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, 1997
OR
( ) Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 (no fee required)
For the transition period from _______to_______
Commission File Number 0-368
OTTER TAIL POWER COMPANY
(Exact name of registrant as specified in its charter)
MINNESOTA 41-0462685
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
215 S. CASCADE ST., BOX 496, FERGUS FALLS, MN 56538-0496
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (218) 739-8200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
NONE NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON SHARES, par value $5.00 per share
PREFERRED SHARE PURCHASE RIGHTS
CUMULATIVE PREFERRED SHARES, without par value
(Title of class)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. (X)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. (Yes X No )
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant.
$441,675,411 as of February 28, 1998
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of the latest practicable date:
11,661,397 Common Shares ($5 par value) as of February 28, 1998
Documents Incorporated by Reference:
1997 Annual Report to Shareholders - Portions incorporated by reference into
Parts I and II
Proxy Statement dated March 13, 1998 - Portions incorporated by reference
into Part III
PART I
Item 1. BUSINESS
--------
(a) General Development of Business
-------------------------------
Otter Tail Power Company (the "Company") is an operating public utility
incorporated in 1907 under the laws of the State of Minnesota. The Company's
principal executive office is located at 215 South Cascade Street, Box 496,
Fergus Falls, Minnesota 56538-0496; its telephone number is (218) 739-8200.
The Company's primary business is the production, transmission,
distribution and sale of electric energy. The Company, through its
subsidiaries, is also engaged in other businesses which are referred to as
Manufacturing, Health Services and Other Business Operations. Manufacturing
Operations is made up of businesses acquired beginning in 1990 involved in the
production of agricultural equipment, automobile and truck frame straightening
equipment, plastic pipe extrusion, and metal parts stamping and fabrication.
Health Services Operations consists of certain businesses acquired 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. 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. On January 2,
1997, the Company's telecommunications subsidiary, North Central Utilities,
Inc. ("NCU"), acquired The Peoples Telephone Co. of Bigfork ("Peoples"), with
1,903 access lines serving five communities in Northern Minnesota. On June 30,
1997, the Company's subsidiary, Mid-States Development, Inc. ("Mid-States"),
acquired Chassis Liner Corporation ("Chassis Liner"), a manufacturer of auto
and truck frame straightening equipment. Both acquisitions were accounted for
under the pooling-of-interest method.
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 22 through 30 of the
Company's 1997 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 Operations, Manufacturing Operations,
Health Services Operations, 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 1997 Annual Report to Shareholders, filed as an Exhibit hereto.
(c) Narrative Description of Business
---------------------------------
ELECTRIC OPERATIONS
-------------------
General
- -------
The Company derived 52% of its consolidated operating revenues from the
electric segment during 1997; 54% during 1996; and 62% during 1995. During
1997 the Company derived approximately 53.4% of its electric revenues from
Minnesota, 38.7% from North Dakota, and 7.9% 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, 34.4% of 1997 electric revenue was derived from
commercial customers, 32.2% from residential customers, 20.2% from industrial
customers, and 13.2% from other sources, including municipalities, farms and
power pools.
No customer accounted for more than 10% of electric revenues in 1997.
Power pool sales to other utilities, which accounted for 14.5% of total 1997
kwh sales, decreased from 15.3% in 1996. Activity in short-term energy sales
is subject to change based on a number of factors and the Company is unable to
predict the 1998 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 live in communities having
a population of more than 1,000, according to the 1990 census. The only
communities served which have a population in excess of 10,000 are Jamestown,
North Dakota (15,571); Fergus Falls, Minnesota (12,362); and Bemidji,
Minnesota (11,245). Since 1990 when the customer count was at a low of
121,277, the Company has experienced an increase in customers. By year end
1997 total customers had increased to 125,191. During 1997, the Company
experienced a net increase of 409 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
industry. The NEPA reduces restrictions on operation and ownership of
independent power producers ("IPPs"). It also allows IPPs and other wholesale
suppliers and purchasers increased access to transmission lines. The NEPA
prohibits retail wheeling ordered by the Federal Energy Regulatory Commission,
but it does not address the states' authority to order retail wheeling.
In 1996 the Federal Energy Regulatory Commission ("FERC") issued two
closely related final rules. FERC Order No. 888 opened wholesale power sales
to competition by requiring public utilities who own, control, or operate
transmission lines, to file nondiscriminatory proforma open access tariffs
that offer others the same transmission service they provide themselves.
FERC Order No. 889 requires utilities to post or make available information
about their transmission system for their own wholesale power transactions,
such as capacity availability, by the same means as their competitors would
via an Open Access Same-time Information System ("OASIS"), as well as
separate their wholesale marketing and transmission operation functions. In
1997 FERC issued Orders No. 888-A and -B which reaffirmed its basic
determinations in Order No. 888 and clarified certain terms. For the status
of other regulatory initiatives relating to competition, see "General
Regulation".
The Company is taking a number of steps to position itself for success in
a competitive marketplace. It has initiated the process of functionally
unbundling its energy supply, energy delivery, and energy services operations
by setting up distinct separate business units in each of these areas. The
Company is developing the necessary accounting systems to capture costs and
determine the profitability of each of these units and to identify areas for
improvement and opportunities for increased profitability. The Company has
established an energy services business unit to promote the energy related
products and services that have always been offered to its customers and to
develop new products and services to be offered to current and potential
customers in order to distinguish itself from the competition. Furthermore,
with the goal of alleviating state tax inequities in the electric industry,
the Company is working with other utilities to develop tax reform proposals
and testimony for a legislative committee developed to study competition.
As the electric industry evolves, the Company may also have opportunities
to increase its market share. The Company's generation capacity appears well
positioned for competition. A comparison of the Company's electric retail
rates to the rates of other investor-owned utilities, cooperatives, and
municipals in the states the Company serves indicates that the Company's rates
are competitive. In addition, the Company would attempt more flexible pricing
strategies under an open, competitive environment.
Capability and Demand
- ---------------------
At December 31, 1997, the Company had base load net plant capability
totaling 560,401 kw, consisting of 251,551 kw from the Big Stone Plant (the
Company's 53.9% share), 154,025 kw from the Hoot Lake Plant, 149,450 kw from
the Coyote Plant (the Company's 35% share), and under contract 5,375 kw from
the Potlatch Co-generation Plant near Bemidji, Minnesota. In addition to its
base load capability, the Company has combustion turbine and small diesel
units, used chiefly for peaking and standby purposes, with a total capability
of 91,208 kw, and 4,374 kw of hydroelectric capability. During 1997, the
Company generated about 69% 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. The Company also has agreements to purchase 60,000 kw of capacity
for the summers of 1998-1999 and 50,000 kw of year-round capacity which runs
through April 30, 2005. The Company also has a direct control load management
system which provides some flexibility to the Company to effect reductions of
peak load.
The Company is a member of the Mid-Continent Area Power Pool ("MAPP").
The objective of MAPP is to coordinate the planning and operation of generation
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 operating agreement for MAPP was restated in 1996 to open
membership to organizations outside the original Upper Midwest boundaries, to
establish a Regional Transmission Group ("RTG") and to add energy market
functions. RTGs, as proposed by the FERC, coordinate planning of transmission
grids on regional levels.
The Company traditionally experiences its peak system demand during the
winter season. For the calendar year 1997, the Company established a new
system peak demand of 635,529 kw on January 7, 1997. The highest previous
sixty-minute peak demand was 635,320 kw on November 26, 1996. Taking into
account additional capacity available to it in January 1997 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 774,610 kw. 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 1998 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. Coyote, a mine-mouth facility, burns
North Dakota lignite coal. 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 1997 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
------- ----------- ---------
Subbituminous Coal. . . . . . . . . . . . . . 2,167,219 73.8%
Lignite Coal. . . . . . . . . . . . . . . . . 733,276 25.0
Hydro . . . . . . . . . . . . . . . . . . . . 26,399 .9
Oil . . . . . . . . . . . . . . . . . . . . . 7,353 .3
--------- -----
Total . . . . . . . . . . . . . . . . . . . . 2,934,247 100.0%
========= ======
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 has purchase agreements for fixed quantities of
subbituminous coal with Kennecott Energy as needed for Hoot Lake Plant. The
lignite coal contract with Knife River Coal Mining Company for the Coyote Plant
expires in 2016, with a 15-year renewal option subject to certain
contingencies, and is expected to provide the plant's lignite coal requirements
during the term of the contract. Knife River Coal Mining Company is an
affiliate of Montana-Dakota Utilities Co., which is a co-owner of the Big Stone
and Coyote Plants.
In September 1996 three of the four co-owners of the Coyote generating
plant filed a Demand and Notice of Arbitration complaint against Knife River
Coal Mining Company and MDU Resources Group, Inc. The three co-owners contend
that the 14-year-old pricing mechanism outlined in the original coal supply
contract has been abandoned by all parties over the past 7 years and no longer
results in fair, equitable, and competitive prices for the lignite coal used to
generate electricity at the plant. The co-owners expect resolution of this
case in 1998.
It is the Company's practice to maintain minimum 30-day inventories (at
full output) of coal at Big Stone, a 20-day inventory at Coyote Plant, and a
10-day inventory at Hoot Lake Plant.
In November 1996, Big Stone Plant put new aluminum coal cars, leased by
the three plant owners, into service transporting coal to the plant. The
Company has a coal transportation agreement with Burlington Northern Railroad
for transportation services to the Big Stone Plant. This contract began in
1995 and runs through 1999. The aluminum coal cars and current coal and freight
agreements result in lower delivered coal prices at the Big Stone Plant which
is returned to the Company's retail customers through the Cost of Energy
Adjustment clause.
The Company has a subbituminous coal transportation agreement with
Northern Coal Transportation Company, effective January 1993, covering coal
moved from Kennecott Energy's Spring Creek mine to Hoot Lake Plant. That
agreement was renewed in January 1996 for an additional three years.
The average cost of coal consumed (including handling charges to the
plant sites) per million BTU for each of the three years 1997, 1996, and 1995,
was $.958, $.944, and $.969, respectively.
The Company is permitted by the State of South Dakota to burn some
alternative fuels, including tire and refuse derived fuel, at its Big Stone
Plant. The quantity of alternative fuel burned during 1997, 3.0% of total fuel
burned at Big Stone Plant, and expected to be burned in 1998, is insignificant
when compared to the total annual coal consumption at Big Stone Plant.
Rate Regulation
- ---------------
The Company is subject to electric rate regulation as follows:
Year Ended
December 31, 1997
-----------------
% of
Electric % of kwh
Rates Regulation Revenues Sales
- ------ ---------- -------- -------
MN retail sales MN Public Utilities
Commission 48.7% 45.9%
ND retail sales ND Public Service
Commission 38.0 33.0
SD retail sales SD Public Utilities
Commission 7.5 6.4
Transmission & sales FERC
for resale 5.8 14.7
---- ----
100.0% 100.0%
===== =====
The following table summarizes the electric rate proceedings with the
Minnesota Public Utilities Commission ("MPUC"), the South Dakota Public
Utilities Commissions ("SDPUC"), the North Dakota Public Service Commission
("NDPSC"), and FERC since January 1, 1993:
Increase
(Decrease) Granted
------------------
Commission Date Amount %
- ---------- ---- ------ -----
(Thousands)
Minnesota Last Proceeding was July 1, 1987
North Dakota
(1) September 22, 1993 ($ 449) (0.6%)
South Dakota Last Proceeding was November 1, 1987
FERC (2) March 25, 1997
(3) May 29, 1997
(1) An agreement for incentive regulation reached between the Company and the
NDPSC 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.
(2) On March 25, 1997, FERC issued an order approving a settlement agreement
in the Company's Open Access Transmission Tariff filing of July 9, 1996.
This settlement sets the rates the Company can charge under its Open
Access Transmission Tariff.
(3) On May 29, 1997, FERC issued an order approving a request for waiver of
the standards of conduct under Order 889.
In 1994 the Company filed a petition with the MPUC for approval of an
annual recovery mechanism for demand-side management related costs, under
Minnesota's Conservation Improvement Programs. An intervenor, on behalf of the
Large General Service Group, filed comments against the petition and requested
the 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 an annual cost of approximately $2,200,000
in 1995, 1996, and 1997, and $1,000,000 thereafter. In 1997 the MPUC approved
the Company's 1996 financial incentive filing along with a 1.75 percent
surcharge on all Minnesota customers' bills starting on July 1, 1997, for the
recovery of conservation-related costs over and above those being recovered in
current rates. The approved surcharge in effect from July 1, 1996, through
June 30, 1997, was 1.25 percent and the approved surcharge in effect from July
1, 1995, through June 30, 1996, was .5030 percent. The current surcharge rate
will be in place until June 30, 1998, when it will be revised for subsequent
years' program results.
Under Minnesota law, the MPUC 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 MPUC 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
MPUC, and rate base and expense items allowed by a currently effective MPUC
order. In addition, if the MPUC 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 MPUC on the last day of the extended period of suspension of
the rate increase, or (II) a settlement has been submitted to and rejected by
the MPUC, and the MPUC 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 NDPSC become effective 30 days after the
date of filing unless suspended by the NDPSC. Within seven months after the
date of suspension, the NDPSC must act on the request, and during the period of
consideration by the NDPSC a suspended rate can be implemented only with the
approval of the NDPSC.
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 SDPUC. The SDPUC 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 SDPUC finds that a
longer time is required, in which case the SDPUC 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 SDPUC has
made a determination concerning any previously filed rate change. In the event
that a requested rate change is suspended by the SDPUC, such requested rate
change can be implemented by the public utility six months after the date of
filing (unless previously authorized by the SDPUC), subject to refund with
interest.
The Company's wholesale power sales and transmission rates are subject to
the jurisdiction of the FERC 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 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 MPUC has
established by regulation a forward test year procedure. North Dakota law
allows a forward test year. The SDPUC 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.
General Regulation
- ------------------
Minnesota: Under the Minnesota Public Utilities Act, the Company is
subject to the jurisdiction of the 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 utilities serving at 10,000 customers, either directly or indirectly,
and having at least 100 megawatts of load. The MPUC's findings and orders with
respect to these submissions is binding for jurisdictional utilities. The
Company's most recent plan was submitted to the MPUC in 1996, and was approved
as submitted in its entirety. The MPUC granted the Company a one year waiver in
submitting the next plan, which is now due in 1999. 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.
North Dakota: The Company is subject to the jurisdiction of the NDPSC with
respect to rates, services, certain issuances of securities and other matters.
The North Dakota Energy Conversion and Transmission Facility Siting Act grants
the NDPSC 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 NDPSC annually.
South Dakota: The South Dakota Public Utilities Act subjects the Company
to the jurisdiction of the SDPUC 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 SDPUC 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.
FERC: The Company is also subject to regulation by the FERC, 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.
General: The United States Congress ended its 1997 legislative session
without taking action on proposed electric industry restructuring
legislation. Federal restructuring legislation in 1998, a Congressional
election year, is also unlikely due to the complexities of issues involved
with federal intervention.
The MPUC issued its Wholesale Competition Report in 1996 and its Retail
Competition Report in 1997 and continues to work on specific topics in the
areas of potential stranded costs, unbundled rates and affiliated
transactions. The Minnesota Legislature is not expected to adopt
deregulation legislation until 1999 at the earliest. In 1997 the North Dakota
Legislature created a subcommittee to investigate the impact of electric
utility industry restructuring on North Dakota. In view of the legislative
effort, the NDPSC closed its investigative docket. The SDPUC has not taken
any action with regards to industry restructuring or retail competition.
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, 1997, approximately $2,210,000 for environmental control facilities.
Included in the 1998-2002 construction budget are approximately $1,780,000
for environmental improvements for existing and new facilities, including
$440,000 for 1998.
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 are being imposed in two phases, the first
phase was imposed in 1995 and the second phase will be imposed 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 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 either by burning low sulfur
subbituminous coal or by the acquisition of SO2 allowances. The cost of
subbituminous coal in 2000 and beyond may be higher than the current market
price but would likely not adversely affect the Company's power plant
operations.
The national NOx emission reduction goals are to be achieved by imposing
mandatory emissions standards on individual sources. The NOx emissions
regulations that were issued by the EPA in 1995 apply to phase one boilers of
the same design as those used at the Company's Hoot Lake Plant units 2 and 3.
