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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One) (X) Annual Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended DECEMBER 31, 2002
OR
( ) Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from _______to_______
Commission File Number 0-368
OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter)
MINNESOTA 41-0462685
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
215 SOUTH CASCADE STREET 56538-0496
BOX 496, FERGUS FALLS, MINNESOTA (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: 866-410-8780
Securities registered pursuant to Name of each exchange
Section 12(b) of the Act: on which registered
Title of each class 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 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 _____)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of the registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ( )
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). (Yes X No _____)
The aggregate market value of the voting stock held by nonaffiliates on June 28,
2002 was $784,354,838.
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of the latest practicable date: 25,593,524 COMMON SHARES
($5 PAR VALUE) AS OF FEBRUARY 28, 2003.
Documents Incorporated by Reference:
2002 ANNUAL REPORT TO SHAREHOLDERS-PORTIONS INCORPORATED BY REFERENCE INTO
PARTS I AND II
PROXY STATEMENT DATED MARCH 6, 2003-PORTIONS INCORPORATED BY REFERENCE INTO PART
III
PART I
Item 1. BUSINESS
(a) General Development of Business
Otter Tail Corporation (the Company) was incorporated in 1907 under the
laws of the State of Minnesota. The Company's executive offices are located at
215 South Cascade Street, Box 496, Fergus Falls, Minnesota 56538-0496 and 3203
32nd Avenue South, P.O. Box 9156, Fargo, North Dakota 58106-9156. Its telephone
number is (866) 410-8780.
The Company makes available free of charge at its internet website
(www.ottertail.com) its annual reports on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K and any amendments to these reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 as soon as reasonably practicable after such material is electronically
filed with or furnished to the Securities and Exchange Commission. Information
on the Company's website is not deemed to be incorporated by reference into this
Annual Report on Form 10-K.
In the late 1980s, the Company determined that its core electric business
was located in a region of the country where there was little or no growth in
the demand for electricity. In order to maintain growth for shareholders, Otter
Tail Power Company (as the Company was known) began to explore opportunities for
the acquisition and long-term ownership of nonelectric businesses. This strategy
has resulted in steady growth over the years. In 2001, the name of the Company
was changed to "Otter Tail Corporation" to more accurately represent the broader
scope of electric and nonelectric operations and the name "Otter Tail Power
Company" was retained for use by the electric utility. In 2002, approximately
57% of the Company's consolidated revenues and approximately 31% of the
Company's consolidated net income came from nonelectric operations.
The Company's strategy is focused on the growth of its operating
companies. The Company's goal is to create value and growth through the
acquisition, long-term ownership and decentralized operation of diverse
businesses. The Company's electric utility provides a steady base of revenues
and earnings as part of this strategy. The following guidelines are considered
when reviewing potential acquisition candidates:
o Emerging or middle market company;
o Proven entrepreneurial management team that will remain after the
acquisition;
o Products and services intended for commercial rather than retail consumer
use;
o The potential to provide immediate earnings and future growth; and
o Preference for 100% ownership of acquired entities.
The Company assesses the performance of its operating companies' return on
capital and will consider divesting under-performing operating companies.
Otter Tail Corporation and its subsidiaries conducted business in 48 states
and 6 Canadian provinces and had approximately 3,111 full-time employees at
December 31, 2002. The businesses of the Company have been classified into five
segments: Electric, Plastics, Manufacturing, Health Services and Other Business
Operations.
o Electric (the Utility) includes the production, transmission, distribution
and sale of electric energy in Minnesota, North Dakota
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and South Dakota under the name Otter Tail Power Company. Electric utility
operations have been the Company's primary business since incorporation.
o Plastics consists of businesses producing polyvinyl chloride pipe in the
Upper Midwest, West, Southwest and South-central regions of the United
States.
o Manufacturing consists of businesses in the following manufacturing
activities: production of waterfront equipment, wind towers,
frame-straightening equipment and accessories for the auto repair industry,
custom plastic pallets, material and handling trays and horticultural
containers; fabrication of steel products; contract machining; and metal
parts stamping and fabrication. These businesses are located primarily in
the Upper Midwest and Utah.
o Health Services consists of businesses involved in the sale of diagnostic
medical equipment, supplies and accessories. These businesses also provide
service maintenance, mobile and fixed-based diagnostic services, portable
X-ray imaging and interim rental of diagnostic medical imaging equipment to
various medical institutions located in 40 states.
o Other Business Operations consists of businesses in electrical and
telephone construction contracting, transportation, telecommunications,
entertainment and energy services and natural gas marketing as well as the
portion of corporate administrative and general expenses that are not
allocated to other segments. These businesses operate primarily in the
Upper Midwest, except for the transportation company which operates in 48
states and 6 Canadian provinces.
