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
<PAGE>
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%
===== =====
<PAGE>
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.
<PAGE>
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 )
<PAGE>
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.
Exhibit 10-G-2
Confidential information has been omitted from this Exhibit and filed
separately with the Commission pursuant to a confidential treatment
request under Rule 24b-2.
FIRST AMENDMENT
TO
COAL TRANSPORTATION AGREEMENT ICC-BN-C-2913
This First Amendment to Coal Transportation Agreement ICC-BN-C-2913
(hereinafter referred to as "First Amendment") is made pursuant to 49
U.S.C. Section 10713 on this 27th day of December, 1995, by and among
Burlington Northern Railroad Company, a Delaware corporation (hereinafter
referred to as "BN"), Otter Tail Power Company, a Minnesota corporation,
Northwestern Public Service Company, a Delaware corporation, and Montana-
Dakota Utilities Co., a Division of MDU Resources Group, Inc., a Delaware
corporation (hereinafter jointly referred to as "Utilities").
WHEREAS, BN and Utilities are parties to a Coal Transportation
Agreement dated July 18, 1994, ICC-BN-C-2913 (hereinafter referred to as
the "Original Agreement"); and
WHEREAS, Utilities own and operate and electric generating plant
described herein, known as the Big Stone Plant; and
WHEREAS, BN and Utilities desire to amend the Original Agreement to
provide for an allowance from coal transportation rates to the Big Stone
Plant; such allowance arising from Utilities' proposed use of high capacity
aluminum cars and BN's resulting provision of cars to supplement coal
transportation requirements to the Big Stone Plant.
NOW THEREFORE, in consideration of the premises, covenants, and
considerations set out herein, the parties hereto agree as follows:
Article I
Filing, Approval, Effective Date, and Term of Amendment
Section 1. Filing and Approval
Within seven (7) days after its receipt of fully executed copies of
this First Amendment, BN will file the requisite contract summary with the
ICC in accordance with the provisions of 49 U.S.C. 10713 and the ICC
regulations promulgated thereunder.
Section 2. Effective Date and Term
This First Amendment shall be effective on the date the contract
summary is filed with the ICC (hereinafter "Effective Date"); PROVIDED,
HOWEVER, that if the ICC disapproves this First Amendment, it will be null
and void ab initio and any shipments moving on or between the date of
filing of this First Amendment and the date of disapproval will be subject
to the terms of the Original Agreement. In accordance with the agreement
of the parties, subject to ICC approval of this First Amendment and the
conditions of 49 C.F.R. 1313(c), the terms of this First Amendment shall
apply on all trains of coal tendered on or after October 1, 1996.
The term of this First Amendment shall end at 11:59 p.m. Central
Standard Time on December 31, 1999.
Confidential Contract
<PAGE>
Article II
Modification of Transportation Rates
Section 1. Modification of Effective Rates - Aluminum Cars Supplied
by Utilities
Commencing with the first train tendered as of the date noted earlier
in Article I, Section 2, provided that Utilities have completed the
installation of adequate railcar unloading facilities at the Big Stone
Plant, and continuing through the term of this First Amendment as stated
above, each of the then Effective Rates shall be reduced by $(*) per ton
(the "Aluminum Car Allowance") which reflects the usage, by Utilities, of
high capacity aluminum cars. The Aluminum Car Allowance shall apply to all
tons tendered by Utilities for shipment in Utilities-supplied aluminum cars
to the Big Stone Plant. The Aluminum Car Allowance shall not be adjusted
during the term of the First Amendment.
Section 2. Rates for Use of BN-Supplied Cars
If Utilities elect to use BN-supplied cars, then commencing with the
first train tendered as of the date noted earlier in Article I, Section 2,
the rate for movement of coal from the Absaloka mine to the Big Stone Plant
in BN-supplied cars shall be $(*) per ton. This rate shall be adjusted
quarterly per Section 5 of the Original Agreement, with the first such
adjustment to become effective on January 1, 1997.
Article III
General
Nothing in this First Amendment shall alter the rights or obligations
of the parties except as specifically set forth above.
IN WITNESS WHEREOF, the parties hereto have caused this First
Amendment to Contract ICC-BN-C-2913 to be executed by their duly authorized
representatives on the day and year first written above.
OTTER TAIL POWER COMPANY
By:/S/ Ward Uggerud
Its: Vice President, Operations
NORTHWESTERN PUBLIC SERVICE COMPANY
By:/S/ A. R. Donnell
Its: V.P. Energy Operations
MONTANA-DAKOTA UTILITIES CO., a division of MDU Resources Group, Inc.
By:/S/ Bruce Imsdahl
Its: Vice President Energy Supply
BURLINGTON NORTHERN RAILROAD COMPANY
By:/S/ David S. Quilici
Its: AVP Coal Marketing
Confidential Contract
Page 2
*Confidential information has been omitted and filed separately with the
Commission pursuant to Rule 24b-2.
Exhibit 13-A
DIVIDENDS
We have paid quarterly dividends on our common stock since 1938 without
interruption or reduction. 1995 dividends were $1.76 per share. The
indicated annual rate for 1996 is $1.80.
BUYING AND SELLING
Otter Tail common stock is traded on NASDAQ's National Market System.
(NASDAQ: National Association of Securities Dealers Automated Quotation.)
Selected consolidated financial data
<TABLE>
- ----------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991 1990 1985
---------- ---------- ---------- ---------- ---------- ---------- ----------
(Thousands except per-share data)
Revenues
Electric
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $64,355 $62,687 $62,167 $59,038 $61,844 $60,326 $63,954
Commercial and farms 39,683 38,082 36,971 35,342 36,246 35,443 35,473
Industrial 69,756 69,332 65,757 63,522 62,284 58,812 57,442
Sales for resale 19,110 19,066 18,107 11,126 11,330 9,759 10,901
Other electric 11,021 9,645 9,288 8,077 7,752 7,999 7,684
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total electric $203,925 $198,812 $192,290 $177,105 $179,456 $172,339 $175,454
Health services 50,896 45,555 32,068 -- -- -- --
Manufacturing 38,690 13,083 8,473 -- -- -- --
Other business operations 35,130 30,073 32,396 32,433 20,389 8,009 --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues $328,641 $287,523 $265,227 $209,538 $199,845 $180,348 $175,454
Net income $28,945 $28,475 $27,369 $26,538 $26,096 $24,852 $24,687
Cash flow from operations $58,077 $51,832 $53,255 $44,866 $46,667 $46,681 N/A
Total assets $609,196 $578,972 $563,905 $530,456 $491,633 $477,224 $480,298
Long-term debt $168,261 $162,196 $166,563 $159,295 $146,326 $135,186 $150,902
Redeemable preferred $18,000 $18,000 $18,000 $18,000 $13,150 $13,705 $28,875
Common shares outstanding
(1) (thousands) 11,180 11,180 11,180 11,180 11,185 11,223 11,955
Number of common
shareholders (2) 13,933 14,115 13,634 13,812 13,928 13,984 16,661
Earnings per common share (3) $2.38 $2.34 $2.23 $2.17 $2.15 $1.99 $1.77
Dividends per common share $1.76 $1.72 $1.68 $1.64 $1.60 $1.56 $1.38
- ----------------------------------------------------------------------------------------------------------
Notes:
(1) Number of shares outstanding at year-end.
(2) Holders of record at year-end.
(3) Based on average number of shares outstanding.
</TABLE>
Management's discussion and analysis of
financial condition and results of operations
Management's major financial objective is to increase shareholder value by
continuing to earn a reasonable return on the Company's capital. This will
enable the Company to preserve and enhance its financial capability by
maintaining acceptable capitalization ratios, maintaining a strong interest
coverage position, providing a reasonable return to the common shareholder,
maintaining an above average level of internal cash generation, and
preserving and strengthening its current credit ratings on outstanding
securities to the benefit of both the Company's customers and its
shareholders.
Liquidity: Liquidity is the ability to generate adequate amounts of cash to
meet the Company's needs, both short-term and long-term. An electric
utility's liquidity is a function of its construction program and debt
service requirements, its net internal funds generation and its access to
long-term securities markets and credit facilities for external capital.
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 achieved a high degree of long-term liquidity by maintaining
desired capitalization ratios and strong bond ratings, implementing cost-
containment programs, evaluating operations and projects on a cost-benefit
approach, investing in projects that enhance shareholder value, and
obtaining adequate depreciation rates.
Cash provided from operations, as indicated by the Consolidated Statement of
Cash Flows for the year ended December 31, 1995, of $58,077,000, combined
with net proceeds from the sale of marketable securities in 1995 of
$17,043,000 and funds on hand of $2,243,000 at December 31, 1994, allowed
the Company to pay dividends, invest in additional nonutility businesses and
passive investments, finance its construction program, and retire First
Mortgage Bonds through sinking fund operations.
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. (Internally generated funds
consist of cash provided by operations less dividends and certain other
adjustments.)
Additional short-term or long-term financing will be required in the period
1996-2000 in connection with the following items:
- A portion of the Company's construction program.
- Maturity of First Mortgage Bonds and 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.
- Other corporate purposes.
The Company had $4.1 million in cash, cash equivalents and temporary cash
investments at December 31, 1995, and $2.2 million at December 31, 1994.
Capital Requirements: The Company has a construction and capital investment
program to provide facilities necessary to meet forecasted customer demands
and provide reliable service in the capital intensive electric utility
business. This includes improvements to existing power plants, acquisition
or construction of additional generating capacity, and upgrading or
replacing portions of the distribution and transmission systems and other
buildings and equipment. The construction program is subject to continuing
review and is revised annually in light of changes in demands for energy,
environmental laws, technology affecting the electric utility industry, the
costs of labor, materials and equipment, and Company's financial condition
(including cash flow and earnings).
Capital project expenditures for the years 1995, 1994, and 1993 were $37
million, $30 million, and $31 million, respectively. The estimated capital
expenditures for 1996 are $37 million, and the total expenditures for the
five-year period 1996-2000 are expected to be approximately $171 million.
The breakdown of 1995 actual and 1996-2000 estimated capital project
expenditures by segment is as follows:
1995 1996 1996-2000
---- ---- ---------
(in millions)
Electric utility $27 $32 $141
Health services 4 3 14
Manufacturing 4 1 9
Other business operations 2 1 7
In addition to these capital requirements, funds totaling approximately
$63,217,000 will be needed during the five-year period 1996 through 2000 to
retire First Mortgage Bonds and other long-term obligations, including
subsidiary long-term obligations, at maturity and through sinking fund
payments.
Capital Resources: Financial flexibility is provided by unused lines of
credit, financial coverages well in excess of the minimum levels required
for issuance of securities, and strong credit ratings.