The Act allowed EPA to either retain the standard as it currently applies to
phase one boilers or adopt more stringent standards for such phase two
boilers by January 1, 1997. More stringent standards were adopted on
December 19, 1996. The Company had the option to either comply with the
phase one standards beginning on January 1, 1997, under EPA's early opt-in
provision, or comply with any revised standard for phase two units. The
Company elected the early opt-in provision for Hoot Lake Plant unit 2. The
unit is governed by the phase one standard until January 1, 2008. The Company
has not elected the early opt-in provision for Hoot Lake Plant unit 3. The
Company currently anticipates that the cost of complying with the limitations
applicable to Hoot Lake Plant unit 3 will not be material.
On December 19, 1996, the EPA also adopted NOx emissions regulations
that would be applicable to cyclone-fired boilers such as those used at Big
Stone and Coyote. The regulations require that the emission standard be
met by cyclone boilers beginning on January 1, 2000. The Utility Air
Regulatory Group ("UARG") filed a Petition for Review in the Court of Appeals
for the District of Columbia regarding the EPA adopted NOx emission
regulations. As a member of UARG, the Company participated in the Petition,
which was rejected by the Court of Appeals on February 13, 1998. The Company
is currently evaluating the Big Stone and Coyote NOx emissions with respect
to the December 19, 1996 rules. Existing emissions monitoring data indicate
that Coyote meets the emission requirements. During 1997, the Company
conducted tests at Big Stone to determine if emissions can be reduced through
modifications to existing equipment. The tests were successful and the
modifications will be completed at a nominal cost.
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 1997 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
3,514 kw at December 31, 1997).
Solid Waste: Permits for disposal of ash and other solid wastes have
been issued for the Company's Big Stone and Coyote Plants. A renewal permit
is pending for the Company's Hoot Lake Plant and the Company anticipates that
it will obtain this renewal in due course. The EPA has promulgated various
solid and hazardous waste regulations and guidelines pursuant to, among other
laws, the Resource Conservation and Recovery Act of 1976, the Solid Waste
Disposal Act Amendments of 1980, and the Hazardous and Solid Waste Amendments
of 1984, which provide for, among other things, the comprehensive control of
various solid and hazardous wastes from their generation to final disposal.
The states of Minnesota, North Dakota and South Dakota have also adopted
rules and regulations pertaining to solid and hazardous waste. The total
impact on the Company of the various solid and hazardous waste statutes and
regulations enacted by the Federal Government or the states of Minnesota,
North Dakota and South Dakota is not certain at this time. To date the
Company has incurred no significant costs as a result of these laws.
In 1980 the United States enacted the Comprehensive Environmental
Response, Compensation and Liability Act, commonly known as the Federal
Superfund law, and in 1986 reauthorized and amended the 1980 Act. In 1983
Minnesota adopted the Minnesota Environmental Response and Liability Act,
commonly known as the Minnesota Superfund law. In 1988 South Dakota enacted
the Regulated Substance Discharges Act, commonly called the South Dakota
Superfund law. In 1989 North Dakota enacted the Environmental Emergency Cost
Recovery Act. Among other requirements the federal and state acts establish
environmental response funds to pay for remedial actions associated with the
release or threatened release of certain regulated substances into the
environment. These federal and state Superfund laws also establish liability
for cleanup costs and damage to the environment resulting from such release
or threatened release of regulated substances. The Minnesota Superfund law
also creates liability for personal injury and economic loss under certain
circumstances. The Company is unable to determine the total impact of the
Superfund laws on its operations at this time but has not incurred any
significant costs to date related to these laws.
The Federal Toxic Substances Control Act of 1976 regulates, among other
things, polychlorinated byphenyls ("PCBs"). The EPA has enacted regulations
concerning the use, storage and disposal of PCBs. The Company completed a
program for removal of all PCB-filled transformers and capacitors by the end
of 1987 and received Certificates of Disposal in 1989. The Company completed
removal of PCB-contaminated mineral oil dielectric fluid from all substation
transformers in 1991 and continues to remove such oil from voltage regulators
as well as other electrical equipment.
Health Effects of Electric and Magnetic Fields ("EMF"): In 1996 the
National Research Council of the National Academy of Sciences, after
evaluating more than 500 studies on the effects of EMF, found insufficient
evidence to consider electric and magnetic fields a threat to human health.
Although research conducted to date has found no conclusive evidence that
electric and magnetic fields affect health, a few studies have suggested a
possible connection with cancer. The utility industry continues to fund
studies. The ultimate impact, if any, of this issue on the Company and the
utility industry is impossible to predict.
Capital Expenditures
- --------------------
The Company is continually expanding, replacing and improving its
electric utility facilities. During 1997 the Company invested approximately
$26,489,000 for additions to its electric utility properties. During the
five years ended December 31, 1997, the Company had gross electric property
additions, including construction work in progress, of approximately
$141,769,000 and gross retirements of approximately $39,862,000.
The Company estimates that during the five years 1998 through 2002 it
will invest for electric utility construction approximately $117,000,000.
The Company continuously reviews options for increasing its generating
capacity, but at this time has no firm plans for additional base load
generating plant construction. The majority of electric utility expenditures
for the five-year period 1998 through 2002 will be for work related to the
Company's transmission and distribution system.
Franchises
- ----------
At December 31, 1997, the Company had franchises in all but one 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.
MANUFACTURING OPERATIONS
------------------------
General
- -------
Manufacturing Operations consists of businesses involved in the
following manufacturing activities: PVC pipe, sugar beet processing
equipment, metal stamping, contract machining, and frame straightening racks
and accessories used by the auto body industry. Initial acquisitions of
businesses in this segment were made in 1990. On June 30, 1997, Mid-States
acquired Chassis Liner in a pooling-of-interests transaction. The Company
derived 21% of its consolidated operating revenues from this segment in 1997,
17% in 1996, and 12% in 1995.
The following is a brief description of each of these businesses:
Precision Machine of North Dakota, Inc., located in West Fargo, ND, uses
computer controlled lathes and milling machines to produce precision
parts for manufacturers.
Dakota Machine, Inc., located in West Fargo, ND, is primarily engaged in
metal fabrication of large equipment that handles or processes sugar
beets. Dakota Engineering, Inc., a subsidiary of Dakota Machine, Inc.,
was formed in 1995 and is engaged in design engineering and construction
management, primarily in the sugar industry.
Glendale Machining, Inc., located in Pelican Rapids, MN, uses computer
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
primarily for the snowmobile/recreation vehicle industry.
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.
Chassis Liner Corporation, located in Alexandria and Lucan, MN,
manufactures vehicle frame-straightening equipment and accessories used
by the auto body industry.
Competition
- -----------
The markets in which the Company's manufacturing entities compete are
characterized by intense competition. The various markets the companies
compete in have many established manufacturers with broader product lines,
greater distribution capabilities, greater capital resources and larger
marketing, research and development staffs and facilities than the Company.
The Company believes the principal competitive factors in its
manufacturing segment are product performance, quality, price, ease of use,
technical innovation, cost effectiveness, customer service and breadth of
product line. The Company intends to continue to compete on the basis of its
high performance products, innovative technologies, cost effective
manufacturing techniques, close customer relations and support and its
strategy to increase offerings of products.
Capital Expenditures
- --------------------
During 1997 capital expenditures of approximately $6,300,000 were made
in Manufacturing Operations, Plant and Equipment. Total capital expenditures
for Manufacturing Operations during the five-year period 1998-2002 are
estimated to be approximately $13,000,000.
HEALTH SERVICES OPERATIONS
--------------------------
General
- -------
Health Services Operations consists of businesses involved in the sale,
service, rental, refurbishing and operation of medical imaging equipment and
the sale of related supplies and accessories to various medical institutions
primarily in the Midwest United States. The Company derived 17% of its
consolidated operating revenues from this segment in 1997, 17% in 1996, and
16% in 1995.
Subsidiaries comprising Health Services Operations include the
following:
Diagnostic Medical Systems, Inc. ("DMS"), located in Fargo, ND, sells,
services and refurbishes diagnostic medical imaging equipment
manufactured primarily by Philips Medical Systems ("Philips"), including
fluoroscopic, radiographic and mammography equipment, along with
ultrasound, computerized tomography ("CT") scanners, magnetic resonance
imaging ("MRI") scanners, cardiac cath labs, and radiation therapy
equipment for the treatment of cancer. DMS is also a distributor of x-
rays supplies and accessories to health care facilities. DMS
subsidiaries are DMS Imaging, Inc. and DMS Leasing, Inc. In 1994 DMS
entered into a five-year dealer agreement with Philips, which can be
terminated by Philips upon certain circumstances. DMS is also a
supplier for Kodak, DuPont, Imation, 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 Imaging, Inc., a subsidiary of DMS located in Fargo, ND and Bemidji
MN, provides mobile and fixed diagnostic medical equipment and related
services to health care providers in a nineteen state area, including
diagnostic nuclear medicine, ultrasound, mammography, computerized axial
tomography, and magnetic resonance imaging. Northern Medical Imaging,
Inc., acquired in April 1996 and Imaging Plus, Inc. were combined in
January 1997 to form DMS Imaging, Inc.
Combined, the Health Service subsidiaries cover the three basics of the
medical imaging industry: (1) operating technologists who do the imaging of
patients of hospitals and clinics; (2) the equipment function that sells,
owns, rents, refurbishes and maintains the imaging machines; and (3) central
office specialists who provide scheduling, billing and administrative
support.
Each of the subsidiaries described above under Health Services
Operations and Manufacturing Operations are owned by Mid-States, which is a
wholly owned subsidiary of Minnesota Dakota Generating Company ("MDG"). MDG
is a wholly owned subsidiary of the Company.
Competition
- -----------
The market for selling, servicing and operating diagnostic imaging services
and imaging systems is highly competitive. In addition to direct competition
from other contract providers, the Company competes with free-standing
imaging centers and health care providers that have their own diagnostic
imaging systems and with equipment manufacturers that sell imaging equipment
to health care providers for full-time installation. Some of the Company's
direct competitors which provide contract MRI services have access to greater
financial resources than the Company. In addition, some of the Company's
customers are capable of providing the same services to their patients
directly, subject only to their decision to acquire a high-cost diagnostic
imaging system, assume the financial and technology risk, and employ the
necessary technologies. The Company competes against other contract
providers on the basis of quality of services, quality and magnetic field
strength of imaging systems, price, availability and reliability.
Capital Expenditures
- --------------------
During 1997 capital expenditures of approximately $3,800,000 were made
in Health Services. Total capital expenditures during the five-year period
1998-2002 are estimated to be $34,000,000.
OTHER BUSINESS OPERATIONS
-------------------------
General
- -------
The Company's Other Business Operations consists of businesses that are
diversified in such areas as electrical and telephone construction
contracting, radio broadcasting, waste incinerating, and telephone/cable TV
utility. On January 2, 1997, NCU acquired Peoples in a pooling-of-interests
transaction. The Company derived 10% of its consolidated operating revenues
from these diversified businesses during 1997, 12% in 1996, and 10% during
1995.
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, installs overhead
and underground utility lines.
KFGO, Inc., located in Fargo, ND, operates two AM and four FM commercial
radio stations along with a video production facility.
Western Minnesota Broadcasting Company, located in Morris, MN, operates
an AM and FM commercial radio station.
Quadrant Co. ("Quadrant") operates a municipal waste burning facility
located in Perham, MN. In 1997 Quadrant began processing solid waste
for three Minnesota counties under the terms of a new waste incineration
agreement. Since operating under the new agreement, Quadrant has
experienced a reduction in revenue of approximately fifty percent, as
compared to 1996. New pollution rules for Minnesota waste incinerators
have been issued. The costs to be in compliance with the new pollution
rules by the year 2000 in conjunction with reduced operating revenues
threaten the economic viability of the plant. However, Quadrant is
currently generating positive cash flows from the operation of its plant
which had a net undepreciated book value of approximately $2.45 million
on December 31, 1997. The Company intends to operate the Quadrant plant
as long as positive cash flows can be maintained but will continue to
evaluate its investment in Quadrant for asset impairment on a quarterly
basis.
Midwest Information Systems, Inc.("MIS"), headquartered in Parkers
Prairie, MN, owns three operating telephone companies serving over 6,300
customers and two cable television companies serving approximately 1,200
customers. MIS is also involved in long-distance telephone, 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 NCU, a
subsidiary of MDG formed for the purpose of acquiring utility companies.
Each of the other subsidiaries described above are owned by Mid-States, which
is also a wholly owned subsidiary of MDG.
General Regulation
- ------------------
The Company's operating telephone subsidiaries are subject to the
regulatory authority of the MPUC regarding rates and charges for telephone
services, as well as other matters. The operating telephone subsidiaries
must keep on file with the DPS schedules of such rates and charges, and any
requests for changes in such rates and charges must be filed for approval by
the MPUC. The telephone industry is also subject generally to rules and
regulations of the Federal Communications Commission ("FCC"). The Company's
operating cable television subsidiary is regulated by federal and local
authorities. The Company's radio broadcasting subsidiaries are regulated by
the FCC.
Environmental Regulation
- ------------------------
In recent years, facilities such as Quadrant that burn municipal solid
waste have been subjected to increasing state and federal environmental
regulation. The Minnesota Pollution Control Agency promulgated rules
relating to ash in 1993 and air emissions in 1994. In late 1996, the U.S.
Court of Appeals for the District of Columbia Circuit vacated air emission
regulations recently adopted by the EPA. EPA has petitioned for a rehearing
of the case. Quadrant continues to operate under an expired air emission
permit with the permission of the Minnesota Pollution Control Agency and
submitted its application for a new air emission permit in April of 1995.
Historically the terms of Quadrant's contracts with customers have enabled
Quadrant to pass on to its customers much of the cost of environmental
compliance. The increasing cost of environmental compliance may adversely
affect Quadrant's ability to successfully negotiate the renewal of the
contracts discussed above.
Competition
- -----------
Each of the businesses in Other Business Operations is subject to
competition, as well as the effects of general economic conditions, in their
respective industries.
Capital Expenditures
- --------------------
During 1997 capital expenditures of approximately $3,000,000 were made
in Other Business Operations. Capital expenditures during the five-year
period 1998-2002 are estimated to be approximately $9,000,000 for Other
Business Operations.
FINANCING
---------
The Company estimates that funds internally generated net of forecasted
dividend payments, 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 its estimated 1998-2002 consolidated capital expenditures.
Additional short-term or long-term financing will be required in the period
1998-2002 for the maturity of First Mortgage Bonds and other long-term debt,
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, 1997, the Company had unutilized net fundable
property available for the issuance of more than $39,000,000 principal amount
of additional First Mortgage Bonds and also was entitled to issue in excess
of $131,000,000 principal amount of additional First Mortgage Bonds on the
basis of First Mortgage Bonds theretofore retired.
The Company's operating subsidiaries have been responsible for obtaining
their own financing after the Company's initial equity investment and have
developed financing arrangements with various banks. Historically, the
Company has not made or guaranteed loans to its subsidiaries, loaned any
subsidiary money or cosigned on any of their borrowing.
The Company has access to short-term borrowing resources. As of December
31, 1997, the Company and subsidiaries had unused credit lines totaling
$52,285,000. The Company had $2,100,000 in short-term borrowings as of
December 31, 1997. The subsidiary companies had $3,115,000 of credit lines
in use at December 31, 1997, 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 1,884 full-time
employees at December 31, 1997. A total of 484 employees are represented by
local unions of the International Brotherhood of Electrical Workers, of which
412 are employees of the Electric Operations segment and are covered by a
three-year labor contract that was renewed in 1996 and expires November 1,
1999. The Company has never experienced any strike, work stoppage, or strike
vote, and regards its present relations with employees as very good.
Forward Looking Information - Safe Harbor Statement Under the Private
Securities Litigation Reform Act of 1995
In connection with the "safe harbor" provisions of the Private
Securities Litigation Reform Act of 1995 (the "Act"), the Company has filed
cautionary statements identifying important factors that could cause the
Company's actual results to differ materially from those discussed in
forward-looking statements made by or on behalf of the Company. When used in
this Form 10-K and in future filings by the Company with the Securities and
Exchange Commission, in the Company's press releases and in oral statements,
words such as "may", "will", "expect", "anticipate", "continue", "estimate",
"project", "believes" or similar expressions are intended to identify
forward-looking statements within the meaning of the Act. Factors that might
cause such differences include, but are not limited to, the factors discussed
under "Factors affecting future earnings" on pages 28 through 30 of the
Company's 1997 Annual Report to Shareholders, filed as an exhibit hereto.