The Company's electric operations, including wholesales power sales, are
operated as a division of Otter Tail Corporation, and the Company's energy
services and natural gas marketing operations are operated as indirect
subsidiaries of Otter Tail Corporation. Substantially all the other businesses
are owned by the Company's wholly owned subsidiary, Varistar Corporation
(Varistar).
The Company continues to investigate acquisitions of additional nonelectric
businesses and expects continued growth in this area. The following acquisitions
were completed during 2002:
o On May 1, 2002 the Company acquired the stock of Computed Imaging Services,
Inc. (CIS) of Houston, Texas for 158,257 shares of Otter Tail Corporation
common stock and approximately $1.2 million in cash. CIS provides computed
tomography and magnetic resonance imaging mobile services, interim rental,
and sales and service of new, used and refurbished diagnostic imaging
equipment to hospitals and other healthcare facilities in the south central
United States. The acquisition of CIS allows the Company to expand its
existing Health Services operations into another region of the country. CIS
annual revenues were approximately $5.9 million in 2001.
o On May 28, 2002 the Company acquired the stock of ShoreMaster, Inc. of
Fergus Falls, Minnesota for 303,124 shares of the Company's common stock
and $2.3 million in cash. ShoreMaster is a leading manufacturer of
waterfront equipment ranging from residential-use boatlifts and docks to
commercial marina systems. The acquisition of ShoreMaster is expected to
provide diversification and growth opportunities for the Company's
Manufacturing segment. ShoreMaster's annual revenues were approximately $20
million in 2001.
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o On October 1, 2002 the Company acquired the stock of Galva Foam Marine
Industries, Inc. of Camdenton, Missouri for 256,940 shares of the Company's
common stock and approximately $1.0 million in cash. Galva Foam is a
leading manufacturer of waterfront equipment ranging from residential
boatlifts and docks to commercial marina systems. The acquisition of Galva
Foam, in combination with the ShoreMaster acquisition, will expand the
market reach of the Company's waterfront manufacturing product line
nationwide with both saltwater and freshwater products. Galva Foam had
annual revenues of approximately $13 million in 2001.
o In 2002, the Company also acquired two other businesses, neither of which
was individually material, one in energy management services and the other
in health services. The total purchase price for these businesses was
approximately $2 million in cash.
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 18 through 30 of the Company's 2002 Annual
Report to Shareholders, filed as an Exhibit hereto.
(b) Financial Information About Industry Segments
The Company is engaged in businesses that have been classified into five
segments: Electric, Plastics, Manufacturing, Health Services and Other Business
Operations. Financial information about the Company's segments is incorporated
by reference to note 2 of "Notes to Consolidated Financial Statements" on pages
38 through 49 of the Company's 2002 Annual Report to Shareholders, filed as an
Exhibit hereto.
(c) Narrative Description of Business
ELECTRIC
General
The Utility, which conducts business under the name of Otter Tail Power
Company, provides electricity to more than 127,000 customers in a 50,000 square
mile area of Minnesota, North Dakota and South Dakota. The Company derived 43%
of its consolidated operating revenues from the Electric segment in 2002, 47% in
2001 and 45% in 2000. In 2002, approximately 50.5% of retail electric revenues
came from Minnesota, 41.2% from North Dakota and 8.3% from South Dakota compared
to 50.9% from Minnesota, 41.2% from North Dakota and 7.9% from South Dakota for
2001.
The territory served by the Utility 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, 29.1% of 2002 electric revenue was derived from commercial
customers, 25.0% from residential customers, 15.8% from industrial customers and
30.1% from other sources, including municipalities, farms and wholesale sales.
For 2001, electric revenue by category was 26.6% from commercial customers,
23.4% from residential, 15.4% from industrial and 34.6% from other sources.
Wholesale electric energy sales increased from 44.0% of total kwh sales in
2001 to 45.2% of total kwh sales in 2002. While wholesale electric energy kwh
sales grew 7.8% between the years, revenue per kwh decreased by 22.5% resulting
in a reduction of wholesale energy gross margins. Activity in the short-term
energy market is subject to change based on a number of factors and it is
difficult to predict the quantity of wholesale power sales or prices for
wholesale power in the future. However, the Company expects that market
conditions for wholesale power transactions in 2003 will be similar to the
conditions that existed in 2002.
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The aggregate population of the Utility's retail electric service area
is approximately 230,000. In this service area of 423 communities and adjacent
rural areas and farms, approximately 130,900 people live in communities having a
population of more than 1,000, according to the 2000 census. The only
communities served which have a population in excess of 10,000 are Jamestown,
North Dakota (15,527); Fergus Falls, Minnesota (13,471); and Bemidji, Minnesota
(11,917). As of December 31, 2002 the Utility served 127,157 customers. This is
an increase of 539 customers from December 31, 2001.