As of December 31, 1995, unused credit lines totaling
$42.6 million were available to meet interim financing of working capital
and other capital requirements, if needed. The Company had no short-term
borrowings as of December 31, 1995. However, the subsidiary companies had
$7.2 million of credit lines in use at December 31, 1995, classified as
current maturities and long-term debt. (See note 9 to financial statements
for further information.)
During 1995 the Company's coverage ratios remained at almost the same levels
as in 1994. The fixed charge coverage ratio after taxes was 3.2 for 1995, as
compared to 3.3 in 1994. The long-term debt interest coverage ratio before
taxes was 4.3 for 1995, as compared to 4.5 in 1994. The Company expects
these coverages to be approximately the same in 1996.
The Company's credit ratings affect its access to the capital market. The
current credit ratings for the Company's First Mortgage Bonds are as
follows:
Moody's Investors Service Aa3
Duff and Phelps AA
Fitch Investors Service AA
Standard and Poor's AA-
The Company's disclosure of these security ratings is not a recommendation
to buy, sell, or hold the Company's securities.
As of December 31, 1995, the Company had the capacity under its Indenture of
Mortgage to issue an additional $132 million principal amount of First
Mortgage Bonds.
Results of operations:
Electric operations:
Otter Tail Power Company provides electrical service to over 120,000
customers in a service territory of over 50,000 square miles.
Operating Revenues
- ------------------
The change in revenues may be summarized as follows:
Revenue increase (decrease)
from prior year
------------------------------
1995 1994 1993
---- ---- ----
(in thousands)
Volume variance (1) $5,419 $6,979 $15,325
Price variance (2) (1,517) (492) (1,525)
Other 1,211 35 1,385
----- ----- ------
Total Electric $5,113 $6,522 $15,185
===== ===== ======
(1) Derived for each customer class by multiplying year-to-year change in
units sold by the average revenue per kwh for the prior year.
(2) Derived for each customer class by multiplying the year-to-year change
in average revenue per kwh by the units sold during the year.
The 1995 volume variance was due to a 3.4% increase in retail kwh sales.
The increase in retail kwh sales was due to increased sales in each customer
class: residential, commercial, and industrial. Total power pool sales
decreased by 1% from the previous year. Noncontractual power pool sales
increased due to a combination of warmer weather and greater plant
availability in 1995 which resulted in more opportunity sales. This
increase was offset by a 53.7% decrease in contractual power pool sales.
The 1994 volume variance was due to a 3.6% increase in retail kwh sales.
The increase in retail kwh sales was principally due to increased sales to
commercial and industrial customers. Power pool sales remained at the same
level as in the previous year. Noncontractual power pool sales declined in
1994 because of the exceptionally high level of sales in 1993. However,
contractual power pool sales were up significantly in 1994 because of a
large sale to another utility.
The 1993 volume variance was due to increased kwh sales in almost every
retail customer classification and an 84% increase in noncontractual power
pool sales. The increase in retail kwh sales can be attributed to the return
of normal winter weather in 1993 coupled with increased usage in the
commercial category. The increase in power pool sales can be attributed to
the weather, which resulted in low water conditions in the spring in
Manitoba and the widespread summer flooding in the Midwest.
Heating degree days, which generally correlate to increases or decreases in
usage by residential customers, were 9,326 for 1995, 9,204 for 1994, and
9,523 for 1993. The average revenue per retail kilowatt-hour was 5.45 cents
in 1995, 5.50 cents in 1994, and 5.53 cents in 1993.
The 1995 price variance was primarily attributed to residential and
commercial sales, sales to a large industrial customer (See discussion under
"Competition"), and the cost of energy adjustment clause. The negative
variance in these categories was partially offset by a positive price
variance in contractual power pool sales. The increase in contractual power
pool sales revenue per kwh sold resulted from spreading a fixed demand
charge over a decrease in kwh sales.
The 1994 price variance was essentially due to industrial customers and
contractual power pool sales. The decrease in contractual power pool sales
revenue per kwh sold resulted from spreading a fixed demand charge over an
increase in kwh sales.
The 1993 price variance was primarily due to noncontractual power pool
sales, residential sales, and the cost of energy adjustment clause.
Noncontractual power pool sales had a 4.3% decrease in revenue per kwh sold
in 1993. The price variance from residential sales was due to the increase
in volume sold. In 1993 slightly over $7,100,000 (an increase of $350,000
over 1992) was returned to the Company's retail customers through the cost
of energy adjustment clause. (See the explanation under "production fuel
and purchased power expense.")
The increase in the other variance in 1993 was due to the Company
recognizing unbilled revenue of $1,446,000. The increase in other variance
in 1995 reflects an increase in unbilled revenue of $388,000 over 1994 and
the initial recognition of conservation program revenues and wheeling
service fees in 1995. The Company changed its method of accounting in North
Dakota from billing dates to energy delivery dates as a result of an order
entered by the NDPSC in September 1993. The change in method of revenue
recognition resulted in additional net income of $870,000 in 1993, $751,000
in 1994, and $984,000 in 1995. The impact on earnings per share was $.08 in
1993, $.07 in 1994 and $.09 in 1995. (See notes 1 and 3 to the financial
statements for further information.)
Expenses
- --------
The percentage changes in operating expenses may be summarized as follows:
Percentage increase (decrease)
from prior year
------------------------------
1995 1994 1993
---- ---- ----
Production fuel (2) 3 10
Purchased power 7 5 22
Electric operation expenses 13 2 14
Electric maintenance (11) 6 18
Depreciation and amortization 3 4 4
Property taxes (6) 6 7
Production fuel and purchased power expense
- -------------------------------------------
In 1995, the cost of steam production fuel per kwh generated decreased by
4.1% while the total kwhs generated increased by 1.6%, which, in
combination, contributed to the 2% decrease in 1995 production fuel expense
compared to 1994. The decrease in fuel cost per unit of generation resulted
mainly from switching fuels at Big Stone plant from lignite to higher-Btu
subbituminous coal in August of 1995. The 3% increase in production fuel in
1994 resulted chiefly from a 3.2% increase in generation. The 10% increase
in production fuel in 1993 was due primarily to a 11% increase in
generation. Of the increased generation, 56% was for power pool sales and
44% was for system use.
The 7% increase in purchased power in 1995 was due to increased kwh
purchases for system use, which correlates to the increase in retail sales.
Purchased power increased 5% in 1994 essentially because of an increase in
cost per kwh purchased. The bulk of the increase in cost per kwh purchased
resulted from an increase in replacement generation cost for plant outages.
The 22% increase in purchased power costs in 1993 was related directly to
the increase in power pool sales.
The increase or decrease in fuel and purchased power costs arising from
changing prices results in adjustments to the Company's rate schedules
through the cost of energy adjustment clause. Over the last five years,
this has resulted in savings of slightly over $35 million to the Company's
customers.
Electric operation and maintenance expenses
- -------------------------------------------
The increase in electric operating expense of 13% in 1995 was primarily due
to two items: A settlement with the Minnesota Public Utilities Commission
requiring recovery of Conservation Improvement Program costs in current
rates starting in 1995 and an increase in postretirement health-care
benefit costs resulting from a plan amendment which reduces the health
insurance contribution requirements for surviving spouses of retired
employees. (See notes 3 and 8 to financial statements for further
information.) Storm-related expenses in the summer and fall of 1995 along
with 1995 economic development expenditures and wage and salary increases
also contributed to the increase in electric operating expense.
The 1994 increase of 2% in electric operating expense resulted principally
from increases in customer account expenses and payroll expenses. The
increase of 14% in electric operation expense in 1993 was due primarily to
increases in labor expenses (retiree medical benefits), North Dakota
conservation programs, and administrative and general expenses.
The 11% decrease in electric maintenance expense in 1995 was mainly due to
significant reductions in power plant maintenance expenses. Coyote plant,
which had a major overhaul in the spring of 1994 but no major overhauls in
1995, was the primary contributor to the reduction in maintenance expenses.
Lower maintenance expenses on Hoot Lake Plant Unit #2, which underwent major
repairs in the summer of 1994, also contributed to the decrease.
The increase in electric maintenance expense of 6% in 1994 was due to
increases in production and distribution maintenance. Production
maintenance increased because of boiler repairs at the Coyote Plant.
Distribution maintenance increased due to more tree-trimming expenses. The
18% increase in electric maintenance in 1993 was due to an increase in
production maintenance of the steam plants (generator, turbine, and coal-
handling equipment).
Depreciation and amortization
- -----------------------------
The increases in depreciation expense of 3% in 1995 and 4% in 1994 were
attributable to additional plant in service in each of the respective years.
The 4% increase in depreciation expense in 1993 was due to additional plant
in service and higher depreciation rates.
Property taxes
- --------------
The 6% decrease in property taxes in 1995 was mainly due to decreased
property tax rates in Minnesota and valuation decreases in South Dakota.
The increases in property taxes of 6% for 1994 and 7% for 1993 were due to
property additions and increased mill rates.
Health services operations:
Health services operations consist of businesses acquired by the Company,
beginning in 1993, which are 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.
1995 1994 1993
---- ---- ----
(in thousands)
Operating revenues $50,896 $45,555 $32,068
Cost of goods sold 31,576 28,690 19,019
Operating expenses 15,739 14,379 10,781
------- ------- -------
Pretax operating income $ 3,581 $ 2,486 $ 2,268
======= ======= =======
The 12% increase in health services operating revenues in 1995 was due to
increased sales of medical equipment in 1995 compared to 1994. The
acquisition of three additional diagnostic imaging companies in January of
1995 also contributed to the increase in operating revenues. The increase in
cost of goods sold in 1995 compared to 1994 was directly related to the 1995
increase in equipment sales. The increase in health services operating
income in 1994 was due to an increase in sales of refurbished equipment as
well as the results of a new subsidiary that was acquired by the Company
toward the end of the first quarter of 1993.
Manufacturing operations:
Manufacturing operations is made up 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.
1995 1994 1993
---- ---- ----
(in thousands)
Operating revenues $38,690 $13,083 $8,473
Cost of goods sold 29,884 9,167 6,175
Operating expenses 5,536 1,475 1,249
------- ------- ------
Pretax operating income $ 3,270 $ 2,441 $1,049
======= ======= ======
The increases in 1995 operating revenues and 1995 cost of goods sold and
operating expenses resulted principally from the acquisition of two
manufacturing companies in 1995 and sales in expanded product lines of
companies acquired prior to 1995.
The 54% increase in 1994 operating revenues, 48% increase in 1994 cost of
goods sold, and 18% increase in 1994 operating expenses were mainly the
result of increased sales of existing product lines.
Other business operations:
The Company's other business operations include a telephone utility and
businesses involved in electrical and telephone construction contracting,
radio broadcasting, and waste incinerating.