These factors are in addition to any other cautionary statements, written or
oral, which may be made or referred to in connection with any such forward-
looking statement or contained in any subsequent filings by the Company with
the Securities and Exchange Commission.
Item 2. PROPERTIES
----------
The Coyote Plant, 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, 1997, 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; 633 miles of 115 kv lines; and
4,120 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. All of
the common shares of the companies owned by Mid-States are pledged to secure
indebtedness of Mid-States.
Item 3. LEGAL PROCEEDINGS
-----------------
Patricia C. Reimel v, John C. MacFarlane, et al, and Otter Tail Power Company
This suit was filed on July 1, 1997, in United States District Court for
the District of Minnesota by Pactricia C. Reimel, individually and
derivatively as a shareholder of the Company. The suit names as defendants
the Company, each member of the Company's Board of Directors and certain
executive officers of the Company. The allegations made by the plaintiff
relate to the Company's Shareholder Rights Plan, which was adopted by the
Company's Board of Directors in January 1997. Claims for relief include
modification or elimination of the Company's Shareholder Rights Plan, as well
as damages in an unspecified amount. The Company believes the suit is
procedurally inappropriate and has requested that the Court dismiss the suit
because the plaintiff failed to make a demand on the Board of Directors of
the Company prior to seeking to resolve the alleged claims through
litigation.
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, 1997.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 1998)
----------------------------------------------------------
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 (58) 4/8/91 Present: Chairman, President and Chief
Executive Officer
Andrew E. Anderson (58) 4/08/96 Present: Vice President, Finance and
Treasurer
4/10/95 Vice President, Finance
Prior to
4/10/95 Controller
Marlowe E. Johnson (53) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Prior to
4/12/93 Division Manager, Jamestown
Douglas L. Kjellerup (56) 4/12/93 Present: Vice President, Marketing and
Development
Prior to
4/12/93 Vice President, Planning and
Development
LeRoy S. Larson (52) 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 (59) 4/8/96 Present: Senior Vice President,
Corporate Services
Prior to
4/8/96 Vice President, Corporate Services
Jay D. Myster (59) 4/8/96 Present: Senior Vice President,
Governmental and Legal, and
Corporate Secretary
Prior to
4/8/96 Vice President, Governmental and Legal,
and Corporate Secretary
Rodney C.H. Scheel (48) 4/10/95 Present: Vice President, Electrical
Prior to
4/10/95 Director, Information Services
Ward L. Uggerud (48) 4/10/89 Present: Vice President, Operations
Jeffrey J. Legge (41) 4/10/95 Present: Controller
Prior to
4/10/95 Manager, Tax Department
The term of office of each of the officers is one year, and there are no
arrangements or understanding between individual officers or any other
persons pursuant to which he was selected as an officer.
No family relationships exist between any officers of the Company.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
-----------------------------------------------------------------
MATTERS
-------
The information required by this Item is incorporated by reference to
the first sentence under "Otter Tail Power Company Stock listing" on Page 48,
to "Selected consolidated financial data" on Page 21 and to "Quarterly
information" on Page 45, of the Company's 1997 Annual Report to Shareholders,
filed as an Exhibit hereto.
In the January 2, 1997, acquisition of Peoples, a Company subsidiary
exchanged 163,758 newly issued shares of the Company's common stock and
$209,000 in cash for all of the outstanding stock of Peoples. In the June
30, 1997, acquisition of Chassis Liner a Company subsidiary exchanged 157,646
newly issued shares of the Company's common stock for all of the outstanding
common stock of Chassis Liner. The issuance of shares of common stock for
both acquisitions did not involve a public offering and therefore was exempt
from registration pursuant to Section 4(2) of the Securities Act of 1933, as
amended (the "Act"). On January 8, 1997, the Company issued 2,630 shares of
its common stock as a bonus to a consultant. The issuance of such shares did
not constitute a "sale" within the meaning of Section 2(3) of the Act.
Item 6. SELECTED FINANCIAL DATA
-----------------------
The information required by this Item is incorporated by reference to
"Selected consolidated financial data" on Page 21 of the Company's 1997
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 22 through 30 of the Company's 1997 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 31 through 44 of the Company's 1997 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 13, 1998. 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 13, 1998.
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 13, 1998.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
----------------------------------------------
None.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
---------------------------------------------------------------
(a) List of documents filed:
(1) and (2) See Table of Contents on Page 22 hereof.
(3) See Exhibit Index on Pages 23 through 29 hereof.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of
certain instruments defining the rights of holders of certain
long-term debt of the Company are not filed, and in lieu
thereof, the Company agrees to furnish copies thereof to the
Securities and Exchange Commission upon request.
(b) Reports on Form 8-K:
The Company's Current Report on Form 8-K filed with the Securities
and Exchange Commission on November 20, 1997, regarding the
Company's issuance of $50,000,000 aggregate principal amount of its
Senior Debentures, 6.375% Series due 2007.
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 and
Treasurer
Dated: March 26, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature and Title
- -------------------
John C. MacFarlane )
Chairman, President and )
Chief Executive Officer )
(principal executive officer) )
and Director )
)
A. E. Anderson )
Vice President, Finance and Treasurer )
(principal financial officer) )
)
Jeffrey J. Legge )
Controller ) By /s/A. E. Anderson
(principal accounting officer) ) A. E. Anderson
) Pro Se and Attorney-in-Fact
) Dated March 26, 1998
Thomas M. Brown, Director )
)
Dayle Dietz, Director )
)
Dennis R. Emmen, Director )
)
Maynard D. Helgaas, Director )
)
Arvid R. Liebe, Director )
)
Kenneth L. Nelson, Director )
)
Nathan I. Partain, Director )
)
Robert N. Spolum, Director )
OTTER TAIL POWER COMPANY
TABLE OF CONTENTS
-----------------
FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL
SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED
DECEMBER 31, 1997
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,
1997:
Page in
Annual
Report to
Shareholders
------------
Financial Statements:
Independent Auditors' Report.............................................33
Consolidated Balance Sheets, December 31, 1997 and 1996.............32 & 33
Consolidated Statements of Income for the Three Years
Ended December 31, 1997..................................................31
Consolidated Statements of Changes in Equity for the
Three Years Ended December 31, 1997......................................34
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1997..................................................35
Consolidated Statements of Capitalization, December 31, 1997
and 1996.................................................................36
Notes to Consolidated Financial Statements............................37-45
Selected Consolidated Financial Data for the Five Years
Ended December 31, 1997..................................................21
Quarterly Data for the Two Years Ended
December 31, 1997........................................................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, 1997
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
3-A 10-K for year 3-A --Restated Articles of
ended 12/31/96 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-7 --Thirty-Second Supplemental
Indenture dated as of
January 18, 1974.
4-D-4 33-46070 4-D-12 --Forty-Third Supplemental
Indenture dated as of
February 1, 1991.
4-D-5 33-46070 4-D-13 --Forty-Fourth Supplemental
Indenture dated as of
September 1, 1991
4-D-6 8-K dated 4-D-15 --Forty-Fifth Supplemental
7/24/92 Indenture dated as of
July 1, 1992
4-D-7 8-A dated 1 --Rights Agreement, dated as of
1/28/97 January 28, 1997, between the
Company and Norwest Bank Minnesota,
National Association
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
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.
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
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).
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-G-1 10-Q for quarter 10-B --Big Stone Coal Transp.
ended 9/30/94 Agreement by and between the
Company, Montana-Dakota
Utilities, Northwestern Public
Service Co., and Burlington
Northern Railroad Company
(dated as of July 18, 1994).
10-G-2 10-K for year 10-G-2 --Amendment No. 1, dated as of
ended 12/31/95 December 27, 1995, to Big
Stone Coal Transportation
Agreement (dated as of
July 18, 1994).
10-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.
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
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-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.
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-K-4 10-K for year 10-K-6 --Interchange Agreement by and
ended 12/31/92 between the Company and
Wisconsin Electric Power Co.
dated as of June 26, 1992.
10-K-5 10-Q for quarter 19-B --Interchange Agreement by and
ended 6/30/93 between the Company and
Wisconsin Public Service
Corp dated as of January
20, 1993.
10-L 10-K for year 10-L --Integrated Transmission
ended 12/31/91 Agreement by and between the
Company, Missouri Basin
Municipal Power Agency and
Western Minnesota Municipal
Power Agency (dated as of
March 31, 1986).
10-L-1 10-K for Year 10-L-1 --Amendment No. 1, dated as
ended 12/31/88 of December 28, 1988, to
Integrated Transmission
Agreement (dated as of
March 31, 1986).
10-M-1 10-K for year 10-M-1 --Hoot Lake Plant Coal
ended 12/31/89 Agreement dated as of
October 1, 1980, by and
between the Company and
Knife River Coal Mining
Company.
10-M-2 10-K for year 10-M-2 --First Amendment dated as of
ended 12/31/89 August 14, 1985, to Hoot
Lake Plant Coal Agreement.
10-M-3 10-K for year 10-M-10 --Hoot Lake Coal Transp.
ended 12/31/92 Agreement dated January 15,
1993 by and between the
Company and Northern Coal
Transportation Co.
10-M-4 10-Q for quarter 19-C --First Amendment dated as of
ended 6/30/93 January 20, 1993 to Hoot Lake
Coal Transportation Agreement
dated January 15, 1993.
10-M-5 10-K for year 10-M-5 --Second Amendment dated as of
ended 12/31/96 May 21, 1996 to Hoot Lake
Coal Transportation Agreement
dated January 15, 1993.
10-N-1 10-K for year 10-N --Deferred Compensation Plan
ended 12/31/91 for Directors, dated
April 9, 1984.*
10-N-2 10-K for year 10-N-2 --Executive Survivor and Sup-
ended 12/31/94 plemental Retirement Plan,
as amended.*
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
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 1997 Annual
Report to Shareholders
incorporated by reference
in this Form 10-K.
21-A --Subsidiaries of Registrant
23 --Consent of Deloitte & Touche LLP
24-A --Powers of Attorney.
27 --Financial Data Schedule.
27-1 --Restated Financial Data Schedules.
Restated Financial Data Schedules for 1996 interim and year end
consolidated financial statements. Exhibit 27.1 contains restated
summary financial information extracted from the restated consolidated
financial statements for the affected periods.
27-2 --Restated Financial Data Schedule
Restated Financial Data Schedules for 1997 interim consolidated
financial statements. Exhibit 27.2 contains restated
summary financial information extracted from the restated consolidated
financial statements for the affected periods.
- --------
* Management contract or compensatory plan or arrangement required to be filed
pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.
<TABLE>
Exhibit 13-A
Selected consolidated financial data
- ----------------------------------------------------------------------------------------------------------
1997 1996(1) 1995 1994 1993 1992 1987
-------- -------- -------- -------- -------- -------- --------
(thousands except per-share data)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues
Electric
Residential $ 66,102 $ 66,295 $ 64,355 $ 62,687 $ 62,167 $ 59,038 $ 60,339
Commercial and farms 74,520 74,355 71,487 69,060 66,286 63,257 62,271
Industrial 41,323 37,453 37,952 38,354 36,442 35,607 30,898
Sales for resale 11,117 10,238 19,110 19,066 18,107 11,126 9,066
Other electric 12,059 11,004 11,021 9,645 9,288 8,077 7,705
-------- -------- -------- -------- -------- -------- --------
Total electric $205,121 $199,345 $203,925 $198,812 $192,290 $177,105 $170,279
Manufacturing 81,543 64,568 38,690 13,083 8,473 -- --
Health services 66,185 61,697 50,896 45,555 32,068 -- --
Other business operations 41,430 45,323 32,818 29,276 32,396 32,433 --
-------- -------- -------- -------- -------- -------- --------
Total operating revenues $394,279 $370,933 $326,329 $286,726 $265,227 $209,538 $170,279
Net income $ 32,346 $ 30,624 $ 28,945 $ 28,475 $ 27,369 $ 26,538 $ 21,566
Cash flow from operations $ 69,398 $ 68,611 $ 58,077 $ 51,832 $ 53,255 $ 44,866 N/A
Total assets $655,441 $669,704 $609,196 $578,972 $563,905 $530,456 $463,504
Long-term debt $189,973 $163,176 $168,261 $162,196 $166,563 $159,295 $124,485
Redeemable preferred $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 17,035
Common shares outstanding
(2) (thousands) 11,731 11,536 11,180 11,180 11,180 11,180 11,968
Number of common
shareholders (3) 13,753 13,829 13,933 14,115 13,634 13,812 14,305
Basic and diluted
earnings per share (4) $ 2.58 $ 2.46 $ 2.38 $ 2.34 $ 2.23 $ 2.17 $ 1.60
Dividends per common share $ 1.86 $ 1.80 $ 1.76 $ 1.72 $ 1.68 $ 1.64 $ 1.46
- ----------------------------------------------------------------------------------------------------------
Notes:
(1) Restated to reflect the effects of two 1997 acqusitions accounted for under the pooling of interests
method. The impact of the poolings on years prior to 1996 is not material.
(2) Number of shares outstanding at year-end.
(3) Holders of record at year-end.
(4) 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 strong 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. Historically,
the Company's liquidity has been a function of its capital expenditures and
debt service requirements, its net internal funds generation and its access
to long-term securities markets and credit facilities for external capital.
Over the years the Company has achieved a high degree of long-term
liquidity by maintaining desired capitalization ratios through timely stock
and debt issuances or repurchases, maintaining strong bond ratings,
implementing cost-containment programs, evaluating operations and projects
on a cost-benefit approach, investing in projects that enhance shareholder
value, and implementing sound tax reduction strategies.
Cash provided by operating activities of $69,398,000 as shown on the
Consolidated Statement of Cash Flows for the year ended December 31, 1997,
combined with funds on hand of $2,130,000 at December 31, 1996, allowed the
Company to pay dividends, meet sinking fund payment requirements on its
outstanding First Mortgage Bonds and finance its consolidated capital
expenditures in 1997.
In November 1997 the Company sold $50 million of Senior Debentures, 6.375%
Series Due 2007, at 98.581 percent of their face value. The net proceeds
from the sale were used to repay $20 million in short-term debt outstanding
at the time of the sale and to repay or retire early three outstanding
series of the Company's First Mortgage Bonds (8.75% Series of 1997, 7.625%
Series of 2003, and 8.125% Coyote Project Series B of 2009) at the
aggregate redemption price of $29 million. The Senior Debentures, which
mature on December 1, 2007, are unsecured obligations of the Company and
rank on a parity with all other unsecured and unsubordinated debt of the
Company.
In 1997 the Company issued 161,831 common shares under its Automatic
Dividend Reinvestment and Share Purchase Plan, and 30,561 common shares to
its leveraged employee stock ownership plan generating proceeds of $6.4
million. The proceeds were used to reduce short-term debt. Also in 1997,
the Company issued 321,404 unregistered common shares to effect two
acquisitions accounted for under the pooling of interests method. (See
notes 2 and 4 to financial statements for more information.)
In November 1997 the Company's subsidiary, Mid-States Development, Inc.
(Mid-States), borrowed $22.5 million under a term note for 10 years with a
fixed interest rate of 7.8 percent. The proceeds were loaned to various
subsidiaries of Mid-States to be used to repay certain variable and fixed-
rate debt. Mid-States also secured a new line of credit of $17.5 million
which it is using to finance its subsidiaries' working capital needs;
interest on the credit line borrowings will be based on LIBOR plus 1.75
percent% (7.6 percent at December 31, 1997). The note and credit line
borrowings are secured by a pledge of all of the common stock of the
companies owned by Mid-States.
Also in November 1997 Mid-States' medical imaging services subsidiary
entered into a sale/leaseback transaction whereby $16 million of diagnostic
medical equipment was sold for net book value and leased back under two
operating leases. Certain proceeds from the sale were used to repay loans
collateralized by the equipment sold. This transaction reduced the level of
fixed assets and debt on the subsidiary's balance sheet.
The Company estimates that funds internally generated net of forecasted
dividend payments, 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 its estimated 1998-2002 consolidated capital
expenditures.