Capability and Demand
At December 31, 2002 the Utility had base load net plant capability
totaling 563,258 kw, consisting of 253,508 kw from the jointly-owned Big Stone
Plant (constituting the Utility's 53.9% share of the plant's total capability),
154,350 kw from the Hoot Lake Plant (owned solely by the Utility), 149,450 kw
from the jointly-owned Coyote Station (constituting the Utility's 35% share of
the station's total capability), and, under contract, 5,950 kw from a
co-generation plant near Bemidji, Minnesota. In addition to its base load
capability, the Utility has combustion turbine and small diesel units, used
chiefly for peaking and standby purposes, with a total capability of 92,855 kw,
and hydroelectric capability of 4,336 kw. During 2002, the Utility generated
about 78% of its retail kwh sales and purchased the balance.
The Utility has arrangements to help meet its future base load
requirements and continues to investigate other means for meeting such
requirements. The Utility has under construction a gas-fired combustion turbine
expected to be operational by June 1, 2003. The unit will have a total
capability between 40,000 and 50,000 kw. The Utility has an agreement with
another utility for the annual exchange of 75,000 kw of seasonal capacity which
runs through October 2004. The Utility has an agreement to purchase 50,000 kw of
year-round capacity which extends through April 30, 2005 and another agreement
to purchase 50,000 kw of year-round capacity through April 30, 2010 from another
utility. The Utility had a seasonal capacity agreement to purchase 50,000 kw for
the summer 2002. The Utility has a direct control load management system which
provides some flexibility to the Utility to effect reductions of peak load. The
Utility, in addition, offers rates to customers which encourage off-peak usage.
The Utility traditionally experiences its peak system demand during the
winter season. For the year ended December 31, 2002, the Utility experienced a
system peak demand of 640,220 kw on February 4, 2002. The highest sixty-minute
peak demand ever was 642,826 kw on December 14, 2000. The Utility's capability
of meeting system demand at the time of the peak in February 2002, including
power purchase agreements, its own generating capacity and reserve requirements
computed in accordance with accepted industry practice, amounted to 843,969 kw.
The Utility's additional capacity available under power purchase contracts (as
described above), combined with generating capability and load management
control capabilities, is expected to meet 2003 system demand, including industry
reserve requirements.
Fuel Supply
Coal is the principal fuel burned at the Big Stone, Coyote and Hoot
Lake generating plants. Coyote, a mine-mouth facility, burns North Dakota
lignite coal. Hoot Lake and Big Stone plants burn western subbituminous coal.
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The following table shows the sources of energy used to generate the Utility's
net output of electricity for 2002 and 2001:
2002 2001
------------------------- ------------------------
Net Kilowatt % of Total Net Kilowatt % of Total
Hours Kilowatt Hours Kilowatt
Generated Hour Generated Hour
Sources (Thousands) Generated (Thousands) Generated
------- ------------ ---------- ------------ ----------
Subbituminous Coal..... 2,459,046 69.3% 2,663,298 70.7%
Lignite Coal........... 1,063,942 30.0 1,075,545 28.6
Hydro.................. 24,220 .7 23,531 .6
Oil.................... 1,205 .0 2,891 .1
--------- ----- --------- -----
Total.................. 3,548,413 100.0% 3,765,265 100.0%
========= ===== ========= =====
The Utility has a primary coal supply agreement with RAG Coal West,
Inc. for the supply of Wyoming subbituminous coal to Big Stone Plant for
2003-2004. Purchases are made for the supply of subbituminous coal for the Hoot
Lake Plant under a contract with Kennecott Coal Sales Company expiring June 30,
2004. A lignite coal contract with Dakota Westmoreland Corporation for the
Coyote Station expires in 2016, with a 15-year renewal option subject to certain
contingencies.
It is the Utility's practice to maintain minimum 30-day inventory (at
full output) of coal at the Big Stone Plant, a 20-day inventory at the Coyote
Station and a 10-day inventory at the Hoot Lake Plant.
Railroad transportation services to the Big Stone Plant are being
provided under a common carrier rate by the Burlington Northern and Santa Fe
Railroad Co. The Company has filed a complaint in regard to this rate with the
Surface Transportation Board requesting the Board set a competitive rate. The
Surface Transportation Board is not likely to act on this complaint until late
in 2004. The Company would expect the outcome of the proceeding to have a
favorable impact on its fuel costs for Big Stone Plant. An agreement is in place
with the Burlington Northern and Santa Fe Railroad for Hoot Lake Plant which
expires in mid-2004. No coal transportation agreement is needed for the Coyote
Station due to its location next to a coal mine.