1995 1994 1993
---- ---- ----
(in thousands)
Operating revenues $35,130 $30,073 $32,396
Cost of goods sold 18,954 16,903 20,028
Operating expenses 11,152 9,779 8,813
------- ------- -------
Pretax operating income $ 5,024 $ 3,391 $ 3,555
======= ======= =======
Operating revenues increased by 17% in 1995, of which half was attributable
to increased construction revenues related to material cost billings on
large projects with a commensurate increase in cost of goods sold. The
remaining increases in revenues and pretax operating income were due to
modest contributions from all other businesses and an increase in
miscellaneous income from the sale of salvaged materials in 1995.
The decrease of 7% in operating revenues for 1994 reflects reductions in
construction revenue offset by increases in radio broadcasting revenues.
The 16% decrease in costs of goods sold in 1994 was due to decreased
construction activity while the 11% increase in 1994 operating expenses
resulted mainly from increased administrative and general and sales expenses
in the radio broadcasting businesses, one of which was acquired in 1994. The
administrative and general expenses at the construction companies remained
about the same from 1993 to 1994.
Consolidated income taxes:
The 4% increase in 1995 income tax expense was related to an increase in
pretax operating income. Income tax expense increased 11% in 1994 due
primarily to higher pretax operating income. The 2% increase in income tax
expense for 1993 was due to an increase in taxable income and higher
corporate tax rates imposed by the Omnibus Budget Reconciliation Act of
1993.
Consolidated interest charges:
Interest charges increased 11% in 1995 and 5% in 1993 due to the new
businesses acquired. Interest charges decreased in 1994 by less than 1%.
Impact of inflation:
For an electric utility, the regulatory process limits the amount of
depreciation expense included in the Company's revenue allowance and limits
electric utility plant in the rate base to original cost. Such amounts
produce cash flows that are inadequate to replace such property in the
future or preserve the purchasing power of common equity capital previously
invested. Under continuation of the current regulatory process, the Company
expects that it will be able to establish rates that will cover the
increased costs of new plant when such costs are incurred. The Company
operates under regulatory provisions that allow price increases in the cost
of fuel and purchased power to be passed to customers through automatic
adjustments to its rate schedules under the cost of energy adjustment
clause. For the past seven years this has resulted in lower retail electric
rates. Other increases in the cost of electric service must be recovered
through timely filings for rate relief with the appropriate regulatory
agency.
The Company's health services, manufacturing and other business operations
consist almost entirely of unregulated businesses. Increased operating
costs are reflected in product or services pricing with any limitations on
price increases determined by the marketplace.
Factors affecting future earnings:
Growth of electric revenue
- --------------------------
The results of operations discussed above are not necessarily indicative of
future earnings. Anticipated higher operating costs and carrying charges on
increased investment in plant, if not offset by proportionate increases in
operating revenues and other income (either by appropriate rate increases,
increases in unit sales, or increases in nonelectric operations), will
affect future earnings.
Growth in electric sales will be subject to a number of factors, including
the volume of power pool sales to other utilities, the effectiveness of
demand-side management programs, weather, competition, and the rate of
economic growth or decline in the Company's service area. The Company's
electric business is primarily dependent upon the use of electricity by
customers in our service area. Percentage changes in the Company's electric
kwh sales to retail customers over the prior year for the last three years
were an increase of 3.4% in 1995, an increase of 3.6% in 1994, and an
increase of 5.0% in 1993.
Rates of return earned on utility operations are subject to review by the
various state commissions that have jurisdiction over the electric rates
charged by the Company. These reviews may result in future revenue
reductions when actual rates of return are deemed by regulators to be in
excess of allowed rates of return.
Demand-side management
- ----------------------
Demand-side management (DSM) efforts will continue in all the jurisdictions
that the Company serves. The goal of DSM is to encourage the wise and
efficient use of electricity by customers. Successful DSM will contribute to
the more efficient and cost-effective operation of existing and future
generation and distribution facilities. Currently, Minnesota is the only
jurisdiction that mandates investments in DSM, and indications are that the
Minnesota Public Utilities Commission's (MPUC) emphasis in this area will
continue into the foreseeable future.
In 1994, the Company filed a petition with the MPUC for approval of an
annual recovery mechanism for DSM-related costs under Minnesota's
Conservation Improvement Programs (CIP). An intervenor on behalf of the
Large General Service Group filed comments against the petition and
requested the MPUC 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 MPUC, resulting in costs to the Company
of approximately $2.2 million each year for three years being absorbed in
current rates starting in 1995.
In 1995, the MPUC approved a .5030% surcharge on all Minnesota customers'
bills starting on July 1, 1995, for the recovery of conservation-related
costs over and above those being recovered in current rates. The approval
of the surcharge resulted in increased earnings of approximately $620,000 in
1995 due to recognition of revenue related to CIP impacts on 1994 and 1995
energy consumption. The current surcharge rate will be in place until June
30, 1996, when it will be revised for subsequent years' program results.
Energy adjustment clause
- ------------------------
The Company began purchasing subbituminous coal for Big Stone Plant in
August of 1995 under a new coal contract that will run through December
1999. Price reductions, in addition to plant efficiency gains due to
switching from lignite to higher-Btu subbituminous coal, are estimated to
result in cost reductions of about $4.9 million a year. The majority of
these price reductions have been and will continue to be passed on to retail
electric customers through the cost of energy adjustment clause, which
enhances the Company's competitive position.
In November of 1995 the Company and two other Coyote Plant partners
initiated a lawsuit against Knife River Coal Mining Company and its parent,
MDU Resources Group, in an attempt to resolve disputes over the pricing
mechanism included in the Coyote coal agreement. Any adjustments to Coyote
coal costs resulting from actions taken with regard to this lawsuit will be
passed on to customers through the cost of energy adjustment clause.
Environmental regulation
- ------------------------
Under current regulations the Federal Clean Air Act (the Act) is not
expected to have a significant impact on future capital requirements or
operating costs. However, proposed or future regulations under the Act,
changes in the future coal supply market, and/or other laws and regulations
could impact such requirements or costs. It is anticipated that, under
current regulatory principles, any such costs could be recovered through
rates.
The Company's plants are not subject to the Act's phase one requirements.
Phase two standards of the Act must be met by the year 2000. The Company
intends that the Big Stone Plant will maintain current levels of operation
and meet phase two requirements for sulfur dioxide emissions by burning
subbituminous coal, which is much lower in sulfur emissions than lignite.
As stated previously, the Big Stone Plant's new coal contract expires at the
end of 1999. The cost of subbituminous coal in 2000 and beyond will
probably be higher than current market price but will likely not adversely
affect the Company's power plant operations. Under recently proposed
regulations, modifications would be required at Big Stone Plant by 2000 to
satisfy proposed nitrogen oxide emission standards. Compliance costs will
depend on the regulations that are ultimately adopted and the cost of
available technologies.
The Company's Coyote Plant is equipped with sulfur dioxide removal
equipment. Compliance with the phase two requirements is not expected to
significantly impact operations at that plant. The Hoot Lake Plant already
uses low-sulfur subbituminous coal. Minor modifications may be required at
the Hoot Lake Plant to meet the phase two nitrogen oxide emission
requirements by 2000.
Competition
- -----------
The electric industry is becoming more competitive. Proposals for
restructuring are being considered by various states and at the federal
level. These proposals, along with the National Energy Policy Act of 1992
(NEPA), are expected to create more competition in the electric industry.
The NEPA reduces restrictions on operation and ownership of independent
power producers (IPP's). It also allows IPP's and other wholesale suppliers
and purchasers increased access to transmission lines. The NEPA prohibits
FERC-ordered retail wheeling, 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 that may result when a utility's customer is lost to
another wholesaler 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 proposal, in its current form, would not
likely result in its having any stranded investment costs due to its
competitively low generation costs.
As the electric industry evolves, the Company may be subject to increased
competition. However, 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 its rates are
competitive. In addition, the Company would attempt more flexible pricing
strategies under an open competitive environment.
One of the Company's largest industrial customers set a goal of reducing its
electric energy costs up to 25% by changing its consumption patterns and
implementing more efficient processes requiring less energy. The Company
worked with the customer toward achieving its goal by developing a new rate
structure under a five year contract, with provisions for extension beyond
five years, pending approval by the MPUC. If approved, the estimated impact
on future revenue will be a decrease of $1.5 million annually. The Company
anticipates that a portion of the decrease will be recovered through
increased energy consumption by the customer, during certain periods, as a
result of the new rate structure.
Diversification
- ---------------
The Company continues to investigate acquisitions of additional businesses
(both utility and nonutility) and expects continued growth in this area.
The success of these businesses and any future business purchases will
affect future earnings.
The Company has invested approximately $3.65 million in net plant and
equipment for its Quadrant subsidiary that sells steam to two industrial
customers. Steam is produced by burning garbage at a fee from several
counties. Although the original term of the contracts with the industrial
customers expired in June 1995, Quadrant Co. continues to sell steam to both
customers. The contract with one steam customer remains in effect until
terminated by either party upon one year's prior written notice. Steam
service to the other customer can be discontinued upon thirty days' notice
by either party. As of December 31, 1995, none of the parties had provided
notice of termination. In addition, the contracts for burning garbage will
expire in September 1996. Quadrant represented approximately $2.7 million
in sales for 1995 and contributed $93,000 to the Company's 1995 consolidated
net income.
In 1997, new pollution rules will be in effect that may require new
operating permits and possible modifications to Quadrant's current plant
operations and equipment. The costs to comply with the new pollution rules
will have an impact on the negotiation of new waste incineration agreements
and could affect the economic viability of the plant. Negotiations with
Quadrant's incineration customers are currently underway to establish terms
for continued service under long-term contracts. The contracts will allow
for early termination if the implementation of new pollution rules is
economically prohibitive. Successful negotiation of the above contracts
will be necessary to provide for recovery of the amount the Company has
invested in Quadrant. The amount of any losses from discontinuing
operations cannot be accurately determined at this time.
Accounting pronouncements
- -------------------------
In 1994, the Company adopted SFAS 112 - Employer's Accounting for
Postemployment Benefits - and SFAS 115 - Accounting for Certain Investments
in Debt and Equity Securities. The adoption of SFAS 112 in 1994 did not
have a material impact on the Company's financial statements. At December
31, 1994, as the result of adopting SFAS 115, the Company's marketable
securities, which were principally invested in preferred stocks of other
utilities, were recorded at fair value, which was $1,100,000 ($684,000 net
of tax) less than original cost. The unrealized loss was recorded net of
tax in shareholder's equity. The reduction in market value is because the
investments reacted adversely to the increase in general interest rates
during 1994. The Company's investment in these securities was completely
liquidated in the fourth quarter of 1995 to provide for current cash needs.