Additional short-term or long-term financing will be required in the period
1998-2002 for the maturity of First Mortgage Bonds and other long-term debt
and 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.
Capital Requirements:
The Company's consolidated capital requirements
include periodic and timely replacement of technically obsolete or worn out
equipment, new equipment purchases, and plant upgrades to accommodate
anticipated growth. The electric segment has a construction and capital
investment program to provide facilities necessary to meet forecasted
customer demands and provide reliable service. The construction program is
subject to continuing review and is revised annually in light of changes in
demands for energy, environmental laws, technology, the costs of labor,
materials and equipment, and the Company's financial condition (including
cash flow and earnings).
Capital expenditures for the years 1997, 1996, and 1995 were $42 million,
$65 million, and $37 million, respectively. An initiative by the Company
to reduce capital expenditures, in part as a response to the changing
regulatory environment, is reflected in the decreased level of expenditures
in 1997, as compared to 1996. Actual 1996 cash expenditures in excess of
1995 actual expenditures reflect: 1) reductions in capital related payables
at year-end 1996, compared to year-end 1995, at the electric utility, 2) $8
million in diagnostic medical equipment purchases by the health services
subsidiary acquired in April 1996, 3) accelerated replacement of equipment
at another of the Company's health services subsidiaries, 4) the purchase
and expansion of a building formerly being leased by a manufacturing
subsidiary, and 5) the purchase of a building by the Company's radio
broadcasting subsidiary.
The estimated capital expenditures for 1998 are $37 million and the total
expenditures for the five-year period 1998-2002 are expected to be
approximately $173 million. The breakdown of 1997 actual and 1998-2002
estimated capital project expenditures by segment is as follows:
1997 1998 1998-2002
---- ---- ---------
(in millions)
Electric utility $ 27 $ 22 $117
Manufacturing 6 3 13
Health services 4 10 34
Other business operations 5 2 9
---- ---- ----
Total $ 42 $ 37 $173
In addition to these capital requirements, funds totaling approximately
$55,288,000 will be needed during the five-year period 1998 through 2002 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 in excess of the minimum levels required for
issuance of securities, strong credit ratings, the pledging of assets owned
by the Company, and alternative financing arrangements such as leasing.
On August 30, 1996, the Company filed a shelf registration statement with
the Securities and Exchange Commission for the issuance of up to 1,000,000
common shares pursuant to the Company's Automatic Dividend Reinvestment and
Share Purchase Plan (the Plan), which permits shares purchased by
shareholders, employees, or customers who participate in the Plan to be
either new issue common shares or common shares purchased on the open
market. The Company estimates that it will raise approximately $5.3
million in capital through the issuance of common shares to fulfill the
requirements of the Plan in 1998. Proceeds from newly issued common shares
will be used for general corporate purposes.
As of December 31, 1997, the Company had $5.3 million in cash and cash
equivalents and $52.3 million in unused lines of credit available to meet
interim financing of working capital and other capital requirements, if
needed. The Company had $2.1 million in short-term borrowings outstanding
as of December 31, 1997. The subsidiary companies had $3.1 million of
credit lines in use at December 31, 1997, classified as current maturities
and long-term debt. (See note 9 to financial statements for further
information.)
The Company's coverage ratios remained stable in 1997 compared to 1996.
The fixed charge coverage ratio after taxes was 3.0 for both 1997 and 1996
and the long-term debt interest coverage ratio before taxes was 4.0 for
1997, as compared to 3.9 for 1996. The Company expects these coverages to
increase in 1998 as a result of decreasing its overall level of debt and
securing lower fixed rate financing in the fourth quarter of 1997.
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-
In 1997 Moody's Investors Service reaffirmed its Aa3 rating and Duff and
Phelps reaffirmed its AA rating, while Fitch Investors Service downgraded
its rating from AA to AA-. Standard and Poor's reaffirmed its AA- rating
but revised its ratings outlook on the Company from stable to negative
sighting growth in the level of nonutility earnings relative to overall
Company earnings as a reason for the revision. 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, 1997, the Company had the capacity under its Indenture
of Mortgage to issue an additional $171 million principal amount of First
Mortgage Bonds. (See note 7 to financial statements for further
information.)
Results of operations:
Electric operations
- -------------------
(bar graph of information in following table)
Electric operating income
(millions)
-------------------------
1995 $47.9
1996 $45.3
1997 $45.0
(end of graph)
Otter Tail Power Company provides electrical service to nearly 125,000
customers in a service territory of over 50,000 square miles.
1997 1996 1995
-------- -------- --------
(in thousands)
Operating revenues $205,121 $199,345 $203,925
Production fuel 31,362 27,913 31,559
Purchased power 24,420 28,378 30,591
Other operation and maintenance expenses 72,112 66,401 63,777
Depreciation and amortization 21,442 19,880 19,448
Property taxes 10,819 11,494 10,634
-------- -------- --------
Operating income $ 44,966 $ 45,279 $ 47,916
The 2.9 percent increase in electric operating revenues in 1997, as
compared to 1996, reflects increases of 1.0 percent in revenue from retail
kwh sales, 56.5 percent in other electric revenue, and 8.6 percent in
revenue from power pool sales. The increase in retail revenue is mainly due
to increases in kwh sales to industrial customers and increases in cost-of-
energy revenue related to power purchased for sale to retail customers in
the first half of 1997. The increase in other electric revenue reflects the
recognition of Minnesota Conservation Improvement Program (CIP) lost
margins recovery approved by the Minnesota Public Utilities Commission
(MNPUC) in the second quarter of 1997. Increases in transmission service
charge revenue and electric property rental income also contributed to the
increase in other electric revenue. Power pool sales increased as a result
of strong sales in the fourth quarter of 1997, which offset lower sales
earlier in the year.
Electric operating revenues decreased 2.2 percent in 1996, as compared to
1995, despite a 4.0 percent increase in retail kwh sales as a result of
lower prices and a decline in the volume of noncontractual power pool
sales. The reduction in retail kwh sales prices in 1996 is related to lower
fuel costs at Big Stone Plant being passed on to customers through the cost
of energy adjustment clause and lower rates charged to one of the Company's
largest industrial customers under the Company's Large General Service
Time-of-Use Rider. A number of external factors contributed to the
decrease in noncontractual power pool sales. Midcontinent Area Power Pool
(MAPP) transmission service charges made it less economical to ship energy
over long distances. The summer of 1996 was milder than the summer of 1995
and high water levels in the summer of 1996 furnished MAPP's hydro
generators with an excess of low-priced electricity to market. In addition
to external factors, lower plant availability in 1996 due to scheduled
outages at both Hoot Lake Unit 3 and Big Stone Plant also contributed to
the decrease in noncontractual power pool sales.
Heating degree days, which generally correlate to increases or decreases in
the use of electricity by residential customers, were 9,628 for 1997,
10,349 for 1996, and 9,326 for 1995.
Increases or decreases 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 nearly $41 million to the Company's
customers.
Production fuel expense increased 12.4 percent in 1997, as compared to
1996, while purchased power expense decreased 13.9 percent over the
comparable periods for a net decrease in production fuel and purchased
power expenses of 0.9 percent. The net reduction in production fuel and
purchased power expenses in 1997, as compared to 1996, was achieved despite
a slight increase in total kwh sales of 0.4 percent mainly as a result of
having Big Stone Plant, the Company's lowest cost generating unit,
available for generation during all of 1997, as compared to 1996, when it
was shut down two months for a major overhaul. In 1997 Big Stone Plant
generated a record net output of 3,166,398 mwh for a single year exceeding
its previous record output by 515,627 mwh. The increase in generation at
Big Stone Plant contributed to a decrease in purchased power in 1997 and
helped alleviate a shortage in available generation caused by the scheduled
maintenance shutdown of Coyote Plant in the Spring of 1997.
The 11.6 percent decrease in production fuel expense in 1996 is the result
of declines in fuel expenses at all three of the Company's major power
plants due to decreases in fuel costs per kwh at Big Stone and Hoot Lake
and decreases in net generation at Big Stone and Coyote. Two factors
contributing to the decrease in system wide generation in 1996 were lower
demand as a result of fewer noncontractual power pool sales and scheduled
maintenance shutdowns at Hoot Lake and Big Stone Plants. The 7.2 percent
decrease in purchased power in 1996 reflects a 45 percent decrease in kwh
purchases for resale partially offset by a 21 percent increase in purchases
for system use. The decrease in purchases for resale correlates to the
decrease in noncontractual power pool sales. The purchase of replacement
generation for planned plant outages was the major factor contributing to
the increase in purchases for system use.
The primary contributors to the 8.6 percent increase in other electric
operation and maintenance expense in 1997 are the overhaul of the Coyote
Plant in the second quarter of 1997 and increased expenditures for outside
and contracted services in 1997. Other operation and maintenance expenses
showed an increase of 4.1 percent for 1996. Other operation expenses were
up in 1996 mainly due to increases in benefit costs as a result of a
revision to actuarial assumptions related to the Company's Executive
Survivor and Supplemental Retirement Plan (see note 8 to financial
statements for further information). Also, there was an increase in
payments for contracted services in 1996, offset by a decrease in economic
development expenditures from the increased levels recorded in 1995.
Production plant maintenance expenses were also up in 1996. Hoot Lake Unit
3 was down for scheduled maintenance in February and March of 1996 and had
a turbine rebuild and steam chest replacement in July 1996. Big Stone
Plant underwent a scheduled ten-week major overhaul in September, October
and November of 1996.
The 7.9 percent increase in depreciation and amortization expense in 1997
is the result of property additions including upgrades made to Big Stone
Plant in the latter part of 1996. The increase in depreciation and
amortization expense of 2.2 percent in 1996 is attributable to additions
to plant in service from capital expenditures.
The decrease in property taxes of 5.9 percent in 1997 reflects reductions
in Minnesota property taxes as a result of legislative action affecting
Minnesota commercial and industrial property class rates for 1997 and lower
assessed values on Minnesota utility property. The 8.1 percent increase in
property taxes in 1996 was due to a 10 percent increase in the assessed
value of the Company's South Dakota utility property compounded by a 14
percent increase in the mill rates applied to that property.
Manufacturing operations
- ------------------------
(bar graph of information in following table)
Manufacturing operating
income
(millions)
-------------------------
1995 $3.3
1996 $6.5
1997 $7.9
(end of graph)
Manufacturing operations is made up of businesses involved in the
production of agricultural equipment, automobile and truck frame
straightening equipment and accessories, plastic pipe extrusion, and metal
parts stamping and fabrication. Initial acquisitions of businesses in this
segment were made in 1990. On June 30, 1997, Mid-States acquired Chassis
Liner Corporation (Chassis Liner) in a pooling of interests transaction.
(See note 2 to financial statements for more information.)
1997 1996 1995
-------- -------- --------
(in thousands)
Operating revenues $ 81,543 $ 64,568 $ 38,690
Cost of goods sold 61,361 48,269 29,884
Operating expenses 12,237 9,795 5,536
-------- -------- --------
Operating income $ 7,945 $ 6,504 $ 3,270
The increase in manufacturing operating revenue of 26.3 percent in 1997,
reflects increased sales at all six of the Company's manufacturing
subsidiaries. The 66.9 percent increase in manufacturing operating revenues
in 1996 reflects revenues from Northern Pipe Products, acquired in October
1995, and increased sales at BTD Manufacturing. Additionally, 1996 results
were restated to include Chassis Liner's $7,700,000 in operating revenues,
$4,524,000 in cost of goods sold, and $2,095,000 in operating expenses as a
result of the pooling. The pro forma effect of the pooling on 1995
consolidated results is considered to be too insignificant to warrant
restatement.
The increases of 27.1 percent in manufacturing cost of goods sold and 24.9
percent in manufacturing operating expenses in 1997, as compared to 1996,
correspond to the increase in sales over the same comparable periods. The
increase in cost of goods sold also reflects increases in prices for resins
used in the manufacture of PVC pipe. The 61.5 percent increase in
manufacturing cost of goods sold and 76.9 percent increase in operating
expenses in 1996 were directly related to the increase in manufacturing
revenue. The increases in manufacturing revenues for 1997 and 1996 more
than offset the increases in manufacturing cost of goods sold and operating
expenses for the same comparable periods resulting in increases in
manufacturing operating income in both 1997 and 1996.
Health services operations
- --------------------------
(bar graph of information in following table)
Health services
operating income
(millions)
-------------------------
1995 $3.6
1996 $5.1
1997 $4.3
(end of graph)
Health services operations include businesses involved in the sale,
service, rental, refurbishing, and operation of medical imaging equipment
and the sale of related supplies and accessories to various medical
institutions, primarily in the Midwest. Initial acquisitions of businesses
in this segment were made in 1993. Two companies were acquired in 1996:
one in February, and a second more significant acquisition in April. (See
note 2 to financial statements for more information.)
1997 1996 1995
-------- -------- --------
(in thousands)
Operating revenues $ 66,185 $ 61,697 $ 50,896
Cost of goods sold 36,872 34,032 31,576
Operating expenses 25,018 22,528 15,739
-------- -------- --------
Operating income $ 4,295 $ 5,137 $ 3,581
A reclassification of $6,192,000 from health services cost of goods sold to
health services operating expenses was made for 1996 related to the medical
imaging services companies acquired in 1996, in order to report these costs
and expenses in a manner consistent with previously acquired medical
imaging services companies.
The increases in health services operating revenue of 7.3 percent in 1997
and 21.2 percent in 1996, and increases in health services operating
expenses of 11.1 percent in 1997 and 43.1 percent in 1996, are all related
to the 1996 acquisitions of two medical imaging services companies. The
increase in health services cost of goods sold in 1997, as compared to 1996,
is due to valuation adjustments related to equipment held for sale and
increased costs associated with customer service contracts.
Other business operations
- -------------------------
(bar graph of information in following table)
Other business operations
operating income
(millions)
-------------------------
1995 $3.5
1996 $2.5
1997 $1.8
(end of graph)
The Company's other business operations include telephone utilities and
businesses involved in electrical and telephone construction contracting,
radio broadcasting, and waste incinerating. In 1996 Mid-States acquired
four radio stations; North Central Utilities, Inc. (NCU), the Company's
telecommunications subsidiary, acquired two small cable TV systems. On
January 2, 1997, NCU acquired The Peoples Telephone Co. of Bigfork
(Peoples) in a pooling of interests transaction. (See note 2 to financial
statements for more information.)
1997 1996 1995
-------- -------- --------
(in thousands)
Operating revenues $ 41,430 $ 45,323 $ 32,818
Cost of goods sold 23,393 28,297 18,954
Operating expenses 16,210 14,574 10,333
-------- -------- --------
Operating income $ 1,827 $ 2,452 $ 3,531
The 8.6 percent decrease in other business operations operating revenue in
1997, as compared to 1996, is due to a decline in revenue and reductions in
material cost pass through billings at the Company's construction
subsidiaries, offset slightly by increases in media and telecommunications
revenue due to the acquisition of several radio stations in 1996. The
decrease in construction activity and material cost pass through billings
are the main factors contributing to the 17.3 percent decrease in cost of
goods sold in 1997. The 38.1 percent increase in other business operations
operating revenue in 1996, as compared to 1995, reflects material cost pass
through billings by the Company's construction subsidiaries on material
intensive jobs. The increase in material costs billed in 1996 is also
reflected in the 49.3 percent increase in cost of goods sold for 1996.
Increases in operating expenses from other business operations of 11.2
percent in 1997 and 41.0 percent in 1996 reflect the acquisitions of four
radio stations during 1996. Operating expenses for 1996, as compared to
1995, were also up as a result of increased construction activity and
nonrecurring expenses related to the radio station acquisitions.
Additionally, 1996 results were restated to include Peoples' $1,493,000 in
operating revenue and $1,428,000 in operating expenses as a result of the
pooling. Results for 1995 were not restated for Peoples because the pro
forma effect was not material.
Consolidated other income and deductions--net
- ---------------------------------------------
A gain on the sale of a Direct Broadcast Satellite franchise, in which the
Company's telecommunications subsidiary, Midwest Information Systems, Inc.,
held a one-third ownership interest, accounted for $1.8 million of the
increase in other income and deductions--net in 1997, as compared to 1996.