The average cost of coal consumed (including handling charges to the
plant sites) per million BTU for each of the three years 2002, 2001 and 2000 was
$1.125, $1.014 and $.994, respectively.
The Utility is permitted by the State of South Dakota to burn some
alternative fuels, including tire derived fuel, at the Big Stone Plant. The
quantity of alternative fuel burned at the Big Stone Plant is insignificant when
compared to the total annual coal consumption at the Big Stone Plant.
General Regulation
The Utility is subject to regulation of rates and other matters in each
of the three states in which it operates and by the federal government for
certain interstate operations. A breakdown of electric rate regulation by each
jurisdiction is as follows:
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2002 2001
----------------- -------------------
% of % of % of % of
Electric kwh Electric kwh
Rates Regulation Revenues Sales Revenues Sales
----- ---------- -------- -------- -------- --------
MN retail sales MN Public Utilities
Commission 35.8% 28.3% 33.8% 29.3%
ND retail sales ND Public Service
Commission 29.2 21.9 27.4 22.4
SD retail sales SD Public Utilities
Commission 5.8 4.5 5.3 4.3
Transmission & Federal Energy
sales for resale Regulatory Commission 29.2 45.3 33.5 44.0
----- ----- ----- -----
100.0% 100.0% 100.0% 100.0%
===== ===== ===== =====
The Utility operates under approved retail electric tariffs in all
three states it serves. The Utility has an obligation to serve any customer
requesting service within its assigned service territory. Accordingly, the
Utility has designed its electric system to provide continuous service at time
of peak usage. The pattern of electric usage can vary dramatically during a 24
hour period and from season to season. The Utility's tariffs provide for
continuous electric service and are designed to cover the costs of service
during peak times. To the extent that peak usage can be reduced or shifted to
periods of lower usage, the cost to serve all customers is reduced. In order to
shift usage from peak times, the Utility has approved tariffs in all three
states for lower rates for residential demand control and controlled service, in
Minnesota and North Dakota for real-time pricing, and in North Dakota and South
Dakota for bulk interruptible rates. Each of these special rates is designed to
improve efficient use of the Utility facilities, while encouraging use of
cost-effective electricity instead of other fuels and giving customers more
control over the size of their electric bill. In all three states, the Utility
has approved tariffs which allow qualifying customers to release and sell energy
back to the Utility when wholesale energy prices make such transactions
desirable.
The majority of the Utility's electric retail rate schedules now in
effect provide for adjustments in rates based on the cost of fuel delivered to
the Utility's generating plants, as well as for adjustments based on the cost of
electric energy purchased by the Company. Such adjustments are presently based
on a two-month moving average in Minnesota and under FERC, a three-month moving
average in South Dakota and a four-month moving average in North Dakota. These
adjustments are applied to the next billing after becoming applicable.
The following summarizes the material regulations of each jurisdiction
applicable to the Utility's electric operations, as well as the specific
electric rate proceedings during the last three years with the Minnesota Public
Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC),
the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy
Regulatory Commission (FERC). The Company's nonelectric businesses are not
subject to direct regulation by any of these agencies.
Minnesota: Under the Minnesota Public Utilities Act, the Utility 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 Utility
has not had a significant rate proceeding before the MPUC since July 1987.
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The Department of Commerce (DOC) is responsible for investigating all
matters subject to the jurisdiction of the DOC or the MPUC, and for the
enforcement of MPUC orders. Among other things, the DOC 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 DOC acts as a state advocate
in matters heard before the MPUC. The DOC also has the power, in the event of
energy shortage or for a long-term basis, to prepare and adopt regulations to
conserve and allocate energy.
Under Minnesota law, every regulated 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 DOC may require the utility 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 DOC 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. Since 1995, the Utility has recovered
demand-side management related costs not included in base rates under
Minnesota's Conservation Improvement Programs through the use of an annual
recovery mechanism approved by the MPUC.
The MPUC requires the submission of a 15-year advance integrated
resource plan by utilities serving at least 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 are binding for jurisdictional
utilities. Typically, the filings are submitted every two years. The Utility's
most recent plan was submitted to the MPUC in 2002 and was approved early in
2003. The MPUC also granted the Utility a one-year waiver in submitting its next
integrated resource plan, which will be completed in 2005.
The MPUC requires the annual filing of a capital structure petition. In
this filing the MPUC reviews and approves the capital structure for the Company.