(See note 10 to the financial statements for further information.)
In March of 1995 the Financial Accounting Standards Board issued SFAS 121 -
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of, which will be effective for financial statements for
fiscal years beginning after December 15, 1995. The statement requires that
long-lived assets and certain identifiable intangibles to be held and used
by an entity be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. The statement also requires that a rate-regulated enterprise
recognize an impairment for the amount of costs excluded when a regulator
excludes all or part of a cost from the enterprise's rate base.
The nature of utility regulation generally provides for the recovery of
amounts invested in utility assets used to serve customers, over a specified
period of time, through approved service rates and allowed rates of return
on rate base. Currently, most of the Company's utility revenues are subject
to regulation. The Company has determined that the carrying amounts of all
its long-lived assets and identifiable intangibles at December 31, 1995, for
both its utility and subsidiary operations are recoverable through expected
future cash flows from the use of those assets, except in the case of its
$3.65 million investment in Quadrant's net plant. An impairment amount for
Quadrant cannot be determined at this time because of the uncertainty
Quadrant has regarding its two industrial customer contracts and the new
pollution rules scheduled for 1997 as previously discussed under
"Diversification."
In October of 1995, the Financial Accounting Standards Board issued SFAS 123
- - Accounting for Stock-Based Compensation, which will be effective for
financial statements for fiscal years beginning after December 15, 1995.
The statement establishes financial accounting and reporting standards for
stock-based employee compensation. As of December 31, 1995, the Company had
no stock-based employee compensation programs in place.
<TABLE>
Otter Tail Power Company
Consolidated Balance Sheets, December 31 1995 1994
- ----------------------------------------------------------------------------------------
(in thousands)
Assets
Plant:
<S> <C> <C>
Electric plant in service $715,305 $698,437
Other nonelectric plant 54,266 36,221
---------- ----------
Total 769,571 734,658
Less accumulated depreciation and amortization 308,174 287,902
---------- ----------
461,397 446,756
Construction work in progress 16,285 10,485
---------- ----------
Net plant 477,682 457,241
---------- ----------
Investments 12,716 22,933
---------- ----------
Intangibles--net 18,902 15,480
---------- ----------
Other assets 7,732 5,531
---------- ----------
Current assets:
Cash and cash equivalents 1,867 1,852
Temporary cash investments 2,208 391
Accounts receivable:
Trade (less accumulated provision for uncollectible accounts:
1995, $398,000; 1994, $432,000) 31,184 27,004
Other 8,276 5,172
Materials and supplies:
Fuel 3,322 3,664
Inventory, materials and operating supplies 19,408 15,794
Deferred income taxes 3,754 4,306
Accrued utility revenues 4,328 4,154
Other 4,427 3,041
---------- ----------
Total current assets 78,774 65,378
---------- ----------
Deferred debits:
Unamortized debt expense and reacquisition premiums 4,687 5,174
Regulatory assets 5,727 5,660
Other 2,976 1,575
---------- ----------
Total deferred debits 13,390 12,409
---------- ----------
Total $609,196 $578,972
========== ==========
See accompanying notes to consolidated financial statements.
- ----------------------------------------------------------------------------------------
</TABLE>
Otter Tail Power Company
<TABLE>
Consolidated Balance Sheets, December 31 1995 1994
- ----------------------------------------------------------------------------------------
(in thousands)
Liabilities
Capitalization (page 36):
Common shares, par value $5 per share -- authorized, 25,000,000
<S> <C> <C>
shares; outstanding, 1995 and 1994 -- 11,180,136 shares $55,901 $55,901
Premium on common shares 30,335 30,335
Retained earnings 98,006 90,412
---------- ----------
Total 184,242 176,648
Cumulative preferred shares:
Subject to mandatory redemption 18,000 18,000
Other 20,831 20,831
Long-term debt 168,261 162,196
---------- ----------
Total capitalization 391,334 377,675
---------- ----------
Current liabilities:
Short-term debt -- 2,900
Sinking fund requirements and current maturities 13,733 8,739
Accounts payable 27,828 22,542
Accrued salaries and wages 3,703 3,889
Federal and state income taxes accrued 393 2,095
Other taxes accrued 11,356 11,712
Interest accrued 3,509 3,524
Other 6,752 2,480
---------- ----------
Total current liabilities 67,274 57,881
---------- ----------
Noncurrent liabilities 13,498 8,245
---------- ----------
Commitments (note 6) -- --
---------- ----------
Deferred credits:
Accumulated deferred income taxes 99,398 94,911
Accumulated deferred investment tax credit 20,994 22,171
Regulatory liabilities 14,500 15,197
Other 2,198 2,892
---------- ----------
Total deferred credits 137,090 135,171
---------- ----------
Total $609,196 $578,972
========== ==========
See accompanying notes to consolidated financial statements.
- ----------------------------------------------------------------------------------------
</TABLE>
Otter Tail Power Company
<TABLE>
Consolidated Statements of Income
For the Years Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------
(in thousands)
Operating revenues:
<S> <C> <C> <C>
Electric $203,925 $198,812 $192,290
Health services 50,896 45,555 32,068
Manufacturing 38,690 13,083 8,473
Other business operations 35,130 30,073 32,396
---------- ---------- ----------
Total operating revenues 328,641 287,523 265,227
---------- ---------- ----------
Operating expenses:
Production fuel 31,559 32,311 31,325
Purchased power 30,591 28,717 27,438
Electric operation expenses 51,513 45,684 44,593
Electric maintenance 12,264 13,725 12,914
Cost of goods sold 80,414 54,760 45,222
Other nonelectric expenses 29,930 23,374 18,509
Depreciation and amortization 21,909 21,190 20,512
Property taxes 10,670 11,318 10,728
Income taxes 16,584 15,931 14,331
---------- ---------- ----------
Total operating expenses 285,434 247,010 225,572
---------- ---------- ----------
Operating income 43,207 40,513 39,655
---------- ---------- ----------
Other income and deductions:
Allowance for equity (other)
funds used during construction 229 146 120
Other income and deductions and applicable taxes 584 1,503 1,419
---------- ---------- ----------
Total other income and deductions 813 1,649 1,539
---------- ---------- ----------
Income before interest charges 44,020 42,162 41,194
---------- ---------- ----------
Interest charges:
Interest 15,223 13,749 13,881
Allowance for borrowed funds
used during construction--credit (148) (62) (56)
---------- ---------- ----------
Interest charges---net 15,075 13,687 13,825
---------- ---------- ----------
Net income 28,945 28,475 27,369
Preferred dividend requirements 2,358 2,358 2,477
---------- ---------- ----------
Earnings available for common shares $26,587 $26,117 $24,892
========== ========== ==========
Average number of common shares outstanding 11,180 11,180 11,180
Earnings per average common share $2.38 $2.34 $2.23
Dividends per common share $1.76 $1.72 $1.68
See accompanying notes to consolidated financial statements.
Consolidated Statements of Retained Earnings
For the Years Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------
(in thousands)
Retained earnings at beginning of year $90,412 $84,209 $78,189
Net income 28,945 28,475 27,369
Other 684 (684) (80)
---------- ---------- ----------
Total 120,041 112,000 105,478
---------- ---------- ----------
Dividends paid:
Cumulative preferred shares at required annual rates 2,358 2,358 2,486
Common shares 19,677 19,230 18,783
---------- ---------- ----------
Total 22,035 21,588 21,269
---------- ---------- ----------
Retained earnings at end of year $98,006 $90,412 $84,209
========== ========== ==========
See accompanying notes to consolidated financial statements.
</TABLE>
Otter Tail Power Company
<TABLE>
Consolidated Statements of Cash Flows
For the Years Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------------------------
(in thousands)
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $28,945 $28,475 $27,369
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 28,602 25,899 25,348
Deferred investment tax credit--net (1,177) (1,347) (1,234)
Deferred income taxes 751 1,386 3,937
Change in deferred debits and other assets (1,792) (1,016) (1,996)
(Gain)/loss on disposal of noncurrent assets 946 (201) (77)
Change in noncurrent liabilities and deferred credits 4,560 1,016 5,509
Allowance for equity (other) funds used during construction (229) (146) (120)
Cash provided by (used for) current
assets and current liabilities:
Change in receivables, materials, and supplies (1,035) (10,712) (227)
Change in other current assets (1,349) (339) (4,519)
Change in payables and other current liabilities 1,436 6,720 250
Change in interest and income taxes payable (1,581) 2,097 (985)
---------- ---------- ----------
Net cash provided by operating activities 58,077 51,832 53,255
---------- ---------- ----------
Cash flows from investing activities:
Gross capital expenditures (37,134) (30,411) (30,894)
Proceeds from disposal of noncurrent assets 2,417 2,574 1,574
Purchase of subsidiaries, net of cash acquired (5,808) (286) (4,056)
Change in temporary cash investments (1,817) 60 9,204
Change in marketable securities and other investments 13,151 (1,630) (7,329)
---------- ---------- ----------
Net cash used in investing activities (29,191) (29,693) (31,501)
---------- ---------- ----------
Cash flows from financing activities:
Change in short-term debt---net issuances (2,900) 2,900 --
Proceeds from issuance of long-term debt 54,482 6,433 33,156
Proceeds from issuance of preferred stock -- -- 4,000
Payments for debt and preferred stock issuance expense -- (56) (245)
Payments for retirement of long-term debt (58,418) (11,784) (24,432)
Payments to trustee for retirement of long-term debt -- -- (13,445)
Payments for retirement of preferred stock -- -- (4,080)
Dividends paid (22,035) (21,588) (21,269)
---------- ---------- ----------
Net cash used in financing activities (28,871) (24,095) (26,315)
---------- ---------- ----------
Net change in cash and cash equivalents 15 (1,956) (4,561)
Cash and cash equivalents at beginning of year 1,852 3,808 8,369
---------- ---------- ----------
Cash and cash equivalents at end of year $1,867 $1,852 $3,808
========== ========== ==========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized) $14,160 $13,160 $13,371
Income taxes $18,286 $14,058 $12,009
See accompanying notes to consolidated financial statements.