Realized gains on sales of investments of $751,000 and an increase of
$1,322,000 in miscellaneous nonoperating income, including compensation for
the abandonment of certain microwave frequencies licensed to the Company,
also contributed to the 1997 increase in other income and deductions--net.
The remainder of the increase in other income and deductions--net for 1997
reflects an increase in revenue recognition related to Minnesota CIP
financial incentives of $307,000. The increase in other income and
deductions--net in 1996, as compared to 1995, reflects a reduction in
miscellaneous expenses at the health services subsidiaries in 1996 and
losses on marketable securities recognized in 1995 related to the Company's
preferred stock investment program which ended in October of 1995.
Consolidated interest charges
- -----------------------------
Interest charges increased 9.8 percent in 1997 and 11.9 percent in 1996 as
a result of increased debt at the Company's subsidiaries due to
acquisitions and growth and increased use of short-term debt at the parent-
company level.
Consolidated income taxes
- -------------------------
The increase of 2.1 percent in 1997 income taxes over 1996 income taxes is
mainly due to an increase in income before income taxes for the same
comparable periods. Part of the increase in taxes on increased operating
income was offset by an increase in affordable housing tax credits earned
in 1997 over 1996. Also, because Chassis Liner was an S corporation prior
to being acquired, income before income taxes for 1997 and 1996 includes
net income, not subject to income taxes, from Chassis Liner of $703,000 and
$1,049,000, respectively. Income taxes for 1996 also reflects reductions
related to deferred tax adjustments. The 13.3 percent decrease in income
taxes in 1996, compared to 1995, was the result of net capital losses
realized in 1995 on the sale of marketable securities not generating tax
savings, the initial recording of affordable housing tax credits in 1996,
and the reversal of taxes previously deferred at rates higher than current
tax rates. (See note 11 and "Investments" under note 1 to financial
statements for more information.)
Impact of inflation
- -------------------
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. 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.
(three bar graphs of information in following tables)
Other income and deductions
(millions)
-------------------------
1995 $1.9
1996 $2.1
1997 $6.1
Interest charges
(millions)
-------------------------
1995 $15.1
1996 $16.9
1997 $18.5
Income taxes
(millions)
-------------------------
1995 $16.2
1996 $14.0
1997 $14.3
(end of graphs)
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 showed increases of 1.4 percent in 1997, 4.0 percent in 1996,
and 3.4 percent in 1995.
Market factors beyond the Company's control such as mergers and
acquisitions, geographical location, transmission costs and uncertainty
about the effects of deregulation could have a negative impact on
noncontractual power pool sales. However, the relative effect of any
decrease in noncontractual power pool sales on earnings is less than its
proportionate effect on the decrease in electric revenues due to the
relatively low margin of profits on these sales.
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 jurisdictions
served by the Company. The goal of DSM is to encourage the wise and
efficient use of electricity by customers. Currently, Minnesota is the
only jurisdiction that mandates investments in DSM.
In 1997 the MPUC approved the Company's 1996 financial incentive filing
along with a 1.75 percent surcharge on all Minnesota customers' bills
starting on July 1, 1997, for the recovery of conservation-related costs
over and above those being recovered in current rates. The approved
surcharge in effect from July 1, 1996, through June 30, 1997, was 1.25
percent and the approved surcharge in effect from July 1, 1995, through
June 30, 1996, was .5030 percent. The current surcharge rate will be in
place until June 30, 1998, when it will be revised for subsequent years'
program results. (See note 3 to financial statements for more
information.)
Energy adjustment clause
- ------------------------
The Company began purchasing subbituminous coal for Big Stone Plant in
August 1995 under a contract that runs through December 1999. Price
reductions, in addition to plant efficiency gains due to switching from
lignite to higher-Btu subbituminous coal, have resulted in cost reductions.
The majority of these reductions, which enhance the Company's competitive
position, are passed on to retail electric customers through the cost of
energy adjustment clause.
In November 1995 the Company and two other Coyote Plant owners 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. The case was remanded to
arbitration in 1997 and a resolution is still pending. Any fuel cost
savings that may result from resolution of this dispute will be passed on
to customers through the cost of energy adjustment clause.
Regulation and legislation
- --------------------------
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 Big Stone Plant will maintain current levels of operation and
meet phase two requirements for sulfur dioxide emissions by burning
subbituminous coal and/or purchasing sulfur dioxide emission allowances.
As stated previously, Big Stone Plant's new coal contract expires at the
end of 1999. The cost of subbituminous coal in 2000 and beyond probably
will be higher than the current market price but likely will not affect the
Company's power plant operations adversely. Under EPA regulations,
modifications would be required at Big Stone Plant by 2000 to satisfy
nitrogen oxide emission standards. During 1997 the Company conducted tests
at Big Stone Plant to determine if nitrogen oxide emissions could be
reduced through modifications to existing equipment. The results of the
tests were positive and the modifications will be completed at a nominal
cost. The Company is a member of the Utility Air Regulatory Group (UARG),
which has filed a petition in Federal Court for reconsideration of the
standards based on inconsistencies in current laws. The petitioners are
awaiting the Court's decision.
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. Hoot Lake Plant already
uses low-sulfur subbituminous coal. Minor modifications may be required at
Hoot Lake Plant to meet the phase two nitrogen oxide emission requirements
by 2000.
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. On April 24, 1996, the FERC issued two final rules, Order Nos.
888 and 889, which may have a potentially significant impact on wholesale
markets.
Order No. 888, effective July 9, 1996, requires electric utilities and
other transmission providers to abide by, and to offer to other
transmission users, terms, conditions and pricing comparable to those they
use for themselves in transmitting power. The Company filed its initial
transmission tariff on July 9, 1996, as required by Order No. 888. A
revised rate schedule became effective in the first quarter of 1997.
Order No. 889, which became effective January 3, 1997, requires public
utilities to implement Standards of Conduct and an Open Access Same-Time
Information System (OASIS). These rules require transmission personnel to
provide information about their transmission systems to all customers,
including their marketing associates within their respective companies,
through the OASIS. The FERC issued orders after rehearing, 888A and B,
further clarifying its intent to prevent any discriminatory abuse of market
power by utilities controlling both transmission and generation assets.
The U.S. Congress ended its 1997 legislative session without taking action
on proposed electric industry restructuring legislation. Federal
restructuring legislation in 1998, a Congressional election year, is also
unlikely due to the complexities of issues involved with federal
intervention.
The Minnesota Public Utilities Commission issued its Wholesale Competition
Report in 1996 and its Retail Competition Report in 1997 and continues to
work on specific topics in the areas of potential stranded costs, unbundled
rates and affiliated transactions. The Minnesota Legislature will most
likely deal with removing tax obstacles to electric utility deregulation in
1998 with an actual deregulation bill not likely until 1999. In 1997 the
North Dakota Legislature created a subcommittee to investigate the impact
of electric utility industry restructuring on North Dakota. In view of the
legislative effort, the North Dakota Public Service Commission closed its
investigative docket. The South Dakota PUC has not taken any action with
regards to industry restructuring or retail competition.
Competition
- -----------
The Company is taking a number of steps to position itself for success in a
competitive marketplace. It has initiated the process of functionally
unbundling its energy supply, energy delivery, and energy services
operations by establishing separate operating business units for each of
these functions. The Company is developing the necessary accounting systems
to capture costs and determine the profitability of each of these business
units and to identify areas for improvement and opportunities for increased
profitability. The Company has established an energy services business
unit to promote the energy related products and services that have always
been offered to its customers and to develop new products and services to
be offered to current and potential customers in order to distinguish
itself from the competition.
In January 1998 the Company announced a voluntary early retirement program
for all nonunion employees age 55 and over. Incentives include elimination
of early retirement benefit reductions, a credit of five years of
additional service for calculating pension and other postretirement
benefits, and a monthly supplement for medical coverage until the retiree
reaches age sixty-two. The Company expects approximately 40 of the 67
employees eligible for the program to accept the offer, which would result
in an estimated one-time noncash charge of approximately
$4 million ($2.4 million net-of-tax) to the Company's income statement in
the first quarter of 1998. Most of the cost of the program will be funded
through the Company's pension plan. The Company anticipates that most of
the staff reductions will be permanent, resulting in enhanced future
earnings through reduced payroll expenses.
The Company also announced that it will begin recording unbilled revenue in
Minnesota and South Dakota, subject to notification of the respective state
regulatory bodies, in the first quarter 1998. This would be consistent
with how the Company is currently recording North Dakota unbilled revenues
under an order from the North Dakota PSC. The accounting change will
result in a one-time noncash increase in earnings of approximately $6.4
million ($3.8 million net-of-tax) in 1998.
As the electric industry evolves and becomes more competitive, the Company
believes it is well positioned to maintain its customer base and may have
opportunities to increase its market share. The Company's generation
capacity appears poised 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 its rates are competitive. In addition, the Company would attempt
more flexible pricing strategies under an open, competitive environment.
The year 2000 (millennium) bug
- ------------------------------
The Company does not expect to incur significant costs over the next two
years to modify software programs to accommodate the year 2000 because
coding standards used when the programs were written have enabled the
Company to programmatically identify and locate the code that needs to be
changed on all programs written in-house. The Company anticipates that it
will be able to cover any conversion costs within current operating budget
levels. Additionally, the Company has replaced or is in the process of
updating or replacing a number of its financial application and other
operating programs within the normal course of business. The new software
will accommodate the millennium change.
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.
In 1997 Quadrant Co. (Quadrant) began processing solid waste for three
Minnesota counties under the terms of a new waste incineration agreement.
Since operating under the new agreement, Quadrant has experienced a
reduction in revenue of approximately 50 percent, as compared to 1996. New
pollution rules for Minnesota waste incinerators have been issued. The
costs to be in compliance with the new pollution rules by the year 2000 in
conjunction with reduced operating revenues threaten the economic viability
of the plant. However, Quadrant is currently generating positive cash
flows from the operation of its plant which had a net undepreciated book
value of approximately $2.45 million on December 31, 1997. The Company
intends to operate the Quadrant plant as long as positive cash flows can be
maintained but will continue to evaluate its investment in Quadrant for
asset impairment on a quarterly basis.
Accounting pronouncements:
In June 1997 the FASB issued Statement of Financial Accounting Standards
(SFAS) 131 - Disclosures about Segments of an Enterprise and Related
Information, effective for financial statements issued for periods
beginning after December 15, 1997. SFAS 131 establishes standards for the
way that public business enterprises report information about operating
segments in annual financial statements and requires that those enterprises
report selected information about operating segments in interim financial
reports issued to shareholders. It also establishes standards for related
disclosures about products and services, geographic areas and major
customers. In general, SFAS 131 requires financial information to be
reported on the basis that it is used internally for evaluating performance
and deciding how to allocate resources. Except for the electric utility
the Company is comprised of many smaller businesses that tend to operate
with a high degree of autonomy with respect to management and strategic
decision-making. Because of this, no single entity may meet the threshold
requirements for segment reporting. As a result the Company may aggregate
two or more entities with similar economic characteristics into a single
segment for reporting purposes, much the same as the Company is currently
doing for segment reporting purposes. Adoption of SFAS 131 in 1998 is not
expected to result in significant changes to the operating segments
presently disclosed. However, structural changes within the electric
utility business related to the functional unbundling of defined business
units may result in segment reporting changes in the future. In 1997 the
Company adopted SFAS 128 and SFAS 130 (see footnote 1 to financial
statements for further information.)
Cautionary Statements for Purposes of the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995
- ------------------------------------------------------------------
The information in this annual report includes forward-looking statements.
Important risks and uncertainties that could cause actual results to
differ materially from those discussed in such forward-looking statements
are set forth above under "Factors affecting future earnings." Other risks
and uncertainties may be detailed from time to time in the Company's future
Securities and Exchange Commission filings.
<TABLE>
Otter Tail Power Company
Consolidated Statements of Income
For the Years Ended December 31 1997 1996 1995
- ----------------------------------------------------------------------------------------
( in thousands, except per share amounts)
<S> <C> <C> <C>
Operating revenues:
Electric $205,121 $199,345 $203,925
Manufacturing 81,543 64,568 38,690
Health services 66,185 61,697 50,896
Other business operations 41,430 45,323 32,818
-------- -------- --------
Total operating revenues 394,279 370,933 326,329
Operating expenses:
Production fuel 31,362 27,913 31,559
Purchased power 24,420 28,378 30,591
Electric operation and maintenance expenses 72,112 66,401 63,777
Cost of goods sold 121,626 110,598 80,414
Other nonelectric expenses 49,325 43,351 29,111
Depreciation and amortization 25,536 23,387 21,909
Property taxes 10,865 11,533 10,670
-------- -------- --------
Total operating expenses 335,246 311,561 268,031
Operating income:
Electric 44,966 45,279 47,916
Manufacturing 7,945 6,504 3,270
Health services 4,295 5,137 3,581
Other business operations 1,827 2,452 3,531
-------- -------- --------
Total operating income 59,033 59,372 58,298
Other income and deductions -- net 6,140 2,125 1,881
Interest charges 18,519 16,863 15,075
-------- -------- --------
Income before income taxes 46,654 44,634 45,104
Income taxes 14,308 14,010 16,159
-------- -------- --------
Net income 32,346 30,624 28,945
Preferred dividend requirements 2,358 2,358 2,358
-------- -------- --------
Earnings available for common shares $ 29,988 $ 28,266 $ 26,587
======== ======== ========
Average number of common shares outstanding 11,639 11,503 11,180
Basic and diluted earnings per share $2.58 $2.46 $2.38
Dividends per common share $1.86 $1.80 $1.76
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
Otter Tail Power Company
Consolidated Balance Sheets, December 31 1997 1996
- ----------------------------------------------------------------------------------------
(in thousands)
Assets
<S> <C> <C>
Plant:
Electric plant in service $758,551 $742,065
Subsidiary companies 89,716 101,789
-------- --------
Total 848,267 843,854
Less accumulated depreciation and amortization 350,647 330,379
-------- --------
Plant - net of accumulated depreciation and amortization 497,620 513,475
Construction work in progress 12,146 11,470
-------- --------
Net plant 509,766 524,945
-------- --------
Investments 20,048 20,549
-------- --------
Intangibles--net 20,911 21,954
-------- --------
Other assets 5,932 6,553
-------- --------
Current assets:
Cash and cash equivalents 5,301 2,130
Accounts receivable:
Trade (less accumulated provision for uncollectible accounts:
1997, $1,026,000; 1996, $690,000) 33,304 32,845
Other 6,796 5,021
Materials and supplies:
Fuel 3,425 3,219
Inventory, materials and operating supplies 24,160 24,273
Deferred income taxes 4,738 4,550
Accrued utility revenues 4,271 5,349
Other 3,795 4,525
-------- --------
Total current assets 85,790 81,912
-------- --------
Deferred debits:
Unamortized debt expense and reacquisition premiums 4,187 4,270
Regulatory assets 5,060 5,866
Other 3,747 3,655
-------- --------
Total deferred debits 12,994 13,791
-------- --------
Total $655,441 $669,704
======== ========
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
Otter Tail Power Company
Consolidated Balance Sheets, December 31 1997 1996
- ----------------------------------------------------------------------------------------
(in thousands)
Liabilities
<S> <C> <C>
Capitalization (page 36):
Common shares, par value $5 per share -- authorized, 25,000,000
shares; outstanding, 1997 11,731,078; 1996 11,536,056 shares $ 58,655 $ 57,680
Premium on common shares 35,196 29,885
Retained earnings 115,942 107,864
Accumulated other comprehensive income 363 619
-------- --------
Total common equity 210,156 196,048
Cumulative preferred shares:
Subject to mandatory redemption 18,000 18,000
Other 20,831 20,831
Long-term debt 189,973 163,176
-------- --------
Total capitalization 438,960 398,055
-------- --------
Current liabilities:
Short-term debt 2,100 25,600
Sinking fund requirements and current maturities 12,324 42,587
Accounts payable 28,427 27,330
Accrued salaries and wages 3,835 3,847
Federal and state income taxes accrued 2,572 2,031
Other taxes accrued 11,122 12,055
Interest accrued 3,339 3,653
Other 2,980 2,829
-------- --------
Total current liabilities 66,699 119,932
-------- --------
Noncurrent liabilities 17,805 16,688
-------- --------
Commitments (note 6) -- --
-------- --------
Deferred credits:
Accumulated deferred income taxes 97,583 99,131
Accumulated deferred investment tax credit 18,666 19,852
Regulatory liabilities 12,121 13,283
Other 3,607 2,763
-------- --------
Total deferred credits 131,977 135,029
-------- --------
Total $655,441 $669,704
======== ========
See accompanying notes to consolidated financial statements.