Once the petition is approved, the Company may issue securities without further
petition or approval, provided the issuance is consistent with the purposes and
amounts set forth in the approved capital structure petition. The Company's
current capital structure petition is in effect until March 31, 2003. The
Company filed its capital structure petition for 2003 on January 31, 2003 and is
awaiting action from the MPUC.
The Minnesota legislature has enacted a statute that favors
conservation over the addition of new resources. In addition, it has mandated
the use of renewable resources where new supplies are needed, unless the utility
proves that a renewable energy facility is not in the public interest. It has
effectively prohibited the building of new nuclear facilities. An existing
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 outside of the state) or any
rate recovery therefrom, and may 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.
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
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hearings, to select or designate sites in Minnesota for new electric power
generating plants (50,000 kw or more) and routes for transmission lines (100 kv
or more) and to certify such sites and routes as to environmental compatibility.
The Minnesota Legislature enacted the Minnesota Energy Security and
Reliability Act in 2001. Its primary focus was to streamline the siting and
routing processes for the construction of new electric generation and
transmission projects. The bill also added to utility requirements for renewable
energy and energy conservation.
North Dakota: The Utility is subject to the jurisdiction of the NDPSC
with respect to rates, services, certain issuances of securities and other
matters. The NDPSC periodically performs audits of gas and electric utilities
over which it has rate setting jurisdiction to determine the reasonableness of
overall rate levels. In the past, these audits have occasionally resulted in
settlement agreements adjusting rate levels for the Utility. 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 applies to proposed new
electric power generating plants of 50,000 kw or more and proposed new
transmission lines of more than 115 kv. The Utility is required to submit a
ten-year plan to the NDPSC annually.
On December 29, 2000 the NDPSC approved a performance-based ratemaking
(PBR) plan that links allowed earnings in North Dakota to seven performance
standards in the areas of price, electric service reliability, customer
satisfaction and employee safety. The PBR plan is effective for 2001 through
2005, unless suspended or terminated by the NDPSC or the Utility. This PBR plan
provides the opportunity for the Utility to raise its allowed rate of return and
share income with customers when earnings exceed the allowed return. During
2001, the Utility achieved a rate of return on equity that exceeded targets
under the plan, resulting in a sharing of the income between shareholders and
customers in the form of a $662,300 refund to North Dakota retail electric
customers in 2002. The Utility's 2002 rate of return is expected to be within
the allowable range defined in the plan.
The NDPSC reserves the right to review the issuance of stocks, bonds,
notes and other evidence of indebtedness of a public utility. However, the
issuance by a public utility of securities registered with the Securities and
Exchange Commission is expressly exempted from review by the NDPSC under North
Dakota state law.
South Dakota: The South Dakota Public Utilities Act subjects the
Utility to the jurisdiction of the SDPUC with respect to rates, public utility
services, establishment of assigned service areas and other matters. The Utility
is not currently subject to the jurisdiction of the SDPUC 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. There have been no significant rate proceedings in South Dakota since
November 1987.
FERC: Wholesale power sales and transmission rates are subject to the
jurisdiction of the FERC under the Federal Power Act of 1935, as amended (FPA).
The FERC is an independent agency which has jurisdiction over rates for
electricity sales for resale, transmission and sale of electric energy in
interstate commerce, interconnection of facilities, and accounting policies and
practices. Filed rates are effective after a one-day suspension period, subject
to ultimate approval by the FERC. The Utility is a member of the Mid-Continent
Area Power Pool (MAPP), which operates in parts of eight states in the Upper
Midwest and in three provinces in Canada. Power pool sales are conducted
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continuously through MAPP in accordance with schedules filed by MAPP with the
FERC. Additional MAPP functions include a regional reliability council that
maintains generation reserve sharing requirements.
The Utility agreed in October 2001 to join the Midwest Independent
System Operator (MISO) regional transmission organization (RTO) pursuant to FERC
Order No. 2000. In December 2001, the MISO received FERC approval as a regional
transmission organization. FERC's view is that the MISO will benefit the public
interest by enhancing the reliability of the Midwest electric grid and
facilitating and enhancing wholesale competition. The MISO covers a broad region
containing all or parts of 20 states and one Canadian province. The MISO began
operational control of the Utility's transmission facilities above 100 kv on
February 1, 2002, but the Utility continues to own and maintain its transmission
assets. As the transmission provider and security coordinator for the region,
the MISO offers available capacity, accepts schedules and provides settlement
for transmission services.