</TABLE>
Otter Tail Power Company
<TABLE>
Consolidated Statements of Capitalization, December 31 1995 1994
- ----------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Total common shareholders' equity $184,242 $176,648
---------- ----------
Cumulative preferred shares -- without par value (stated and
liquidating value $100 a share) -- authorized 1,500,000 shares;
outstanding:
Series subject to mandatory redemption
$6.35, 180,000 shares; 9,000 shares due 2002-06; 135,000
Shares due 2007 18,000 18,000
---------- ----------
Total 18,000 18,000
Less current sinking fund requirement -- --
---------- ----------
Total preferred subject to mandatory redemption 18,000 18,000
---------- ----------
Other series:
$3.60, 60,000 shares 6,000 6,000
$4.40, 25,000 shares 2,500 2,500
$4.65, 30,000 shares 3,000 3,000
$6.75, 40,000 shares 4,000 4,000
$9.00, 53,311 shares 5,331 5,331
---------- ----------
Total other preferred 20,831 20,831
---------- ----------
Cumulative preference shares -- without par value, authorized
1,000,000 shares; outstanding: none
Long-term debt:
First mortgage bond series:
8.75%, due December 15, 1997 19,000 19,200
7.25%, due August 1, 2002 19,400 19,600
7.625%, due February 1, 2003 9,360 9,480
8.75%, due September 15, 2021 19,200 19,400
8.25%, due August 1, 2022 29,100 29,400
Pollution control and industrial development series:
6.00-6.80%, due February 1, 2006, Big Stone project 5,487 5,547
8.125%, due August 1, 2009, Coyote project, series B 840 850
6.00-6.90%, due February 1, 2019, Coyote project 21,969 22,204
---------- ----------
Total 124,356 125,681
Subsidiary and other long-term debt:
Long-term lease obligation (5.625% pollution control revenue
bonds due July 1, 1998) 2,200 2,200
Industrial development refunding revenue bonds
5.00% due December 1, 2002 3,010 3,010
Pollution control refunding revenue bonds
variable 5.20% at December 31, 1995, due December 1, 2012 10,400 10,400
Industrial development revenue bond (Quadrant Co. project
variable 5.36% at December 31, 1995, due April 1, 1996 --
Otter Tail Power Company guarantor) 200 600
Obligations of Mid-States Development, Inc.
rates 3.89% to 10% at December 31, 1995 33,496 19,729
Obligations of North Central Utilities, Inc.
variable 7.31% to 7.46% at December 31, 1995 9,013 9,999
Other 8 49
---------- ----------
Total 182,683 171,668
Less:
Current maturity 12,408 7,414
Sinking fund requirement 1,325 1,325
Unamortized debt discount and premium -- net 689 733
---------- ----------
Total long-term debt 168,261 162,196
---------- ----------
Total capitalization $391,334 $377,675
========== ==========
See accompanying notes to consolidated financial statements.
</TABLE>
Otter Tail Power Company
Notes to Consolidated Financial Statements
For the Three Years Ended December 31, 1995
1. Summary of accounting policies
System of accounts -- The accounting records of the Company conform to
the Uniform System of Accounts prescribed by the Federal Energy
Regulatory Commission (FERC), the Public Service Commission of North
Dakota, and the Public Utilities Commissions of Minnesota and South
Dakota.
Principles of consolidation -- The consolidated financial statements
include the accounts of the Company and all wholly owned subsidiaries.
All significant intercompany transactions have been eliminated.
Plant, retirements, and depreciation -- Utility plant is stated at
original cost and the cost of additions includes contracted work, direct
labor and materials, allocable overheads, and allowance for funds used
during construction. The cost of depreciable units of property retired
plus removal costs less salvage is charged to the accumulated provision
for depreciation. Maintenance, repairs, and replacement of minor items
of property are charged to operating expenses. Repairs to property made
necessary by storm damage are charged to the reserve therefor. The
provisions for utility depreciation for financial reporting purposes are
made on the straight-line method based on the estimated service lives of
the properties. Such provisions as a percent of the average balance of
depreciable property were 2.97% in 1995, 2.98% in 1994, and 2.95% in
1993.
Property and equipment of nonutility and subsidiary operations are
carried at historical cost, or at the current appraised value if acquired
in a business combination, and are depreciated on a straight-line basis
over the useful lives (3 to 40 years) of the related assets. Upon sale
or retirement of property and equipment, the cost and related accumulated
depreciation are eliminated from the respective accounts and the
resulting gain or loss is included in the consolidated financial
statements.
Jointly owned plants -- The consolidated financial statements include the
Company's 53.9% and 35% ownership interests in the assets, liabilities
and expenses of the Big Stone and Coyote Plants, respectively. Amounts
at December 31, 1995 and 1994, included in Plant in Service for Big Stone
were $108,577,000 and $107,872,000, respectively, and the accumulated
provision for depreciation and amortization was $62,486,000 and
$59,757,000, respectively. Amounts at December 31, 1995 and 1994,
included in Plant in Service for Coyote were $143,748,000 and
$143,445,000, respectively, and the accumulated provision for
depreciation and amortization was $54,441,000 and $50,918,000,
respectively. The Company's share of direct expenses of the jointly
owned plants in service is included in the corresponding operating
expenses in the statement of income.
Allowance for funds used during construction (AFC) -- AFC, a noncash
item, is included in construction work in progress based on a composite
rate that assumes that funds used for construction were provided by
borrowed funds and equity funds. The AFC so included in construction
work in progress will ultimately be included in the rate base used in
establishing rates for utility services. The composite rate for AFC was
9.50% for 1995 and 10.25% for both 1994 and 1993.
Income taxes -- Comprehensive interperiod income tax allocation is used
for substantially all book and tax temporary differences. Deferred
income taxes arise for all temporary differences between pretax financial
and taxable income, and between the book and tax basis of assets and
liabilities. Deferred taxes are recorded using the tax rates scheduled
by tax law to be in effect when the temporary differences reverse. The
Company amortizes the investment tax credit over the estimated lives of
the related property.
Operating revenues -- Electric customers' meters are read and bills are
rendered on a cycle basis. Prior to 1993 the Company in all of its
jurisdictions recorded electric revenues based on billing dates.
Effective January 1, 1993, due to a North Dakota Public Service
Commission (NDPSC) order, the Company changed its method of revenue
recognition in North Dakota from billing dates to energy delivery dates.
(See note 3 for further information on the order.) The North Dakota
unbilled revenue amount as of January 1, 1993, ($4.4 million) is required
by the order to be amortized to electric revenues over 36 months. The
change in method of revenue recognition resulted in additional net income
of $870,000 in 1993, $751,000 in 1994 and $984,000 in 1995. The impact
on earnings per share was $.08 in 1993, $.07 in 1994 and $.09 in 1995.
The Company's rate schedules applicable to substantially all customers
include a cost of energy adjustment clause under which the rates are
adjusted to reflect changes in average cost of fuels and purchased power.
Since July 1, 1995, rate schedules applicable to Minnesota customers also
include a .5030% surcharge for recovery of conservation-related expenses.
(See further discussion under note 3.)
Health services' operating revenues on major equipment and installation
contracts are recorded using the percentage-of-completion method. Amounts
received in advance under customer service contracts are deferred and
recognized on a straight-line basis over the contract period.
Manufacturing revenues are recorded when products are shipped, when
services are rendered, and on a percentage-of-completion basis for large
items that are assembled over several months.
Other business operations' operating revenues are recorded when services
are rendered, products are shipped and, in the case of construction
contracts, the percentage-of-completion method is used.
Storm damage reserve -- The Company is required under its Indenture of
Mortgage to make annual provisions for storm damage of not less than .5%
of gross electric operating revenues. Provisions for loss have been used
in determining rates approved by the applicable regulatory commissions.
Provisions for 1995, 1994, and 1993 were $1,800,000, $995,000, and
$1,164,000, respectively, and repairs charged to such reserves were
$1,597,000, $1,269,000, and $1,083,000, respectively. Accrued
liabilities included $1,060,000 and $857,000 for storm damage at December
31, 1995 and 1994, respectively.
Employee incentive plan -- Effective January 1, 1988, the Company
established a gain sharing plan for the benefit of all employees. The
totals received by all employees for 1995, 1994, and 1993 were
$870,000, $1,314,000, and $1,172,000, respectively.
Use of Estimates -- In recording transactions and balances resulting from
business operations, the Company uses estimates based on the best
information available. Estimates are used for such items as plant
depreciable lives, tax provisions, uncollectible accounts, environmental
loss contingencies, unbilled revenues and actuarially determined benefit
costs. As better information becomes available (or actual amounts are
determinable), the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting
estimates. Recent changes in interest rates have resulted in changes to
actuarial assumptions used in the benefit cost calculations for
postretirement benefits. Also, the depreciable lives of certain plant
assets are reviewed and, if appropriate, revised each year, as discussed
previously. (See Note 8 for more information on the effects of these
changes in estimates.)
Reclassifications -- Certain prior year amounts have been reclassified
to conform to 1995 presentation. Such reclassification had no impact on
net income and shareholders' equity.
Cash equivalents -- The Company considers all highly liquid debt
instruments purchased with a maturity of 90 days or less to be cash
equivalents.
Consolidated Statements of Cash Flows -- Excluded from the Consolidated
Statements of Cash Flows, are the following noncash transactions: In
September of 1995, the Company recorded a $3.5 million passive investment
in the form of a delayed equity contribution to a limited liability
company. As of December 31, 1995, the Company had made actual cash
contributions of $467,000 on its obligation. The remaining balance of
$3,033,000, to be paid before August 1, 1996, is included in Other
Current Liabilities on the Company's December 31, 1995, Balance Sheet.
The Company has recorded an investment of $2 million of which $780,000
remains payable on March 1, 1996, in the form of a delayed equity
contribution to a limited partnership that invests in tax-credit
qualifying affordable housing.
Debt reacquisition premiums -- In accordance with regulatory treatment,
the Company defers debt redemption premiums and amortizes such costs over
the original life of the reacquired bonds.
Investments -- The Company's temporary cash investments consist of money
market funds recorded at cost, which approximates market. At December
31, 1994, the Company had noncurrent investments of preferred stock which
were recorded at fair value. (See further discussion under note 10.)
Inventories -- The electric operation inventories are reported at average
cost. The health service, manufacturing and other business operation
inventories are stated at the lower of cost (first-in, first-out) or
market.
Short-term debt -- The composite interest rate on short-term debt
outstanding as of December 31, 1994, was 6.5%.
Intangible assets -- The majority of the Company's intangible assets
consist of Goodwill associated with the acquisition of subsidiaries and
are amortized on a straight-line basis over periods of 40 years for the
telephone company acquired in August of 1992 and 15 years or less for all
other intangibles. The Company periodically evaluates the recovery of
intangible assets based on an analysis of undiscounted future cash
flows. Total intangibles as of December 31 are as follows:
1995 1994
------ ------
(in thousands)
Goodwill on telephone company $ 7,749 $ 7,749
Other intangible assets 15,797 11,233
------- -------
Total 23,546 18,982
Less accumulated amortization 4,644 3,502
------- -------
Intangibles-net $18,902 $15,480
2. Segment information
The Company's wholly-owned subsidiary Mid-States Development, Inc.
purchased two additional manufacturing companies and three small
diagnostic imaging companies in 1995, one additional business in 1994,
and six businesses in 1993. Of the companies purchased in 1995, one
manufacturing company and all three diagnostic imaging companies were
purchased in January, the other manufacturing company was purchased in
October.
