
the standard until January 1, 2008. Subject to additional evaluation of the
results of continuous emission monitoring which began at Hoot Lake in 1994,
the Company anticipates that it will elect the early opt-in provision for Hoot
Lake Plant unit 2 and may also do so for unit 3. The Company currently
anticipates that the cost of complying with the limitations expected to be
applicable to Hoot Lake Plant will not be material.

On January 19, 1996, the EPA also proposed NOx emissions regulations
that would be applicable to cyclone-fired boilers such as those used at Big
Stone and Coyote. The Act requires the EPA to specify before January 1, 1997,
the NOx limitations for cyclone boilers. If the regulations are adopted as
proposed, modifications may be required at Big Stone by 2000 to satisfy the
emission standards. 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
3,398 kw at December 31, 1995).

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, 1995, 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 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. The
Company derived 15% of its consolidated operating revenues from this segment
in 1995, 16% 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
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.

Mobile Imaging, Inc., located in Fargo, ND, is engaged primarily in
providing mobile CT and MRI services in the Upper Midwest, and also
provides interim scanner rental 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 technologists 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 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.

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 sector
were made in 1990. Two additional companies were acquired in 1995, one in
January and the other in October. The Company derived 12% of its consolidated
operating revenues from this segment in 1995, 5% in 1994, and 3% in 1993.

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 machines that handle and refine 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.

OTHER BUSINESS OPERATIONS
General

The Company's Other Business Operations consists of businesses that are
diversified in such areas as electrical and telephone contracting, radio
broadcasting, waste incinerating, and telephone/cable TV utility. The Company
derived 11% of its consolidated operating revenues from these diversified
businesses during 1995, 10% in 1994, and 12% during 1993.

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.

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. 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 expired in
June 1995 and have been extended) with two industrial customers,
Quadrant sells the steam generated from the incineration process. The
Company has invested approximately $3.65 million in plant and equipment
in Quadrant. Quadrant represented approximately $2.7 million in sales
for 1995 and an insignificant contribution to consolidated operating
income for the Company. Long-term extensions 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.
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.

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.

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. The EPA has proposed air emission
regulations which, if adopted as proposed, will defer to state regulations.
Quadrant currently is operating 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.

CONSTRUCTION PROGRAM & FINANCING

The Company is continually expanding, replacing and improving its
electric utility facilities. During 1995 the Company invested approximately
$28,327,000 (including allowance for funds used during construction) for
additions to its electric utility properties. During the five years ended
December 31, 1995, the Company had gross electric property additions,
including construction work in progress, of approximately $123,674,000 and
gross retirements of approximately $30,260,000. During 1995 capital
expenditures of approximately $4,000,000 were also made in both Health
Services and Manufacturing, and $2,000,000 in Other Business Operations.

Total capital expenditures for the Company and its subsidiaries during
the five-year period 1996-2000 are estimated to be approximately $171,000,000.
Of this $14,000,000 is for Health Services Operations, $9,000,000 for
Manufacturing, and $7,000,000 for Other Business Operations. The Company
estimates that during the five years 1996 through 2000 it will invest for
electric utility construction approximately $141,000,000 (including allowance
for funds used during construction). The Company continously 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 1996 through 2000 will be for
work related to the Company's transmission and distribution system.

The Company estimates that funds internally generated, combined with
funds on hand will be sufficient to meet all sinking fund payments for First
Mortgage Bonds in the next five years and to provide for the majority of its
1996-2000 construction program expenditures. Additional short-term or
long-term financing will be required in the period 1996-2000 in connection
with a portion of 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, 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, 1995, the Company had unutilized net fundable
property available for the issuance of more than $30,000,000 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. As of December
31, 1995, the Company and subsidiaries had unused credit lines totaling
$42,600,000. The Company had no short-term borrowings as of December 31,
1995. However, the subsidiary companies had $7,200,000 of credit lines in use
at December 31, 1995, 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 1,552 full-time
employees at December 31, 1995. A total of 476 employees are represented by
local unions of the International Brotherhood of Electrical Workers, of which
432 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, 1995, 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 4,270
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, 1995.

Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1996)

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 (56) 4/8/91 Present: Chairman, President and Chief
Executive Officer
Prior to
4/8/91 President and Chief Executive Officer

Andrew E. Anderson (56) 4/10/95 Present: Vice President, Finance
Prior to
4/10/95 Controller

Marlowe E. Johnson (51) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Prior to
4/12/93 Division Manager, Jamestown

Douglas L. Kjellerup (54) 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 (50) 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 (57) 1/1/78 Present: Vice President,
Corporate Services

Jay D. Myster (57) 4/12/82 Present: Vice President, Governmental
and Legal, and Corporate Secretary

Rodney C.H. Scheel (46) 4/10/95 Present: Vice President, Electrical
Prior to
4/10/95 Director, Information Services

Ward L. Uggerud (46) 4/10/89 Present: Vice President, Operations

Jeffrey J. Legge(39) 4/10/95 Present: Controller
Prior to
4/10/95 Manager, Tax Department
Prior to
5/1/91 Manager, General Accounting

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 the first sentence under "Buying and selling" on
Page 48, to "Selected consolidated financial data" on Page 23 and to
"Quarterly information" on Page 45, of the Company's 1995 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 1995 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 1995 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 1995 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, 1996. 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, 1996.

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, 1996.

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, 1996.

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 31 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, 1995.

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 /s/ A. E. Anderson
A. E. Anderson
Vice President, Finance

Dated: March 27, 1996

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 )
(principal financial officer) )
)
Jeffrey J. Legge )
Controller ) By /s/ A. E. Anderson
(principal accounting officer) ) A. E. Anderson
) Pro Se and Attorney-in-Fact
) Dated March 27, 1996
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, 1995

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,
1995:
Page in
Annual
Report to
Shareholders
Financial Statements:

Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . .33

Consolidated Balance Sheets, December 31, 1995 and 1994 . . . . . 32 & 33

Consolidated Statements of Income for the Three Years
Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . .34

Consolidated Statements of Retained Earnings for the
Three Years Ended December 31, 1995 . . . . . . . . . . . . . . . . . .34

Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . .35

Consolidated Statements of Capitalization, December 31, 1995
and 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36

Notes to Consolidated Financial Statements. . . . . . . . . . . . . 37-45

Selected Consolidated Financial Data for the Five Years
Ended December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . 23

Quarterly Data for the Two Years Ended
December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . .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, 1995

Previously Filed
As
Exhibit
File No. No.
3-A 10-K for year 3-A --Restated Articles of
ended 12/31/94 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 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 --Amendment No. 1, dated as of
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.
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-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-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 Sup-
ended 12/31/94 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 1995 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.

- ------------
*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.