In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on
Standard Market Design (SMD). Its purpose is to insure standard commercial rules
for the operation of competitive markets for electricity. The SMD NOPR calls for
markets to be operational across the United States by the end of 2004. The MISO,
with strong FERC encouragement, has established the end of 2003 as a target for
MISO markets to be operational within its geographical area of operation. The
MISO is working together with the FERC on this process and has filed proposed
energy market rules with FERC for day-ahead and real-time energy markets and
financial transmission rights and has requested assurances from FERC that all
start-up costs will be recoverable for market participants. As the Utility
transitions to the full operation of the MISO there could be short-term negative
impacts on wholesale power transactions.
Other: The Utility 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 Utility may also
become subject to comprehensive energy legislation currently pending before the
United States Congress.
The Utility is unable to predict the impact on its operations resulting
from future regulatory activities, from future legislation or from future tax
that may be imposed on the source or use of energy.
Competition, Deregulation and Legislation
Electric sales are subject to competition in some areas from
municipally owned systems, rural electric cooperatives and, in certain respects,
from on-site generators and cogenerators. 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 Utility may also
face competition as the restructuring of the electric industry evolves.
The Company believes the Utility is well positioned to be successful in
a more competitive environment. A comparison of the Utility's electric retail
rates to the rates of other investor-owned utilities, cooperatives and
municipals in the states the Utility serves indicates that the Utility's rates
are competitive. In addition, the Utility would attempt more flexible pricing
strategies under an open, competitive environment.
Legislative and regulatory activity could affect operations in the
future. The Utility cannot predict the timing or substance of any future
legislation or regulation. State and federal efforts to restructure the electric
utility industry have slowed. The United States Congress ended its 2002
legislative session without passing electric industry restructuring legislation.
Congress did consider a comprehensive energy bill, but failed to pass it prior
to the November elections. There was no legislative action in
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2002 regarding electric retail choice in any of the states where the Utility
operates and no major electricity legislation is expected in 2003 legislative
sessions in those states. The Company does not expect retail competition to come
to the States of Minnesota, North Dakota or South Dakota in the foreseeable
future.
Environmental Regulation
Impact of Environmental Laws: The Utility's existing generating plants
are subject to stringent federal and state standards and regulations regarding,
among other things, air, water and solid waste pollution. The Utility estimates
it has expended in the five years ended December 31, 2002, approximately $5.3
million for environmental control facilities. Included in the 2003-2007
construction budget are approximately $2.6 million for environmental equipment
for existing and new facilities, including $0.8 million for 2003.
Air Quality: Pursuant to the Federal Clean Air Act of 1970 as amended
(the Act), the United States Environmental Protection Agency (EPA) has
promulgated national primary and secondary standards for certain air pollutants.
The primary fuels burned by the Utility's steam generating plants are
North Dakota lignite coal and western subbituminous coal. Electrostatic
precipitators have been installed at the principal units at the Hoot Lake 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 units at the Hoot Lake Plant
currently meet all presently applicable federal and state air quality and
emission standards.
The Utility improved the fine particulate emissions control at Big
Stone Plant by replacing a major portion of the plant's electrostatic
precipitator in the third quarter of 2002. The replacement technology is an
Advanced Hybrid technology that was installed as part of a demonstration project
co-funded by the Department of Energy's National Energy Technology Laboratory
Power Plant Improvement Initiative. The technology is designed to capture at
least 99.99% of the fly ash particulates emitted from the boiler. Initial test
data demonstrates the emissions design parameters were met. However, the Utility
will continue to investigate and assess the operational performance of the unit
as well as options to improve the Advanced Hybrid's balance-of-plant impacts as
part of its on-going effort to refine the demonstration technology. For the
$13.4 million project, the Energy Department's share is approximately $6.5
million, the Utility's share is approximately $2.9 million and the remaining
portion was funded by the Big Stone Plant co-owners and other industry
participants. The Big Stone Plant is currently operating within all presently
applicable federal and state air quality and emission standards.
The Coyote Station is equipped with 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 desulfurize hot gases from the
stack. The fabric filter collects spray dryer residue along with the fly ash.
The Coyote Station is currently operating within all presently applicable
federal and state air quality and emission standards.
The Act, in addressing acid deposition, imposed requirements on power
plants in an effort to reduce national emissions of sulfur dioxide (SO2) and
nitrogen oxides (NOx).
The national SO2 emission reduction goals are achieved through a
market-based system under which power plants are allocated "emissions
allowances" that will require plants to either reduce their emissions or acquire
allowances from others to achieve compliance. Each allowance is an authorization
to emit one ton of sulfur dioxide. Sulfur dioxide emission requirements are
currently being met by all of the Utility's generating facilities without the
need to acquire other allowances for compliance.
10
The national NOx emission reduction goals are achieved by imposing
mandatory emissions standards on individual sources. All of the Utility's
generating facilities met the NOx standards during 2002. Hoot Lake Plant unit 2
is governed by the phase one early opt-in provision until January 1, 2008. The
remaining generating units meet the NOx emission regulations that were adopted
by the EPA in December 1996.