</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, 1997, and 1996, and the related consolidated
statements of income, changes in equity, and cash flows for each of the
three years in the period ended December 31, 1997. 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, 1997, and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
February 2, 1998
Minneapolis, Minnesota
<TABLE>
Otter Tail Power Company
Consolidated Statements of Changes in Equity
- ----------------------------------------------------------------------------------------------------------
accumulated
common par value premium on other
shares common common retained comprehensive total
outstanding shares shares earnings income equity
----------- -----------------------------------------------------
( in thousands, except common shares outstanding)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1994 11,180,136 $ 55,901 $ 30,335 $ 91,096 $ (684) $176,648
Comprehensive income:
Net income 28,945 28,945
Reversal of previously recorded
unrealized loss on available-for-
sale securities sold in 1995 684 684
--------
Total comprehensive income 29,629
Cumulative preferred dividends
at required annual rates (2,358) (2,358)
Common dividends (19,677) (19,677)
----------- ----------------------------------------------------
Balance, December 31, 1995 11,180,136 $ 55,901 $ 30,335 $ 98,006 $ -- $184,242
Effects of pooling transactions,
January 1, 1996:
Peoples Telephone 163,758 819 (798) 2,058 216 2,295
Chassis Liner 157,646 788 (588) 381 581
Common stock issuances 34,516 172 936 1,108
Comprehensive income:
Net income 30,624 30,624
Unrealized gains on
available-for-sale securities 403 403
--------
Total comprehensive income 31,027
Cumulative preferred dividends
at required annual rates (2,358) (2,358)
Common dividends (20,124) (20,124)
Distributions by pooled entities (723) (723)
----------- ----------------------------------------------------
Balance, December 31, 1996 11,536,056 $ 57,680 $ 29,885 $107,864 $ 619 $196,048
Cash portion of Peoples pooling
transaction, January 1, 1997 (209) (209)
Common stock issuances 195,022 975 5,520 6,495
Comprehensive income:
Net income 32,346 32,346
Unrealized gains on
available-for-sale securities 103 103
Reversal of previously recorded
unrealized gains on available-for-
sale securities sold in 1997 (359) (359)
--------
Total comprehensive income 32,090
Cumulative preferred dividends
at required annual rates (2,358) (2,358)
Common dividends (21,496) (21,496)
Distributions by pooled entities (414) (414)
----------- ----------------------------------------------------
Balance, December 31, 1997 11,731,078 $ 58,655 $ 35,196 $115,942 $ 363 $210,156
- ----------------------------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
Otter Tail Power Company
Consolidated Statements of Cash Flows
For the Years Ended December 31 1997 1996 1995
- ---------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 32,346 $ 30,624 $ 28,945
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 39,302 35,305 28,602
Deferred investment tax credit--net (1,186) (1,186) (1,177)
Deferred income taxes (3,155) (5,277) 751
Change in deferred debits and other assets 1,204 3,679 (1,792)
Change in noncurrent liabilities and deferred credits 1,960 3,389 4,560
Allowance for equity (other) funds used during construction -- (325) (229)
(Gain)/loss on investments in and disposal of noncurrent assets (1,722) 555 946
Cash provided by (used for) current assets and current liabilities:
Change in receivables, materials, and supplies (2,270) 396 (1,035)
Change in other current assets 1,752 (922) (1,349)
Change in payables and other current liabilities 908 867 1,436
Change in interest and income taxes payable 259 1,506 (1,581)
-------- -------- --------
Net cash provided by operating activities 69,398 68,611 58,077
-------- -------- --------
Cash flows from investing activities:
Gross capital expenditures (41,973) (64,823) (37,134)
Proceeds from disposal of noncurrent assets 20,802 4,734 2,417
Proceeds from the sales of marketable securities 785 -- 17,043
Purchase of subsidiaries, net of cash acquired -- (10,006) (5,808)
Change in temporary cash investments -- 2,208 (1,817)
Change in other investments (470) (10,640) (3,892)
-------- -------- --------
Net cash used in investing activities (20,856) (78,527) (29,191)
-------- -------- --------
Cash flows from financing activities:
Change in short-term debt--net issuances (23,500) 25,600 (2,900)
Proceeds from issuance of long-term debt 178,272 118,083 54,482
Proceeds from issuance of common stock 6,286 1,719 --
Payments for debt and common stock issuance expense (244) (22) --
Payments for retirement of long-term debt (181,917) (111,957) (58,418)
Dividends paid (24,268) (23,244) (22,035)
-------- -------- --------
Net cash (used in)/provided by financing activities (45,371) 10,179 (28,871)
-------- -------- --------
Net change in cash and cash equivalents 3,171 263 15
Cash and cash equivalents at beginning of year 2,130 1,867 1,852
-------- -------- --------
Cash and cash equivalents at end of year $ 5,301 $ 2,130 $ 1,867
======== ======== ========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized) $ 18,203 $ 16,650 $ 14,160
Income taxes $ 18,057 $ 18,832 $ 18,286
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
Otter Tail Power Company
Consolidated Statements of Capitalization, December 31 1997 1996
- ----------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Total common shareholders' equity $210,156 $196,048
-------- --------
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
-------- --------
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 -- 18,800
7.25%, due August 1, 2002 19,000 19,200
7.625%, due February 1, 2003 -- 9,240
8.75%, due September 15, 2021 18,800 19,000
8.25%, due August 1, 2022 28,500 28,800
Pollution control series:
6.20-6.80%, due February 1, 2006, Big Stone project 5,367 5,427
8.125%, due August 1, 2009, Coyote project, series B -- 830
6.20-6.90%, due February 1, 2019, Coyote project 21,499 21,734
-------- --------
Total first mortgage bond series 93,166 123,031
Senior debentures 6.375%, due December 1, 2007 50,000 --
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 4.20% at December 31, 1997, due December 1, 2012 10,400 10,400
Obligations of Mid-States Development, Inc.:
7.80% ten-year term note 22,500 --
various at 2.90% to 11.38% at December 31, 1997 10,775 56,900
Obligations of North Central Utilities, Inc.
variable 7.13% to 7.28% at December 31, 1997 11,542 10,867
Other 6 1
-------- --------
Total 203,599 206,409
Less:
Current maturity 11,329 41,462
Sinking fund requirement 995 1,125
Unamortized debt discount and premium -- net 1,302 646
-------- --------
Total long-term debt 189,973 163,176
-------- --------
Total capitalization $438,960 $398,055
======== ========
See accompanying notes to consolidated financial statements.
</TABLE>
Otter Tail Power Company
Notes to consolidated financial statements
For the three years ended December 31, 1997
1. Summary of accounting policies
System of accounts - In 1997 the Company implemented an activity based
costing system along with an entirely new account code structure that will
enable it to capture costs to facilitate decision-making in a less
regulated and more competitive electric industry. For regulatory reporting
purposes, all new account code combinations can be translated into the
accounts of 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. Profits on
sales from the regulated electric utility company to nonregulated
affiliates are eliminated. However, profits on sales to the regulated
electric utility company from nonregulated affiliates are not eliminated,
in accordance with the requirements of Statement of Financial Accounting
Standards (SFAS) No. 71 - Accounting for the Effects of Certain Types of
Regulation.
Plant, retirements, and depreciation -- Utility plant is stated at original
cost. 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 electric utility property were 3.08 percent in 1997, 3.00
percent in 1996, and 2.97 percent in 1995.
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 accounted for under the purchase method of accounting,
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 percent and 35 percent ownership interests in the assets,
liabilities and expenses of Big Stone Plant and Coyote Plant, respectively.
Amounts at December 31, 1997 and 1996, included in Plant in Service for
Big Stone were $108,273,000 and $109,521,000, respectively, and the
accumulated provision for depreciation and amortization was $61,650,000 and
$59,078,000, respectively. Amounts at December 31, 1997 and 1996, included
in Plant in Service for Coyote were $145,720,000 and $145,542,000,
respectively, and the accumulated provision for depreciation and
amortization was $61,820,000 and $58,436,000, 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. In 1997 the average level of
short-term borrowing exceeded the average level of construction work in
progress; consequently, 1997 AFC was based entirely on the year's average
short-term debt borrowing rate. In 1996 and 1995 AFC was based on a
composite rate that assumes funds used for construction were provided by
borrowed funds and equity funds. The AFC included in construction work in
progress will ultimately be included in the rate base used in establishing
rates for utility services. The rate for AFC was 5.67 percent for 1997,
8.50 percent for 1996, and 9.50 percent for 1995.
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 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 recorded electric
revenues based on billing dates in all of its jurisdictions. 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. The North Dakota
unbilled revenue amount as of January 1, 1993, ($4.4 million) was amortized
to electric revenues over 36 months as required by the order. The change
in method of revenue recognition resulted in additional net income of
$984,000 in 1995. The impact on 1995 earnings per share was $.09. The
Company will begin recording unbilled revenue in Minnesota and South
Dakota, subject to notification of the respective state regulatory bodies,
in 1998. The accounting change will result in a one-time noncash increase
in earnings of approximately $6.4 million ($3.8 million net-of-tax) in
1998.
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 surcharge for recovery of conservation-related expenses: 1.75
percent as of July 1, 1997, 1.25 percent from July 1, 1996, through June
30, 1997, and .5030 percent from July 1, 1995, through June 30, 1996. (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 operating 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 or products are shipped. In the case of construction
contracts, the percentage-of-completion method is used.
Storm damage provision -- The Company is required under its Indenture of
Mortgage to make annual provisions for storm damage of not less than 0.5
percent gross electric operating revenues. Provisions for loss have been
used in determining rates approved by the applicable regulatory
commissions. Provisions for 1997, 1996, and 1995 were $1,423,000,
$1,247,000, and $1,800,000, respectively.
Employee incentive plan -- The Company has a gain sharing plan for all
electric utility company employees. The total compensation received by all
electric utility company employees for 1997, 1996, and 1995 was $817,000,
$778,000, and $870,000, respectively. Mid-States' companies have incentive
plans for certain employees that are based on certain levels of sales and
profits. Total amounts accrued for these incentive plans in 1997, 1996,
and 1995 were $2,658,000, $1,998,000 and $1,891,000, respectively. North
Central Utilities, Inc. companies have incentive plans for all employees
based on levels of profitability and returns. Amounts accrued related to
these plans for 1997, 1996, and 1995 were $351,105, $34,094, and $16,380,
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, service contract maintenance costs
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.
Reclassifications -- Certain prior year amounts have been reclassified to
conform to 1997 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 -- The combined 1996 beginning cash
balance of $589,000 of the two companies acquired in 1997 pooling of
interests transactions is included under proceeds from the issuance of
common stock in 1996; this treatment is required because financial
statements prior to 1996 are not being restated to reflect the effect of
the poolings due to their insignificant impact on the Company's
consolidated financial statements prior to 1996. Cash used of $209,000 to
acquire shares of minor shareholders in one of the 1997 pooling
acquisitions is netted against proceeds from the issuance of common stock
in 1997.
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 -- At December 31, 1997 and 1996, the Company had noncurrent
investments of $6,761,000 and $6,163,000, respectively, in limited
partnerships that invest in tax-credit qualifying affordable housing
projects. These investments, accounted for under the equity method,
provided the Company with tax credits of $1,057,000 and $593,000, in 1997
and 1996, respectively. At December 31, 1997 and 1996, the Company had
$703,000 and $1,211,000, respectively, invested in marketable equity
securities classified as available-for-sale and recorded at market value.
The balance of investments at December 31, 1997, consists of $5,571,000 in
additional investments accounted for under the equity method, and
$7,013,000 in financial instruments, with $2,070,000 related to
participation in economic development loan pools. The balance of
investments at December 31, 1996, consists of $8,722,000 in additional
investments accounted for under the equity method, and $4,453,000 in
financial instruments, with approximately $2,000,000 related to
participation in economic development loan pools. (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, 1997 and 1996, was 6.15 percent and 5.77 percent,
respectively. The average interest rate paid on short-term debt during
1997 and 1996 was 5.67 percent and 5.65 percent, respectively.
Intangible assets -- The majority of the Company's intangible assets consist
of goodwill associated with the acquisition of subsidiaries. Intangible
assets are amortized on a straight-line basis over periods of 40 years for
the telephone company 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:
1997 1996
-------- --------
(in thousands)
Goodwill on telephone company $ 7,749 $ 7,749
Other intangible assets 20,594 19,870
------- -------
Total 28,343 27,619
Less accumulated amortization 7,432 5,665
------- -------
Intangibles-net $20,911 $21,954
Adoption of new accounting pronouncements -- In February 1997 the FASB issued
SFAS 128 - Earnings Per Share, effective for financial statements issued
for periods ending after December 15, 1997. SFAS 128 requires certain
public companies to present both basic and diluted earnings per share (EPS)
on the face of their income statements. Diluted EPS reflects the dilution
that could occur if securities or other contracts to issue common stock
(options, warrants, convertible debt or preferred stock, contingent share
arrangements, etc.) were exercised or converted into common stock or
resulted in the issuance of common stock that then shared in the earnings
of the entity. Other than the Company's outstanding $9.00 exchangeable
cumulative preferred shares, which are not redeemable or exchangeable until
after August 9, 1999, the Company has no financial instruments outstanding
similar to those mentioned above. Additionally, if the outstanding $9.00
preferred shares were exchanged for shares of the Company's common stock,
the effect on the Company's 1997 EPS would be antidilutive. Therefore, the
Company's basic and diluted EPS are the same and are effectively disclosed
on the face of the Company's 1997, 1996 and 1995 consolidated statements of
income included in this report.
In June 1997 the FASB issued SFAS 130 - Reporting Comprehensive Income,
effective for fiscal years beginning after December 15, 1997, with earlier
application permitted. SFAS 130 establishes standards for reporting and
display of comprehensive income and its components (revenues, expenses,
gains, and losses) in a full set of general-purpose financial statements
and requires that all items required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. SFAS 130 requires an enterprise to classify items of other
comprehensive income by their nature in a financial statement and to
display the accumulated balance of other comprehensive income separately
from retained earnings and additional paid-in capital in the equity section
of a statement of financial position. The Company has elected early
application of the requirements of SFAS 130 with the display of elements of
other comprehensive income in the consolidated statements of changes in
equity. The statement of changes in equity not only provides for the
display of elements of other comprehensive income pursuant to the
requirements of SFAS 130 but it also allows for the elimination of the
consolidated statements of retained earnings from the Company's financial
statements and it provides for the presentation of changes in equity
related to recent issuances of the Company's common stock.
2. Business combinations and segment information
On January 2, 1997, the Company's telecommunications subsidiary, North
Central Utilities, Inc., (NCU) acquired all of the outstanding common stock
of The Peoples Telephone Co. of Bigfork (Peoples), a telephone company with
1,903 access lines serving five communities in Northern Minnesota, in
exchange for 163,758 newly issued shares of the Company's common stock and
$209,000 in cash. On June 30, 1997, the Company's subsidiary, Mid-States
Development, Inc., (Mid-States) acquired all of the outstanding common
stock of Chassis Liner Corporation (Chassis Liner), a manufacturer of auto
and truck frame straightening equipment with facilities in Alexandria and
Lucan, Minnesota, in exchange for 157,646 newly issued shares of the
Company's common stock. These acquisitions have been accounted for under
the pooling of interests method of accounting. There were no transactions
between the Company, Peoples and Chassis Liner prior to the acquisitions.
Costs incurred to effect these mergers were not significant.
The Company's 1996 consolidated financial statements have been restated to
include both Peoples and Chassis Liner. However, the Company's 1995
consolidated financial statements and other financial information for 1995
and prior years presented herein have not been restated to reflect the
effects of the poolings because the impact of the poolings on those years
is not material. The results of operations of the separate companies and
the combined amounts included in the consolidated financial statements are
presented in the table below.