In all acquisitions, the purchase method of accounting was used and the
acquisitions would have had no significant pro forma effect on the
Company's operating revenues, net income, or earnings per share for 1995,
1994, and 1993. The total acquisition price for all businesses was
$20,704,000.
The Company has operations in four business areas. Electric operations
includes the electric utility only. Health services operations consists
of businesses involved in the sale, service, rental, refurbishing and
operations of medical imaging equipment and the sale of related supplies
and accessories to various medical institutions primarily in midwestern
United States. Manufacturing operations include production of
agricultural equipment, plastic pipe, and fabricated metal parts. Other
business operations consists of businesses diversified in such areas as
electrical and telephone construction contracting, radio broadcasting,
waste incinerating, and telecommunications. Information for the business
segments for 1995, 1994 and 1993 is presented in the table below:
1995 1994 1993
------ ------ ------
(in thousands)
Operating revenue
Electric $203,925 $198,812 $192,290
Health services 50,896 45,555 32,068
Manufacturing 38,690 13,083 8,473
Other business operations 35,130 30,073 32,396
-------- -------- --------
Total $328,641 $287,523 $265,227
Pretax operating income
Electric $ 47,916 $ 48,126 $ 47,114
Health services 3,581 2,486 2,268
Manufacturing 3,270 2,441 1,049
Other business operations 5,024 3,391 3,555
-------- -------- --------
Total $ 59,791 $ 56,444 $ 53,986
Income taxes 16,584 15,931 14,331
-------- -------- --------
Consolidated operating income $ 43,207 $ 40,513 $ 39,655
Depreciation and amortization
Electric $ 19,448 $ 18,970 $ 18,219
Health services 517 455 435
Manufacturing 344 227 227
Other business operations 1,600 1,538 1,631
-------- -------- --------
Total $ 21,909 $ 21,190 $ 20,512
Capital expenditures
Electric $ 27,443 $ 25,693 $ 24,526
Health services 4,020 2,544 3,471
Manufacturing 3,879 357 479
Other business operations 1,792 1,817 2,418
-------- -------- --------
Total $ 37,134 $ 30,411 $ 30,894
Identifiable assets
Electric $509,588 $505,291 $498,440
Health services 41,623 26,415 23,175
Manufacturing 27,270 7,215 5,815
Other business operations 30,715 40,051 36,475
-------- -------- --------
Total $609,196 $578,972 $563,905
3. Rate matters
On July 1, 1995, the Company began charging all Minnesota customers a
.5030% surcharge on their electric service statements for recovery of
conservation-related costs exceeding the amount already included in base
rates. The conservation-related costs being recovered through the
surcharge and in base rates include Conservation Improvement Program
(CIP) expenditures, carrying charges on costs incurred in excess of costs
currently being recovered, lost margins on avoided kilowatt-hour sales,
and bonus incentives related to energy savings. The MPUC approved
recovery of 1994 lost margins and bonus incentives in 1995. The Company
recorded revenues related to 1995 and 1994 lost margins and bonus
incentives of $477,000 and $537,000, respectively. As these costs are
recovered through the monthly billing process, the amounts billed are
offset by the amortization of deferred (CIP) charges.
In 1994 the Company filed a petition with the MPUC for approval of an
annual recovery mechanism for DSM-related costs, under Minnesota's CIP.
An intervenor, on behalf of the large general service group, filed
comments against the petition and requested the MPUC 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 MPUC, resulting in costs of approximately $2.2 million each year for
three years which must be absorbed in current rates starting in 1995.
On September 22, 1993, the NDPSC entered an order approving an agreement
for incentive regulation for 1993. The Agreement provided a mechanism
for sharing equally between ratepayers and shareholders any amounts
earned in 1993 over or under a specified return on rate base in North
Dakota. As part of the calculation, the NDPSC will allow the Company to
recognize postretirement benefits other than pensions under the accrual
method required by SFAS 106. The NDPSC's order also requires the Company
to change its method of revenue recognition in North Dakota as of January
1, 1993, from billing dates to energy delivery dates. (See "operating
revenues" under note 1 for more information on the accounting for
unbilled revenue.)
As a result of 1993 Incentive Regulation, the Company refunded $413,000,
plus accrued interest, to its North Dakota customers in December 1994.
Incentive regulation was not in place in 1994 or 1995.
4. Common shares
The Company's stock repurchase plan, extended by the Company in 1993,
expired on December 31, 1995. The purpose of the plan was to reduce the
common equity portion of the Company's capital structure. A total of
787,376 shares were purchased under the program, which began in 1989. No
shares were purchased in 1995, 1994 or 1993.
5. Retained earnings restriction
The Company's Indenture of Mortgage and Articles of Incorporation, as
amended, contain provisions that limit the amount of dividends that may
be paid to common shareholders. Under the most restrictive of these
provisions, retained earnings at December 31, 1995, were restricted by
$9,686,000.
6. Commitments
At December 31, 1995, the Company had commitments under contracts in
connection with construction programs aggregating approximately
$7,500,000. For capacity requirements the Company has agreements
extending through April of 2005, at annual costs of approximately
$8,000,000 in 1996, $2,800,000 in 1997, $2,300,000 in each year of 1998
through 2004 and $760,000 in 2005.
The Company also has several long-term coal contracts in which the
Company is responsible for making payment only upon the delivery of the
coal. The risk of loss from nonperformance of the contracts is
considered nominal because of the availability of other suppliers and the
expected continued reliability of the current fuel suppliers.
Furthermore, the cost of energy adjustment provision in the rate-making
process lessens the risk of loss (in the form of increased costs) from
market price changes because it assures recovery of almost all fuel
costs. The Company has entered into an agreement to acquire new aluminum
coal cars for transporting coal to Big Stone Plant beginning in September
of 1996. The Company intends to lease the cars under an operating lease
with a term of 15-20 years and annual lease payments approximating $1
million per year.
7. Long-term obligations
Preferred shares -- On November 12, 1993, the Company retired 40,000
shares of the $9.50 series.
The $6.35 cumulative preferred shares are redeemable in whole or in part
at the option of the Company after December 1, 1997, at $103.175.
The $9.00 exchangeable cumulative preferred shares are redeemable in
whole or in part at the option of the Company after August 9, 1999, for
$100.00 per share payable in cash or, at the holder's election, common
shares. Subject to certain conditions, such shares are exchangeable at
the option of the holder after August 9, 1999, for $100.00 per share in
cash or common shares.
Long-term debt -- All utility property, with certain minor exceptions, is
subject to the lien of the Indenture of Mortgage of the Company securing
its First Mortgage Bonds. The Company is required by the Indenture to
make annual payments (exclusive of redemption premiums) for sinking fund
purposes, except that the requirement with respect to certain series may
be satisfied by the delivery of bonds of such series of equal principal
amount. The Company issued First Mortgage Bonds of its pollution control
and industrial development series to secure payment of a like principal
amount of revenue bonds that were issued by local governmental units to
finance facilities leased or purchased and that the Company has
capitalized. The aggregate amounts of maturities and sinking fund
requirements on bonds outstanding and other long-term obligations at
December 31, 1995, for each of the next five years are $13,733,000 for
1996, $29,979,000 for 1997, $10,010,000 for 1998, $5,007,000 for 1999,
and $4,488,000 for 2000.
8. Pension plan and other postretirement benefits
The Company's noncontributory funded pension plan covers substantially
all electric utility employees. The plan provides 100% vesting after 5
vesting years of service and for retirement compensation at age 65, with
reduced compensation in cases of retirement prior to age 62. The Company
reserves the right to discontinue the plan, but no change or
discontinuance may affect the pensions theretofore vested. The Company's
policy is to fund pension costs accrued. All past service costs have been
provided for. The total pension expense was $1,009,000 for 1995,
$1,356,000 for 1994, and $1,333,000 for 1993. A portion of the pension
expense is capitalized as a part of utility plant construction.
The pension plan has a trustee who is responsible for pension payments to
retirees. Five investment managers are responsible for managing the
plan's assets. In addition, an independent actuary performs the
necessary actuarial valuations for the plan.
Net periodic pension cost for 1995, 1994, and 1993 includes the following
components:
1995 1994 1993
------ ------ ------
(in thousands)
Service cost-benefit earned during the period $ 1,908 $ 2,076 $ 1,774
Interest cost on projected benefit obligation 6,511 6,209 5,867
------- ------- -------
$ 8,419 $ 8,285 $ 7,641
(Gain)/loss on return on assets (26,509) 3,234 (7,636)
Plus/(less): net deferral and amortization 19,099 (10,163) 1,328
------- ------- -------
Net periodic pension cost $ 1,009 $ 1,356 $ 1,333
======= ======= =======
The assumptions used for actuarial valuations were:
1995 1994 1993
------ ------ ------
Discount rate 7.25% 8.00% 7.50%
Rate of increase in future compensation level 4.25% 4.50% 4.50%
Long-term rate of return on assets 8.50% 8.50% 8.00%
The plan assets consist of common stock and bonds of public companies,
U.S. Government Securities, cash and cash equivalents.
The funded status of the plan and amounts recognized on the balance sheet
at December 31, 1995 and 1994, are as follows:
1995 1994
------ ------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 69,340 $ 60,528
Nonvested benefits 8,594 7,645
-------- --------
Accumulated benefit obligation $ 77,934 $ 68,173
======== ========
Projected benefit obligation $ 95,359 $ 83,653
Plan assets at fair value 110,728 87,313
-------- --------
Funded status $ 15,369 $ 3,660
Unrecognized transition asset (1,486) (1,722)
Unrecognized prior service cost 9,200 10,079
Unrecognized net actuarial (gain) or loss (18,057) (7,581)
-------- --------
Net pension asset $ 5,026 $ 4,436
======== ========
In addition to providing pension benefits to all employees, the Company
has an unfunded, nonqualified benefit plan for executive officers and
certain key management employees. This plan provides defined benefit
payments to these employees upon their retirements or to their
beneficiaries upon their deaths for a 15-year period. Life insurance
carried on the plan participants is payable to the Company upon the
employee's death. The net periodic pension cost of this program in 1995,
1994 and 1993 was $412,000, $271,000, and $141,000, respectively.