The Act calls for EPA studies of the effects of emissions of listed
pollutants by electric steam generating plants. The EPA has completed the
studies and sent reports to Congress. The Act required that the EPA make a
finding as to whether regulation of emissions of hazardous air pollutants from
fossil fuel-fired electric utility generating units is appropriate and
necessary. On December 14, 2000 the EPA announced that it affirmatively decided
to regulate mercury emissions from electric generating units. The EPA expects to
propose regulations by December 2003 and issue final rules by December 2004.
Because promulgation of rules by the EPA has not been completed, it is not
possible to assess whether, or to what extent, this regulation will impact the
Utility.
In 1998, the EPA announced its New Source Review Enforcement Initiative
targeting coal-fired utilities, petroleum refineries, pulp and paper mills and
other industries for alleged violations of EPA's New Source Review rules. These
rules require owners or operators that construct new major sources or make major
modifications to existing sources to obtain permits and install air pollution
control equipment at affected facilities. The EPA is attempting to determine if
emission sources violated certain provisions of the Act by making major
modifications to their facilities without installing state-of-the-art pollution
controls. On January 2, 2001, the Utility received a request from the EPA,
pursuant to Section 114(a) of the Act, to provide certain information relative
to past operation and capital construction projects at the Big Stone Plant. The
Utility has responded to that request and at this time cannot determine what, if
any, actions will be taken by the EPA. In December 2002, the EPA issued changes
to the existing New Source Review rules. These changes are not expected to
result in any significant additional costs to the Utility. The EPA also proposed
changes clarifying application of certain sections of the New Source Review
rules. The Utility is currently evaluating the proposal. The EPA plans to accept
comments on these proposed changes in early 2003 and then undertake a new
rule-making process during the next one to two years.
The Coyote Station is subject to certain emission limitations under the
"Prevention of Significant Deterioration" (PSD) program of the Clean Air Act.
The EPA and the North Dakota Department of Health are currently engaged in
discussions about the maximum allowable increases of sulfur dioxide, which may
result in imposition of a cap on the sulfur dioxide emissions from all the
coal-fired steam-electric generating units that are located in North Dakota,
including the Coyote Station. If a cap were imposed, it is likely the cap would
be set at a level above current actual emission levels. The probable impact of a
cap on sulfur dioxide emissions on future operations, if it were imposed, is
uncertain.
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 Utility has all federal and state water permits presently necessary
for the operation of the Big Stone and Hoot Lake Plants. The water discharge
permit for the Coyote Station was renewed in 1998 for a five-year term. The
Utility has filed the permit renewal application for Coyote Station and believes
that since there are no significant issues with the renewal request, it will
receive a renewed permit in due course. The Utility owns five small dams on the
Otter Tail River, which are subject to FERC licensing
11
requirements. A license for all five dams was issued on December 5, 1991. Total
nameplate rating (manufacturer's expected output) of the five dams is 3,450 kw.
Solid Waste: Permits for disposal of ash and other solid wastes have
been issued for the Coyote Station and the Big Stone Plant. The Hoot Lake Plant
permit was under public notice until January 17, 2003 and the Utility expects
that the permit will be issued shortly. The Utility estimates that the current
ash disposal site at the Hoot Lake Plant will be filled to capacity within
approximately one year. The Utility plans to increase marketing of the ash for
construction purposes and to build a new ash disposal site adjacent to the
current site within the same permitted area in 2003. An estimate of the
engineering costs required to construct a new facility has been completed. On
that basis, the Utility believes that the investment required will not have a
significant impact on future plant operating costs.
At the request of the Minnesota Pollution Control Agency (MPCA), the
Utility has an ongoing investigation at its former, closed Hoot Lake Plant ash
disposal sites. The MPCA continues to monitor site activities under their
Voluntary Investigation and Cleanup Program. In April 2001, the Utility
submitted a Remedial Investigation Work Plan to the MPCA describing its plan to
further investigate the environmental impact of the closed portion of the Hoot
Lake Plant ash disposal site. The MPCA approved the plan, with some suggested
modifications, in July 2001. These tasks have been completed. The MPCA also
asked that the Utility eliminate a ground water seepage that was originating
from one of the disposal areas. Site work relating to that request was completed
in November 2001. However, seepage reappeared in a new location in the spring of
2002. The Utility initiated additional studies to further characterize the site
and its report was submitted to the MPCA in March 2003 for their review and
comment. Although the Utility is still evaluating various options, its
preliminary estimate of remediation costs to address the ash disposal site
issues over the next three years is not expected to have a material impact on
the Company's consolidated results of operations, financial position or cash
flows.