Otter Tail
Power Pooled
Company Entities Combined
-------- -------- --------
(in thousands, except per share amounts)
For the year ended December 31, 1996:
Changes in common equity:
Common shares, par value $ 56,073 $ 1,607 $ 57,680
Premium on common shares 31,271 (1,386) 29,885
Retained earnings 105,479 2,385 107,864
Accumulated other comprehensive income 403 216 619
-------- -------- --------
Total common equity $193,226 $ 2,822 $196,048
======== ======== ========
Operating revenues $361,739 $ 9,194 $370,933
Net Income (1) $ 29,955 $ 669 $ 30,624
Earnings available for common shares $ 27,597 $ 669 $ 28,266
Average common shares outstanding 11,182 321 11,503
Basic and diluted earnings per share $ 2.47 $ 2.46
For the three months ended March 31, 1997:(2)
Operating revenues $ 91,770 $ 2,519 $ 94,289
Net Income (1) $ 10,234 $ 456 $ 10,690
Earnings available for common shares $ 9,645 $ 456 $ 10,101
Average common shares outstanding 11,412 157 11,569
Basic and diluted earnings per share $ .85 $ .87
(1)Prior to being acquired, Chassis Liner was an S Corporation and,
consequently, was not subject to federal or state income taxes. The pro
forma income tax provision for Chassis Liner that would have been
reported by the Company as an additional provision to its historical tax
expense had Chassis Liner not been an S Corporation prior to the
acquisition is $182,000 for the three month period ended March 31, 1997,
$281,000 for the year ended December 31, 1997, and $420,000 for year
ended December 31, 1996, based on a tax rate of 40 percent.
(2)Chassis Liner only.
In 1996 Mid-States purchased a Montana-based supplier of X-ray supplies and
accessories in February, a mobile medical diagnostic services company
located in Minnesota in April, and four radio stations located in the
Fargo, North Dakota/ Moorhead, Minnesota, market area: two in June, one in
October, and one in December. NCU acquired two small cable TV systems in
1996. Mid-States purchased a manufacturing company and three diagnostic
imaging companies in January 1995, and another manufacturing company in
October 1995.
In the 1996 and 1995 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
1996 and 1995. The total price for the businesses acquired was $11,060,000
in 1996 and $10,820,000 in 1995.
The Company's business operations, which are based mainly in Minnesota,
North Dakota, and South Dakota, principally in the region known as the "Red
River Valley of the North," are broken down into four segments. 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 located primarily
in the Midwestern United States. Manufacturing operations includes
production of agricultural equipment, plastic pipe, automobile and truck
frame straightening equipment and accessories, 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 1997, 1996 and 1995 is presented in the table below:
1997 1996 1995
-------- -------- --------
(in thousands)
Operating revenue
Electric $205,121 $199,345 $203,925
Manufacturing 81,543 64,568 38,690
Health services 66,185 61,697 50,896
Other business operations 41,430 45,323 32,818
-------- -------- --------
Total $394,279 $370,933 $326,329
Operating income
Electric $ 44,966 $ 45,279 $ 47,916
Manufacturing 7,945 6,504 3,270
Health services 4,295 5,137 3,581
Other business operations 1,827 2,452 3,531
-------- -------- --------
Total $ 59,033 $ 59,372 $ 58,298
Depreciation and amortization
Electric $ 21,442 $ 19,880 $ 19,448
Manufacturing 542 594 344
Health services 638 585 517
Other business operations 2,914 2,328 1,600
-------- -------- --------
Total $ 25,536 $ 23,387 $ 21,909
Capital expenditures
Electric $ 26,603 $ 38,224 $ 27,443
Manufacturing 6,264 4,787 3,879
Health services 3,800 16,230 4,020
Other business operations 5,306 5,582 1,792
-------- -------- --------
Total $ 41,973 $ 64,823 $ 37,134
Identifiable assets
Electric $526,679 $523,509 $509,588
Manufacturing 40,814 34,354 27,270
Health services 35,738 65,140 41,623
Other business operations 52,210 46,701 30,715
-------- -------- --------
Total $655,441 $669,704 $609,196
SFAS 131 establishes standards for the way that public business enterprises
report information about operating segments in annual financial statements
and requires that those enterprises report selected information about
operating segments in interim financial reports issued to shareholders. It
also establishes standards for related disclosures about products and
services, geographic areas and major customers. In general, SFAS 131
requires financial information to be reported on the basis that it is used
internally for evaluating performance and deciding how to allocate
resources. Adoption of SFAS 131 in 1998 is not expected to result in
significant changes to the operating segments presently disclosed.
3. Rate matters
On July 1, 1995, the Company began charging all Minnesota customers a
.5030 percent surcharge on their electric service statements for recovery
of conservation-related costs exceeding the amount already included in base
rates. On July 1, 1996, the rate was increased to 1.25 percent and on July
1, 1997, the rate was increased to 1.75 percent. 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 1996, 1995 and 1994 lost margins
and bonus incentives in 1997, 1996 and 1995, respectively. The Company
recorded revenues related to 1997, 1996, and 1995 lost margins and bonus
incentives of $1,150,000, $1,266,000, and $766,000, respectively. As these
costs are recovered through the monthly billing process, the amounts billed
are offset by the amortization of deferred CIP charges.
4. Common shares
New issuances -- On August 30, 1996, the Company filed a shelf registration
statement with the Securities and Exchange Commission for the issuance of
up to 1,000,000 common shares pursuant to the Company's Automatic Dividend
Reinvestment and Share Purchase Plan (the Plan), which will permit shares
purchased by shareholders, employees, or customers who participate in the
Plan to be either new issue common shares or common shares purchased on the
open market. In December 1996 the Company began issuing newly issued
common shares under the Plan; 161,831 common shares were issued in 1997 and
34,516 shares were issued in 1996. Additional common stock issuances in
1997 included 321,404 unregistered shares to effect the pooling
acquisitions, 30,561 shares to the Company's leveraged employee stock
ownership plan and 2,630 shares issued as a bonus to a consultant.
Shareholder Rights Plan -- On January 27, 1997, the Company's Board of
Directors declared a dividend of one preferred share purchase right (Right)
for each outstanding common share held of record as of February 10, 1997.
One Right was also issued with respect to each common share issued after
February 10, 1997. Each Right entitles the holder to purchase from the
Company one one-hundredth of a share of newly created Series A Junior
Participating Preferred Stock at a price of $70, subject to certain
adjustment. The Rights are exercisable when, and are not transferable
apart from the Company's common shares until, a person or group has
acquired 15 percent or more, or commenced a tender or exchange offer for
15 percent or more, of the Company's common shares. If the specified
percentage of the Company's common shares is acquired, each right will
entitle the holder (other than the acquiring person or group) to receive,
upon exercise, common shares of either the Company or the acquiring company
having value equal to two times the exercise price of the Right. The
Rights are redeemable by the Company's Board of Directors in certain
circumstances and expire on January 27, 2007.
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, 1997, were restricted by
$10,055,000.
6. Commitments
At December 31, 1997, the Company had commitments under contracts in
connection with construction programs aggregating approximately $3,551,000.
For capacity requirements the Company has agreements extending through
April 2005, at annual costs of approximately $4,700,000 in 1998, $4,800,000
in 1999, $2,300,000 in each year of 2000 through 2004 and $760,000 in 2005.
The Company also has several long-term coal contracts in which it 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.
At December 31, 1997, Midwest Information Systems, Inc., (MIS) had an
investment of $88,000 in a wireless communications limited liability
company (LLC) accounted for under the equity method. MIS may be required
to make additional capital contributions of $549,000. MIS has also
guaranteed $480,000 of the LLC's debt.
In 1996 the Big Stone Plant joint owners entered into operating leases for
250 new aluminum coal cars for transporting coal to Big Stone Plant. The
terms of the leases are 15 years. The new cars began transporting coal in
October 1996. In November 1997 Mid-States' medical imaging services
subsidiary entered into a sale/leaseback transaction whereby $16,000,000 of
diagnostic medical equipment was sold and leased back under two operating
leases with terms of three and four years. The amounts of future operating
lease payments are as follows:
Electric Subsidiary
utility companies Total
-------- ---------- -------
(in thousands)
1998 $ 939 $ 8,447 $ 9,386
1999 939 7,742 8,681
2000 939 7,249 8,188
2001 939 5,623 6,562
2002 939 1,913 2,852
Later Years 4,851 552 5,403
Rent expense was $6,714,000, $6,288,000, and $4,987,000 for 1997, 1996, and
1995, respectively.
7. Long-term obligations
Preferred shares -- 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, declining linearly to $100.00 at December 31, 2002.
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
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. Mid-States' ten year term
note and credit line borrowings are secured by a pledge of all of the
common stock of the companies owned by Mid-States. The aggregate amounts
of maturities and sinking fund requirements on bonds outstanding and other
long-term obligations at December 31, 1997, for each of the next five years
are $12,324,000 for 1998, $5,858,000 for 1999, $5,658,000 for 2000,
$5,283,000 for 2001, and $26,165,000 for 2002.
8. Pension plan and other postretirement benefits
The Company's noncontributory funded pension plan covers substantially all
electric utility employees. The plan provides 100 percent 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 cost was $1,104,000 for 1997, $1,292,000 for 1996, and
$1,009,000 for 1995.
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 1997, 1996, and 1995 includes the following
components:
1997 1996 1995
-------- -------- --------
(in thousands)
Service cost--benefit earned during the period $ 2,385 $ 2,273 $ 1,908
Interest cost on projected benefit obligation 7,131 6,754 6,511
-------- -------- --------
$ 9,516 $ 9,027 $ 8,419
(Gain) on return on assets (21,119) (15,738) (26,509)
Plus: net deferral and amortization 12,707 8,003 19,099
-------- -------- --------
Net periodic pension cost $ 1,104 $ 1,292 $ 1,009
======== ======== ========
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, 1997 and 1996, are as follows:
1997 1996
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 77,303 $ 72,243
Nonvested benefits 10,370 9,688
-------- --------
Accumulated benefit obligation $ 87,673 $ 81,931
======== ========
Projected benefit obligation $107,356 $100,664
Plan assets at fair value 137,560 121,506
-------- --------
Funded status $ 30,204 $ 20,842
Unrecognized transition asset (1,015) (1,251)
Unrecognized prior service cost 10,593 9,916
Unrecognized net actuarial (gain) (37,152) (25,773)
-------- --------
Net pension asset $ 2,630 $ 3,734
======== ========
The assumptions used for actuarial valuations were:
1997 1996
-------- --------
Discount rate 7.25% 7.25%
Rate of increase in future compensation level 4.25% 4.25%
Long-term rate of return on assets 8.50% 8.50%
In addition to providing pension benefits to all electric utility
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 1997,
1996 and 1995 was $482,000, $485,000, and $412,000, respectively. In the
second quarter of 1996 actuary reports for the Company's Executive Survivor
and Supplemental Retirement Program amended July 1, 1994, were revised to
reflect assumption changes regarding expected retirement age and projected
benefits under the July 1, 1994 plan amendment, which expanded the plan to
include nonofficer upper level management employees. The restatement
resulted in an expense adjustment of an additional $2,590,000, and a
reduction in earnings per share of $0.14 in 1996.
The funded status of the plan and amounts recognized on the balance sheet
at December 31, 1997 and 1996, are as follows:
1997 1996
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 5,051 $ 4,322
Nonvested benefits 448 686
-------- --------
Accumulated benefit obligation $ 5,499 $ 5,008
======== ========
Projected benefit obligation $ 6,964 $ 6,636
Plan assets at fair value -- --
-------- --------
Funded Status $ (6,964) $ (6,636)
Unrecognized transition obligation 62 82
Unrecognized prior service cost 1,647 1,774
Unrecognized net actuarial loss 615 487
Additional liability (715) (715)
-------- --------
Accrued benefit liability $ (5,355) $ (5,008)
======== ========
The assumptions used for actuarial valuations for 1997 and 1996 were a
discount rate of 7.25 percent and a salary scale rate increase of 5.0
percent.
In addition to providing pension benefits, the Company provides a portion
of health insurance benefits for retired employees. Substantially all of
the Company's electric utility employees may become eligible for health
insurance benefits if they reach age 55 and have 10 years of service.
Upon adoption of SFAS 106 - Employers' Accounting for Postretirement
Benefits Other Than Pensions - in January 1993, the Company elected to
recognize its transition obligation related to postretirement benefits
earned of approximately $14,964,000 over a period of 20 years.
The net postretirement benefit cost for 1997, 1996, and 1995 includes the
following components:
1997 1996 1995
-------- -------- --------
(in thousands)
Service cost - benefit earned during the period $ 578 $ 484 $ 411
Interest cost on accumulated postretirement
benefit obligation 1,159 1,132 1,187
Amortization of transition obligation 748 748 881
Amortization of experience (gain) (251) (210) (311)
Plan amendment prior service cost -- -- 2,155
Life insurance curtailment gain -- (749) --
------- ------- -------
Net postretirement benefit cost $ 2,234 $ 1,405 $ 4,323
======= ======= =======
The funded status of the plan and the amounts recognized on the balance
sheet at December 31, 1997 and 1996, are as follows:
1997 1996
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Retirees $ 10,209 $ 9,096
Fully eligible plan participants 4,483 4,582
Other active plan participants 3,015 2,645
-------- --------
Accumulated postretirement benefit obligation $ 17,707 $ 16,323
Plan assets at fair value -- --
-------- --------
Funded status $(17,707) $(16,323)
Unrecognized (gain) (3,449) (4,038)
Unrecognized transitional obligation 11,223 11,971
-------- --------
Postretirement benefit liability $ (9,933) $ (8,390)
======== ========
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 1997, was 7.5 percent
for 1998, decreasing linearly each successive year until it reaches 5.0
percent in 2003, after which it remains constant. The assumed health care
cost trend rate used in measuring the accumulated postretirement benefit
obligation as of December 31, 1996, was 7.0 percent for 1997, decreasing
linearly each successive year until it reaches 5.0 percent in 2001, after
which it remains constant. The assumed discount rate used in determining
the accumulated postretirement benefit obligation as of December 31, 1997
and 1996, was 7.25 percent. 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, 1997, by approximately 10.7
percent and the service and interest cost components of the net
postretirement health care cost in 1997 by approximately 16.5 percent.
The Company has a leveraged employee stock ownership plan (ESOP) for the
benefit of all its electric utility employees. Contributions made by the
Company were $1,055,000 for 1997, $1,010,000 for 1996, and $993,000 for
1995.
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, 1997, 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 $40,000,000 of which
$2,100,000 was used at December 31, 1997. The subsidiary companies' bank
lines and letters of credit, which require no compensating balances,
totaled $17,500,000 of which $3,115,000 was used at December 31, 1997.
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.
Other investments -- The carrying amount approximates fair value. A portion
of other investments is 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. About $26 million of the Company's long term debt,
which is subject to variable interest rates, approximates fair value.