The funded status of the plan and amounts recognized on the balance sheet
at December 31, 1995 and 1994, are as follows:
1995 1994
------ ------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 3,067 $ 1,882
Nonvested benefits 583 575
------- -------
Accumulated benefit obligation $ 3,650 $ 2,457
======= =======
Projected benefit obligation $ 3,650 $ 2,457
Plan assets at fair value -- --
------- -------
Funded Status $(3,650) $(2,457)
Unrecognized transition obligation 102 123
Unrecognized prior service cost 1,177 1,235
Unrecognized net actuarial (gain) or loss 1,018 68
Additional liability (1,426) (414)
------- -------
Accrued benefit liability $(2,779) $(1,445)
======= =======
The assumptions used for actuarial valuations for 1995 and 1994 were
discount rates of 7.5% and 8.0% respectively and a salary scale rate
increase of 5%.
In addition to providing pension benefits, the Company provides a portion
of health insurance and life insurance benefits for retired employees.
Substantially all of the Company's electric utility employees may become
eligible for health insurance and life insurance benefits if they reach
age 55 and have 10 years of service. Effective January 1, 1993, the
Company adopted Statement of Financial Accounting Standards No. 106 -
Employers' Accounting for Postretirement Benefits Other Than Pensions
(SFAS 106). SFAS 106 requires the Company to accrue the estimated cost
of retiree benefit payments during the years the employee provides
service. The Company previously expensed the cost of these benefits,
which are principally health care, as claims were incurred. The Company
has elected to recognize the transitional obligation of approximately
$17,619,000 over a period of twenty years. The plan was amended during
the fourth quarter of 1995 to reduce the contribution required of an
employee's surviving spouse for health insurance. This amendment
increased benefit costs by $2,155,000 in 1995 because most of the prior
service cost was related to retired employees' spouses for which the
Company has no current economic benefit. The Company estimates this
amendment will have a service cost of approximately $200,000 per year in
future years. The Company's cash flows are not affected by
implementation of SFAS 106.
The net postretirement benefit cost for 1995, 1994, and 1993 includes the
following components:
1995 1994 1993
------ ------ ------
(in thousands)
Service cost - benefit earned during the period $ 411 $ 596 $ 502
Interest cost on accumulated postretirement
benefit obligation 1,187 1,412 1,367
Amortization of transition obligation 881 881 881
Amortization of experience (gain)/loss (311) -- --
Plan amendment prior service cost 2,155 -- --
------ ------ ------
Net postretirement benefit cost $4,323 $2,889 $2,750
====== ====== ======
The funded status of the plan and the amounts recognized on the balance
sheet at December 31, 1995 and 1994, are as follows:
1995 1994
------ ------
(in thousands)
Actuarial present value of benefit obligation:
Retirees $ 10,276 $ 10,377
Fully eligible plan participants 5,000 5,289
Other active plan participants 2,607 3,576
-------- --------
Accumulated postretirement benefit obligation $ 17,883 $ 19,242
Plan assets at fair value -- --
-------- --------
Funded status $(17,883) $(19,242)
Unrecognized (gain)/loss (4,662) (566)
Unrecognized transitional obligation 14,976 15,857
-------- --------
Postretirement benefit liability $ (7,569) $ (3,951)
======== ========
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 1995, was 9.5% for
1996, decreasing linearly each successive year until it reaches 5% in
2001, after which it remains constant. The assumed health care cost
trend rate used in measuring the accumulated postretirement benefit
obligation as of December 31, 1994, was 10.5% for 1995, decreasing
linearly each successive year until it reaches 5% in 2001, after which it
remains constant. The assumed discount rates used in determining the
accumulated postretirement benefit obligation as of December 31, 1995 and
1994, were 7.25% and 8%, respectively. A one-percentage-point increase in
the assumed health care cost trend rate for each year would increase the
accumulated postretirement obligation as of December 31, 1995, by
approximately 13% and the service and interest cost components of the net
postretirement health care cost in 1995 by approximately 15%.
The Company has a leveraged employee stock ownership plan (ESOP) for the
benefit of all its employees. Contributions made by the Company were
$993,000 for 1995, $970,000 for 1994, and $940,000 for 1993.
9. Compensating balances and short-term borrowings
The Company maintains formal bank lines of credit for its electric
utility operations separate from lines and letters of credit maintained
by the subsidiary companies. They make available to the Company bank
loans for short-term financing and provide backup financing for
commercial paper notes. At December 31, 1995, the Company maintained no
compensating balances to support formal bank lines of credit. The
Company's bank lines of credit for electric utility operations totaled
$30,000,000 of which none was used at December 31, 1995. The subsidiary
companies' bank lines and letters of credit, which require no
compensating balances, totaled $19,850,000 of which $7,236,000 was used
at December 31, 1995. Based on the terms and nature of use of the
subsidiaries' lines, outstanding amounts are reflected in long-term debt
and current maturities on the Company's consolidated balance sheets.
10. Fair value of financial instruments
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:
Cash and short-term investments -- The carrying amount approximates fair
value because of the short-term maturity of those instruments.
Marketable securities -- The fair value of investments are estimated
based on quoted market prices.
Other investments -- The carrying amount approximates fair value. A
portion of other investments are in financial instruments that have
variable interest rates that reflect fair value. The remainder of other
investments is accounted for by the equity method which, in the case of
operating losses, results in a reduction of the carrying amount.
Redeemable preferred stock -- The fair value is estimated based on the
current rates available to the Company for the issuance of redeemable
preferred stock.
Long-term debt -- The fair value of the Company's long-term debt is
estimated based on the current rates available to the Company for the
issuance of debt.
1995 1994
------------------ ------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
-------- -------- -------- --------
Cash and short-term investments $ 4,075 $ 4,075 $ 2,243 $ 2,243
Marketable securities -- -- 17,132 17,132
Other investments 12,716 12,716 5,801 5,801
Redeemable preferred stock (18,000) (18,650) (18,000) (17,487)
Long-term debt (168,261) (183,099) (162,196) (160,694)
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115 - Accounting for Certain Investments in Debt
and Equity Securities (SFAS 115). SFAS No. 115 establishes standards of
financial accounting and reporting for investments in equity securities
that have readily determinable values and for all investments in debt
securities. The Company's marketable securities are included in
investments on the balance sheet and are classified as available for
sale. These securities are recorded at fair value with any unrealized
gain or loss included as a separate component in the retained earnings on
the balance sheet. Realized gains and losses are computed on each
specific investment sold. The amounts recognized on the balance sheet as
of December 31, 1995 and 1994 and amounts sold for each year are as
follows:
1995 1994
------ ------
(in thousands)
Available for sale - securities
Cost $-- $18,268
Gross unrealized gain -- 99
Gross unrealized loss -- (1,235)
------- -------
Fair value $-- $17,132
======= =======
Proceeds from sale $90,774 $39,092
Gross realized gains 1,591 993
Gross realized losses (2,816) (1,066)
11. Income tax expense
The total income tax expense differs from the amount computed by applying
the federal income tax rate (35% in 1995, 1994 and 1993) to net income
before total income tax expense for the following reasons:
1995 1994 1993
------ ------ ------
(in thousands)
Tax computed at federal statutory rate $15,786 $15,525 $14,495
Increases (decreases) in tax from:
State income taxes net of federal
income tax benefit 2,097 2,088 1,926
Investment tax credit amortization (1,177) (1,347) (1,234)
Depreciation differences -- flow-through
method reversal 222 617 649
Differences reversing in excess of
federal rates (754) (707) (635)
Dividend received/paid deduction (872) (889) (824)
Permanent and other differences 857 594 (333)
------- ------- -------
Total Income tax expense $16,159 $15,881 $14,044
======= ======= =======
Overall effective federal and
state income tax rate 35.8% 35.8% 33.9%
Income tax expense is comprised of the following:
Charged (credited) to operations:
Current federal income taxes $13,840 $12,892 $ 9,288
Current state income taxes 3,201 2,935 2,344
Deferred federal income taxes 603 1,185 3,275
Deferred state income taxes 117 266 658
Investment tax credit amortization (1,177) (1,347) (1,234)
------- ------- -------
Total $16,584 $15,931 $14,331
Charged (credited) to other income and deductions:
Current federal income taxes (269) 115 (192)
Current state income taxes (21) 50 (11)
Deferred federal and state income taxes (135) (215) (84)
------- ------- -------
Total Income tax expense $16,159 $15,881 $14,044
======= ======= =======
The Company's deferred tax assets and liabilities were comprised of the
following on December 31, 1995 and 1994:
1995 1994
------ ------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 13,782 $ 14,544
Vacation accrual 953 844
Unbilled/unearned revenue 3,886 3,864
Operating reserves 5,137 3,572
Nondeductible land - plant abandonment 1,134 1,134
Transfer to regulatory asset (689) (790)
Other 1,364 1,716
-------- --------
Total deferred tax assets $ 25,567 $ 24,884
-------- --------
Deferred tax liabilities
Differences related to property (114,081) (110,062)
Excess tax over book - pensions (1,994) (1,759)
Transfer to regulatory asset (2,563) (1,157)
Transfer to regulatory liability 649 657
Other (3,222) (3,168)
--------- ---------
Total deferred tax liabilities $(121,211) $(115,489)
--------- ---------
Deferred income taxes $ (95,644) $ (90,605)
========= =========
12. Property, plant and equipment
December 31, 1995 1994
------ ------
(in thousands)
Production $ 302,601 $ 300,712
Transmission 132,031 129,627
Distribution 207,248 198,163
General 73,425 69,935
Other nonelectric plant 54,266 36,221
--------- ---------
769,571 734,658
Less accumulated depreciation & amortization 308,174 287,902
--------- ---------
461,397 446,756
Construction work in progress 16,285 10,485
--------- ---------
Net plant $ 477,682 $ 457,241
========= =========
<PAGE>
13. Quarterly information (unaudited)
<TABLE>
The quarterly data shown below reflects seasonal and timing variations that are common in the utility
industry.