1997 1996
-------------------- --------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
-------- -------- -------- --------
Cash and short-term investments $ 5,301 $ 5,301 $ 2,130 $ 2,130
Other investments 20,048 20,048 20,549 20,549
Redeemable preferred stock (18,000) (19,619) (18,000) (18,000)
Long-term debt (189,973) (207,063) (163,176) (170,483)
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 in
accumulated other comprehensive income in the equity section of the balance
sheet net of deferred income taxes of $257,000 at year-end 1997 and
$431,000 at year-end 1996. Realized gains and losses are computed on each
specific investment sold. The amounts recognized on the balance sheet as
of December 31, 1997 and 1996, and amounts sold for each year are as
follows:
1997 1996
-------- --------
Available for sale - securities (in thousands)
Cost $ 83 $ 161
Gross unrealized gain 620 1,050
Gross unrealized loss -- --
------- -------
Fair value $ 703 $ 1,211
======= =======
Proceeds from sale $ 785 $ --
Gross realized gains 707 --
Gross realized losses -- --
11. Income taxes
The total income tax expense differs from the amount computed by applying
the federal income tax rate (35 percent in 1997, 1996 and 1995) to net
income before total income tax expense for the following reasons:
1997 1996 1995
-------- -------- --------
(in thousands)
Tax computed at federal statutory rate $16,329 $15,378 $15,786
Increases (decreases) in tax from:
State income taxes net of federal
income tax benefit 2,224 1,835 2,097
Investment tax credit amortization (1,186) (1,186) (1,177)
Depreciation differences --
flow-through method reversal 408 (138) 222
Differences reversing in excess of federal rates (994) (1,030) (754)
Dividend received/paid deduction (620) (604) (872)
Affordable housing tax credits (1,057) (593) (93)
Permanent and other differences (796) 348 950
------- ------- -------
Total Income tax expense $14,308 $14,010 $16,159
======= ======= =======
Overall effective federal and state
income tax rate 30.7% 31.4% 35.8%
Income tax expense includes the following:
Charges (credits) related to operations:
Current federal income taxes $17,123 $18,014 $13,840
Current state income taxes 3,300 3,608 3,201
Deferred federal income taxes (3,410) (4,657) 603
Deferred state income taxes (205) (480) 117
Investment tax credit amortization (1,186) (1,186) (1,177)
------- ------- -------
Total $15,622 $15,299 $16,584
------- ------- -------
Charges (credits) related to other income
and deductions:
Current federal income taxes (645) (430) (176)
Affordable housing tax credits (1,057) (593) (93)
Current state income taxes 19 (103) (21)
Deferred federal and state income taxes 369 (163) (135)
------- ------- -------
Total Income tax expense $14,308 $14,010 $16,159
======= ======= =======
The Company's deferred tax assets and liabilities were composed of the
following on December 31, 1997 and 1996:
1997 1996
---------- ----------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 12,258 $ 13,021
Vacation accrual 1,121 1,039
Unbilled/unearned revenue 4,105 4,452
Operating reserves 7,890 6,872
Nondeductible land - plant abandonment -- 1,134
Transfer to regulatory asset (61) (617)
Other 1,747 1,646
--------- ---------
Total deferred tax assets $ 27,060 $ 27,547
Deferred tax liabilities
Differences related to property (111,300) (114,090)
Excess tax over book - pensions (1,043) (1,481)
Transfer to regulatory asset (4,999) (4,012)
Transfer to regulatory liability (188) 204
Other (2,375) (2,749)
--------- ---------
Total deferred tax liabilities $(119,905) $(122,128)
--------- ---------
Deferred income taxes $ (92,845) $ (94,581)
========= =========
12. Property, plant and equipment
1997 1996
-------- --------
(December 31, in thousands)
Electric Plant:
Production $305,147 $305,472
Transmission 141,956 137,539
Distribution 227,463 217,825
General 83,985 81,229
-------- --------
Electric plant 758,551 742,065
Less accumulated depreciation and amortization 315,011 301,380
-------- --------
Electric plant net of accumulated depreciation 443,540 440,685
Construction work in progress 12,146 11,470
-------- --------
Net electric plant $455,686 $452,155
-------- --------
Subsidiary companies plant $ 89,716 $101,789
Less accumulated depreciation and amortization 35,636 28,999
-------- --------
Net subsidiary companies plant $ 54,080 $ 72,790
-------- --------
Net plant $509,766 $524,945
======== ========
<TABLE>
13. Quarterly information (unaudited)
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
-------------- -------------- --------------- ---------------
1997 1996 1997 1996 1997 1996 1997 1996
------ ------ ------ ------ ------- ------ ------- ------
(in thousands except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $94,289 $90,568 $91,096 $91,874 $101,858 $95,276 $107,036 $93,215
Operating income $19,741 $19,057 $ 9,798 $12,642 $ 13,753 $12,868 $ 15,742 $14,805
Net income $10,690 $10,195 $ 5,393 $ 6,273 $ 7,785 $ 6,739 $ 8,478 $ 7,417
Earnings available for common shares $10,101 $ 9,605 $ 4,803 $ 5,684 $ 7,195 $ 6,149 $ 7,889 $ 6,828
Basic and diluted earnings per share $ .87 $ .84 $ .41 $ .49 $ .62 $ .53 $ .67 $ .59
Dividends paid per common share $ .465 $ .45 $ .465 $ .45 $ .465 $ .45 $ .465 $ .45
Price range:
High $34 3/4 $38 5/8 $34 1/4 $38 5/8 $34 1/2 $34 1/2 $38 3/8 $34 1/4
Low $31 1/2 $35 1/4 $30 $32 $31 1/2 $31 3/4 $32 1/8 $32
Average number of common
shares outstanding 11,569 11,502 11,621 11,502 11,661 11,502 11,704 11,509
Initially the Company did not intend to restate prior year's consolidated financial statements for the
Peoples' pooling because its impact alone on 1996 consolidated results was not considered significant.
However, the Chassis Liner pooling in June of 1997 was considered to have a significant enough pro forma
effect on 1996 consolidated results to warrant restatement. For reasons of consistency, the Company's
1996 consolidated financial statements presented herein have been restated to include both Peoples and
Chassis Liner. However, the Company's 1995 consolidated financial statements and other financial
information for 1995 and prior years presented herein have not been restated to reflect the effects of
the poolings because the impact of the poolings on those years is not material. (See note 2 to
financial statements for more information.)
</TABLE>
- -----------------------------------------------------------------------
Stock listing
- -------------
Otter Tail common stock is traded on The Nasdaq Stock Market's National
Market. (Nasdaq: National Association of Securities Dealers Automated
Quotation.)
Exhibit 21-A
OTTER TAIL POWER COMPANY
Subsidiaries of the Registrant
March 1, 1998
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
Peoples Telephone of Bigfork Minnesota
Data Video Systems, Inc. Minnesota
Otter Tail Communications SD, Inc. South Dakota
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
Dakota Engineering, Inc. North Dakota
Aerial Contractors, Inc. North Dakota
Moorhead Electric, Inc. Minnesota
KFGO, Inc. North Dakota
Western Minnesota Broadcasting Company Minnesota
Diagnostic Medical Systems, Inc. North Dakota
DMS Imaging, Inc. North Dakota
DMS Leasing Corporation North Dakota
BTD Manufacturing, Inc. Minnesota
Northern Pipe Products, Inc. North Dakota
Northern Micro, Inc. North Dakota
Fargo Baseball, LLC Minnesota
Fargo Sports Concession LLC Minnesota
Chassis Liner Corporation Minnesota
Otter Tail Energy Services Company, Inc. Minnesota
Mid-States Testing Company Minnesota
*Inactive
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
Nos. 333-11145 on Form S-3 and 333-25261 on Form S-8 of Otter Tail
Power Company of our report dated February 2, 1998, incorporated by
reference in this Annual Report on Form 10-K of Otter Tail Power
Company for the year ended December 31, 1997.
Deloitte & Touche LLP
Minneapolis, Minnesota
March 26, 1998
Exhibit 24-A
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, 1997, 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: January 8, 1998.
____Jeffrey J. Legge____
Jeffrey J. Legge
In Presence of:
Anita Anderson
__________________
Denise Herness
__________________
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, 1997, 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: January 9, 1998.
____John C. MacFarlane____
John C. MacFarlane
In Presence of:
Dee Fletcher
__________________
Tom Hoxie
__________________
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, 1997, 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: January 13, 1998
____Robert N. Spolum____
Robert N. Spolum
In Presence of:
Ilene Berg
__________________
Dave Fining
__________________
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, 1997, 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: January 16, 1998.
____Nathan I. Partain____
Nathan I. Partain
In Presence of:
Connie M. Lueche
__________________
Ellen Rember
__________________
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, 1997, 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: January 16, 1998.
____Dayle Dietz____
Dayle Dietz
In Presence of:
Leo Johnson
__________________
Janet L. Johnson
__________________
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, 1997, 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: January 9, 1998.
____Arvid R. Liebe____
Arvid R. Liebe
In Presence of:
Renee Thomas
__________________
Sheri Hammer
__________________
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, 1997, 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: January 9, 1998.
____Thomas M. Brown____
Thomas M. Brown
In Presence of:
Donna M. Hull
__________________
Cheryl A. Fields
__________________
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, 1997, 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: January 8, 1998.
____Maynard D. Helgaas____
Maynard D. Helgaas
In Presence of:
Tom Schneider
__________________
Becky Luhning
__________________
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, 1997, 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: January 19, 1998
____Kenneth L. Nelson____
Kenneth L. Nelson
In Presence of:
Mike Holper
__________________
Wayne Cagheny
__________________
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, 1997, 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: January 9, 1998
____Dennis R. Emmen____
Dennis R. Emmen
In Presence of:
Penny Mosher
__________________
Lori Dawkins
__________________
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, 1997, 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: January 15, 1998.
____A. E. Anderson____
A. E. Anderson
In Presence of:
Penny Mosher
__________________
Nancy D. Tollerson
__________________
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, 1997,
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: January 29, 1998.
____Jay D. Myster____
Jay D. Myster
In Presence of:
Penny Mosher
__________________
Becky Luhning
__________________
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Exhibit 27
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of December 31, 1997, and the Consolidated
Statement of Income for the twelve months ended December 31, 1997, 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-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 455,687
<OTHER-PROPERTY-AND-INVEST> 100,970
<TOTAL-CURRENT-ASSETS> 85,790
<TOTAL-DEFERRED-CHARGES> 12,994
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 655,441
<COMMON> 58,655
<CAPITAL-SURPLUS-PAID-IN> 35,196
<RETAINED-EARNINGS> 116,305
<TOTAL-COMMON-STOCKHOLDERS-EQ> 210,156
18,000
20,831
<LONG-TERM-DEBT-NET> 189,973
<SHORT-TERM-NOTES> 2,100
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 12,324
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 202,057
<TOT-CAPITALIZATION-AND-LIAB> 655,441
<GROSS-OPERATING-REVENUE> 394,279
<INCOME-TAX-EXPENSE> 14,308
<OTHER-OPERATING-EXPENSES> 335,246
<TOTAL-OPERATING-EXPENSES> 349,554
<OPERATING-INCOME-LOSS> 44,725
<OTHER-INCOME-NET> 6,140
<INCOME-BEFORE-INTEREST-EXPEN> 50,865
<TOTAL-INTEREST-EXPENSE> 18,519
<NET-INCOME> 32,346
2,358
<EARNINGS-AVAILABLE-FOR-COMM> 29,988
<COMMON-STOCK-DIVIDENDS> 21,496
<TOTAL-INTEREST-ON-BONDS> 16,941
<CASH-FLOW-OPERATIONS> 69,398
<EPS-PRIMARY> 2.58
<EPS-DILUTED> 2.58
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Exhibit 27-1
Restated summary information extracted from the restated Consolidated
Balance Sheets as of 3-31-96, 6-30-96, 9-30-96, 12-31-96, and the
restated Consolidated Statements of Income for the 3, 6, 9, and 12-month
periods ended 3-31-96, 6-30-96, 9-30-96, and 12-31-96, respectively.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C> <C> <C> <C>
<PERIOD-TYPE> 3-MOS 6-MOS 9-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1996 DEC-31-1996 DEC-31-1996 DEC-31-1996
<PERIOD-END> MAR-31-1996 JUN-30-1996 SEP-30-1996 DEC-31-1996
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 440,439 447,250 449,718 452,155
<OTHER-PROPERTY-AND-INVEST> 87,015 107,707 116,613 121,846
<TOTAL-CURRENT-ASSETS> 84,940 86,175 81,140 81,912
<TOTAL-DEFERRED-CHARGES> 12,069 11,514 11,428 13,791
<OTHER-ASSETS> 0 0 0 0
<TOTAL-ASSETS> 624,463 652,646 658,899 669,704
<COMMON> 57,508 57,508 57,508 57,680
<CAPITAL-SURPLUS-PAID-IN> 28,949 28,949 28,949 29,885
<RETAINED-EARNINGS> 105,236 105,764 106,653 107,864
<TOTAL-COMMON-STOCKHOLDERS-EQ> 191,693 192,221 193,110 195,429
18,000 18,000 18,000 18,000
20,831 20,831 20,831 20,831
<LONG-TERM-DEBT-NET> 172,777 183,846 189,702 163,176
<SHORT-TERM-NOTES> 0 2,450 4,650 7,200
<LONG-TERM-NOTES-PAYABLE> 0 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 10,300 15,700 18,400
<LONG-TERM-DEBT-CURRENT-PORT> 20,014 25,131 18,859 42,587
0 0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0 0 0
<LEASES-CURRENT> 0 0 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 201,148 199,867 198,047 204,081
<TOT-CAPITALIZATION-AND-LIAB> 624,463 652,646 658,899 669,704
<GROSS-OPERATING-REVENUE> 90,568 182,442 277,718 370,933
<INCOME-TAX-EXPENSE> 5,619 8,365 10,337 14,010
<OTHER-OPERATING-EXPENSES> 71,512 150,743 233,151 311,561
<TOTAL-OPERATING-EXPENSES> 77,131 159,108 243,488 325,571
<OPERATING-INCOME-LOSS> 13,437 23,334 34,230 45,362
<OTHER-INCOME-NET> 492 905 1,091 2,125
<INCOME-BEFORE-INTEREST-EXPEN> 13,929 24,239 35,321 47,487
<TOTAL-INTEREST-EXPENSE> 3,734 7,771 12,114 16,863
<NET-INCOME> 10,195 16,468 23,207 30,624
590 1,179 1,769 2,358
<EARNINGS-AVAILABLE-FOR-COMM> 9,605 15,289 21,438 28,266
<COMMON-STOCK-DIVIDENDS> 5,031 10,062 15,093 20,124
<TOTAL-INTEREST-ON-BONDS> 3,675 7,635 11,774 16,026
<CASH-FLOW-OPERATIONS> 14,602 26,322 49,682 69,398
<EPS-PRIMARY> 0.84 1.33 1.86 2.46
<EPS-DILUTED> 0.84 1.33 1.86 2.46
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Exhibit 27-2
Restated summary financial information extracted from the restated
Consolidated Balance Sheets as of 3-31-97, 6-30-97, and 9-30-97,
respectively.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C> <C> <C>
<PERIOD-TYPE> 3-MOS 6-MOS 9-MOS
<FISCAL-YEAR-END> DEC-31-1997 DEC-31-1997 DEC-31-1997
<PERIOD-END> MAR-31-1997 JUN-30-1997 SEP-30-1997
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 453,025 456,082 456,926
<OTHER-PROPERTY-AND-INVEST> 120,683 121,443 117,798
<TOTAL-CURRENT-ASSETS> 86,170 84,700 90,158
<TOTAL-DEFERRED-CHARGES> 12,633 13,810 13,666
<OTHER-ASSETS> 0 0 0
<TOTAL-ASSETS> 672,511 676,035 678,548
<COMMON> 58,052 58,251 58,462
<CAPITAL-SURPLUS-PAID-IN> 31,788 32,856 34,036
<RETAINED-EARNINGS> 112,688 111,977 113,754
<TOTAL-COMMON-STOCKHOLDERS-EQ> 202,528 203,084 206,252
18,000 18,000 18,000
20,831 20,831 20,831
<LONG-TERM-DEBT-NET> 164,862 162,726 162,687
<SHORT-TERM-NOTES> 800 2,400 4,400
<LONG-TERM-NOTES-PAYABLE> 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 16,400 25,800 24,700
<LONG-TERM-DEBT-CURRENT-PORT> 48,076 46,449 43,905
0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0 0
<LEASES-CURRENT> 0 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 201,014 196,745 197,773
<TOT-CAPITALIZATION-AND-LIAB> 672,511 676,035 678,548
<GROSS-OPERATING-REVENUE> 94,289 185,385 287,243
<INCOME-TAX-EXPENSE> 5,631 7,142 10,953
<OTHER-OPERATING-EXPENSES> 74,548 155,847 243,952
<TOTAL-OPERATING-EXPENSES> 80,179 162,989 254,905
<OPERATING-INCOME-LOSS> 14,110 22,396 32,338
<OTHER-INCOME-NET> 1,122 2,825 5,397
<INCOME-BEFORE-INTEREST-EXPEN> 15,232 25,221 37,735
<TOTAL-INTEREST-EXPENSE> 4,542 9,138 13,867
<NET-INCOME> 10,690 16,083 23,868
589 1,179 1,769
<EARNINGS-AVAILABLE-FOR-COMM> 10,101 14,904 22,099
<COMMON-STOCK-DIVIDENDS> 5,309 10,637 16,058
<TOTAL-INTEREST-ON-BONDS> 4,187 8,414 12,679
<CASH-FLOW-OPERATIONS> 16,080 25,519 42,872
<EPS-PRIMARY> 0.87 1.29 1.90
<EPS-DILUTED> 0.87 1.29 1.90
</TABLE>