Three Months Ended
---------------------------------------------------------------------
March 31 June 30 September 30 December 31
--------------- --------------- --------------- ---------------
1995 1994 1995 1994 1995 1994 1995 1994
------ ------ ------ ------ ------ ------ ------ ------
(in thousands except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $83,963 $73,436 $73,807 $68,917 $81,048 $71,142 $89,823 $74,028
Operating income $12,598 $12,347 $8,572 $8,267 $11,022 $8,943 $11,015 $10,956
Net income $8,707 $9,356 $5,337 $5,397 $7,147 $5,905 $7,754 $7,817
Earnings available for
common shares $8,118 $8,766 $4,747 $4,808 $6,557 $5,315 $7,165 $7,228
Earnings per common share $.73 $.78 $.42 $.43 $.59 $.48 $.64 $.65
Dividends paid per common share $.44 $.43 $.44 $.43 $.44 $.43 $.44 $.43
Price range:
high $35 $34 3/4 $35 $34 $35 1/4 $34 3/4 $37 3/4 $34 3/4
low $31 3/4 $29 1/2 $30 3/4 $29 1/2 $32 1/4 $29 3/4 $34 1/8 $29 3/4
Average number of common
shares outstanding 11,180 11,180 11,180 11,180 11,180 11,180 11,180 11,180
</TABLE>
Independent Auditors' Report
To the Shareholders of Otter Tail Power Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Otter Tail Power Company and its subsidiaries (the
Company) as of December 31, 1995 and 1994, and the related consolidated
statements of income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 1995. These consolidated
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1995 and 1994, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
January 29, 1996
Minneapolis, Minnesota
Exhibit 21-A
OTTER TAIL POWER COMPANY
Subsidiaries of the Registrant
March 1, 1996
Company State of Organization
Minnesota Dakota Generating Company Minnesota
Otter Tail Realty Company Minnesota
Otter Tail Management Corporation* Minnesota
ORD Corporation* Minnesota
Quadrant Co. Minnesota
North Central Utilities, Inc. Minnesota
Midwest Information Systems, Inc. Minnesota
Midwest Telephone Co. Minnesota
Osakis Telephone Company Minnesota
Data Video Systems, Inc. Minnesota
MIS Investments, Inc. Minnesota
Mid-States Development, Inc. Minnesota
Glendale Machining, Inc. Minnesota
Precision Machine of North Dakota, Inc. North Dakota
Dakota Machine, Inc. North Dakota
Aerial Contractors, Inc. North Dakota
Moorhead Electric, Inc. Minnesota
KFGO, Inc. North Dakota
Western Minnesota Broadcasting Company Minnesota
Imaging Plus, Inc. North Dakota
Mobile Imaging, Inc. North Dakota
Diagnostic Medical Systems, Inc. North Dakota
DMS Leasing Corporation North Dakota
Medical Operators and Management Corp. North Dakota
BTD Manufacturing, Inc. Minnesota
Northern Pipe Products, Inc. North Dakota
Radiographic Supply, Inc. Montana
Dakota Engineering, Inc. North Dakota
Fargo Baseball, LLC Minnesota
*Inactive
POWER OF ATTORNEY
__________
I, JEFFREY J. LEGGE, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Controller and Principal
Accounting Officer of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended December
31, 1995, and any and all amendments to said Annual Report, and to
deliver on my behalf said Annual Report and any and all amendments
thereto, as each thereof is so signed, for filing with the Securities
and Exchange Commission pursuant to the Securities Exchange Act of 1934,
as amended.
Date: _______1/8_____________, 1996.
_______Jeffrey J. Legge____________
Jeffrey J. Legge
In Presence of:
_______Kathy Kowalski____________
_______Todd Wahlund______________
<PAGE>
POWER OF ATTORNEY
__________
I, JOHN C. MAC FARLANE, do hereby constitute and appoint A. E.
ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any one
of them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as President and Chief Executive Officer, Principal
Executive Officer and Director of Otter Tail Power Company, the Annual
Report of Otter Tail Power Company on Form 10-K for its fiscal year
ended December 31, 1995, and any and all amendments to said Annual
Report, and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: ______12/22 _________, 1995.
_______John C. MacFarlane____________
John C. MacFarlane
In Presence of:
_______Penny Mosher________________
_______Dee Fletcher_______________
<PAGE>
POWER OF ATTORNEY
__________
I, ROBERT N. SPOLUM, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: _____12/26__________, 1995
______Robert N.Spolum________________
Robert N. Spolum
In Presence of:
_______Linda Brenzel_______________
_______Michele Pingel______________
<PAGE>
POWER OF ATTORNEY
__________
I, NATHAN I. PARTAIN, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ______1/9___________, 1996.
______Nathan I. Partain______________
Nathan I. Partain
In Presence of:
______Tom Lewis____________________
______James C. Hermann_____________
<PAGE>
POWER OF ATTORNEY
__________
I, DAYLE DIETZ, do hereby constitute and appoint JOHN C. MAC
FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ______1/4___________, 1996.
______Dayle Dietz____________________
Dayle Dietz
In Presence of:
________Diane S. Pederson__________
________Owen E. Jensen_____________
<PAGE>
POWER OF ATTORNEY
__________
I, ARVID R. LIEBE, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and ExchangeCommission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ________12/26_______, 1995.
______Arvid R. Liebe_________________
Arvid R. Liebe
In Presence of:
_________Daryl Liebe_______________
_________Susan M. Stengel__________
<PAGE>
POWER OF ATTORNEY
__________
I, THOMAS M. BROWN, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: _______12/28________, 1995.
_____Thomas M. Brown_________________
Thomas M. Brown
In Presence of:
_____Donna M. Huee_________________
_____Linda J. Barnes_______________
<PAGE>
POWER OF ATTORNEY
__________
I, C. E. BRUNKO, do hereby constitute and appoint JOHN C. MAC
FARLANE, A. E. ANDERSON, JAY D. MYSTER, and BEVERLY A. NORLIN, or any
one of them, my Attorney-in-Fact for the purpose of signing, in my name
and on my behalf as Assistant Treasurer and Assistant Secretary of Otter
Tail Power Company, the Annual Report of Otter Tail Power Company on
Form 10-K for its fiscal year ended December 31, 1995, and any and all
amendments to said Annual Report, and to deliver on my behalf said
Annual Report and any and all amendments thereto, as each thereof is so
signed, for filing with the Securities and Exchange Commission pursuant
to the Securities Exchange Act of 1934, as amended.
Date: _______1/3__________, 1996.
______C. E. Brunko___________________
C. E. Brunko
In Presence of:
_______Susan K. Vukonich___________
_______Loren K. Hanson_____________
<PAGE>
POWER OF ATTORNEY
__________
I, MAYNARD D. HELGAAS, do hereby constitute and appoint JOHN
C. MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY
A. NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ________12/28_______, 1995.
______Maynard D. Helgaas_____________
Maynard D. Helgaas
In Presence of:
_______Ronald Herraas______________
_______Denice S.Nichel_____________
<PAGE>
POWER OF ATTORNEY
__________
I, KENNETH L. NELSON, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ___1/29_____________, 1996
_____Kenneth L. Nelson_____
Kenneth L. Nelson
In Presence of:
_____D. R. Emmen___________________
_____Dayle Dietz___________________
<PAGE>
POWER OF ATTORNEY
__________
I, DENNIS R. EMMEN, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A.
NORLIN, or any one of them, my Attorney-in-Fact for the purpose of
signing, in my name and on my behalf as Director of Otter Tail Power
Company, the Annual Report of Otter Tail Power Company on Form 10-K for
its fiscal year ended December 31, 1995, and any and all amendments to
said Annual Report, and to deliver on my behalf said Annual Report and
any and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ______1/2___________, 1996
______Dennis R. Emmen________________
Dennis R.Emmen
In Presence of:
_______Becky Luhning_______________
_______Penny Mosher________________
<PAGE>
POWER OF ATTORNEY
__________
I, A. E. ANDERSON, do hereby constitute and appoint JOHN C.
MAC FARLANE, JAY D. MYSTER, C. E. BRUNKO, and BEVERLY A. NORLIN, or any
one of them, my Attorney-in-Fact for the purpose of signing, in my name
and on my behalf as Vice President, Finance of Otter Tail Power Company,
the Annual Report of Otter Tail Power Company on Form 10-K for its
fiscal year ended December 31, 1995, and any and all amendments to said
Annual Report, and to deliver on my behalf said Annual Report and any
and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: ______1/8___________, 1996.
_____A. E. Anderson__________________
A. E. Anderson
In Presence of:
______Penny Mosher_________________
______Lori D. Dawkins_____________
<PAGE>
POWER OF ATTORNEY
__________
I, BEVERLY A. NORLIN, do hereby constitute and appoint JOHN C.
MAC FARLANE, A. E. ANDERSON, JAY D. MYSTER, and C. E. BRUNKO, or any one
of them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as Assistant Secretary of Otter Tail Power Company, the
Annual Report of Otter Tail Power Company on Form 10-K for its fiscal
year ended December 31, 1995, and any and all amendments to said Annual
Report, and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: ______1/4___________, 1996.
______Beverly A. Norlin______________
Beverly A. Norlin
In Presence of:
______Becky Luhning________________
______Penny Mosher_________________
<PAGE>
POWER OF ATTORNEY
__________
I, JAY D. MYSTER, do hereby constitute and appoint JOHN C. MAC
FARLANE, A. E. ANDERSON, BEVERLY A. NORLIN, and C. E. BRUNKO, or any one
of them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as Vice President, Governmental & Legal and Corporate
Secretary of Otter Tail Power Company, the Annual Report of Otter Tail
Power Company on Form 10-K for its fiscal year ended December 31, 1995,
and any and all amendments to said Annual Report, and to deliver on my
behalf said Annual Report and any and all amendments thereto, as each
thereof is so signed, for filing with the Securities and Exchange
Commission pursuant to the Securities Exchange Act of 1934, as amended.
Date: _______1/2__________, 1996.
______Jay D. Myster__________________
Jay D. Myster
In Presence of:
_______Becky Luhning_______________
_______Penny Mosher________________
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of December 31, 1995, and the Consolidated
Statement of Income for the twelve months ended December 31, 1995, and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 439,850
<OTHER-PROPERTY-AND-INVEST> 77,182
<TOTAL-CURRENT-ASSETS> 78,774
<TOTAL-DEFERRED-CHARGES> 13,390
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 609,196
<COMMON> 55,901
<CAPITAL-SURPLUS-PAID-IN> 30,335
<RETAINED-EARNINGS> 98,006
<TOTAL-COMMON-STOCKHOLDERS-EQ> 184,242
18,000
20,831
<LONG-TERM-DEBT-NET> 168,261
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 13,733
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 204,129
<TOT-CAPITALIZATION-AND-LIAB> 609,196
<GROSS-OPERATING-REVENUE> 328,641
<INCOME-TAX-EXPENSE> 16,584
<OTHER-OPERATING-EXPENSES> 268,850
<TOTAL-OPERATING-EXPENSES> 285,434
<OPERATING-INCOME-LOSS> 43,207
<OTHER-INCOME-NET> 813
<INCOME-BEFORE-INTEREST-EXPEN> 44,020
<TOTAL-INTEREST-EXPENSE> 15,075
<NET-INCOME> 28,945
2,358
<EARNINGS-AVAILABLE-FOR-COMM> 26,587
<COMMON-STOCK-DIVIDENDS> 19,677
<TOTAL-INTEREST-ON-BONDS> 14,558
<CASH-FLOW-OPERATIONS> 58,077
<EPS-PRIMARY> 2.38
<EPS-DILUTED> 2.38