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
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 Utility 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 Utility 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, which was reauthorized and amended in 1986. 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 known as 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 Utility 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
Utility is not presently named as a potentially
12
responsible party under the federal or state Superfund laws.
Capital Expenditures
The Utility is continually expanding, replacing and improving its
electric facilities. During 2002, approximately $45.8 million was invested for
additions and replacements to its electric utility properties, including
$16 million for continuing work on the new gas-fired combustion turbine and
$7 million for completion of the Company-owned portion of a large transmission
line project in North Dakota. During the five years ended December 31, 2002
gross electric property additions, including construction work in progress, were
approximately $146.9 million and gross retirements were approximately
$43.0 million.
The Utility estimates that during the five-year period 2003-2007 it
will invest approximately $146 million for electric construction. The Utility
continuously reviews options for increasing its generating capacity. While at
this time the Utility has no firm plans for additional base load generating
plant construction, the Utility has under construction a gas-fired combustion
turbine expected to be operational by June 1, 2003. Most of the costs related to
the construction of the gas-fired combustion turbine occurred in 2002. The
majority of electric utility expenditures for the five-year period 2003 through
2007 will be for work related to the Utility's production plants and
distribution system.
Franchises
At December 31, 2002 the Utility had franchises to operate as an
electric utility in all of the 371 incorporated municipalities that 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 that the Utility serves.
Employees
At December 31, 2002 the Utility had approximately 728 full-time
employees. A total of 365 employees are represented by local unions of the
International Brotherhood of Electrical Workers and are covered by a three-year
labor contract expiring November 1, 2005. The Utility has not experienced any
strike, work stoppage or strike vote, and considers its present relations with
employees to be good.
PLASTICS
General
Plastics consists of businesses producing polyvinyl chloride (PVC)
pipe. The Company derived 12% of its consolidated operating revenues from this
segment in 2002, 10% in 2001 and 14% in 2000.
The following is a brief description of these businesses:
Northern Pipe Products, Inc., located in Fargo, ND, manufactures and
sells PVC pipe for municipal, rural water, irrigation and other uses in
the Upper Midwest region of the United States.
Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells
PVC pipe for municipal, rural water, irrigation and other uses in the
West, Southwest and South-central regions of the United States.
Together these companies have the capacity to produce approximately
170 million pounds of PVC pipe annually.
13
Customers
The PVC pipe products are marketed through a combination of independent
sales representatives, company salespersons and customer service
representatives. Customers for the PVC pipe products consist primarily of
wholesalers and distributors throughout the Upper Midwest, Southwest and Western
United States.
Competition
The plastic pipe industry is highly competitive, due to a relatively
small number of producers, an even smaller number of raw material suppliers and
the commodity nature of the product. Because of shipping costs, competition is
usually regional in scope, instead of national. Northern Pipe and Vinyltech
compete not only against other plastic pipe manufacturers, but also ductile
iron, steel, concrete and clay pipe producers. Pricing pressure will continue to
affect operating margins in the future.
Northern Pipe and Vinyltech intend to continue to compete on the basis
of their high quality products, cost-effective production techniques and close
customer relations and support.
Manufacturing and Resin Supply
PVC pipe is manufactured through a process known as extrusion. During
the production process, PVC compound (a dry powder-like substance) is introduced
into an extrusion machine, where it is heated to a molten state and then forced
through a sizing apparatus to produce the pipe. The newly extruded pipe is then
pulled through a series of water cooling tanks, marked to identify the type of
pipe and cut to finished lengths. Warehouse and outdoor storage facilities are
used to store the finished product. Inventory is shipped from storage to
customers mainly by common carrier.
The PVC resins are acquired in bulk and shipped to point of use by rail
car. Over the last ten years, there has been consolidation in PVC resin
producers. There are a limited number of third party vendors that supply the PVC
resin used by Northern Pipe and Vinyltech. During 2002, seven vendors supplied
the resin used, with over 58% of the resin purchased from two main vendors.
During 2001 and 2000, two vendors provided approximately 75% of the PVC resin
used. The loss of a key vendor, or any interruption or delay in the supply of
PVC resin could disrupt the ability of the Plastics segment to manufacture
products, cause customers to cancel orders or require incurrence of additional
expenses to obtain PVC resin from alternative sources, if such sources were
available. Both Northern Pipe and Vinyltech believe they have good relationships
with their key raw material vendors.
Due to the commodity nature of PVC resin and PVC pipe and the dynamic
supply and demand factors worldwide, historically the markets for both PVC resin
and PVC pipe have been very cyclical with significant fluctuations in prices and
gross margins.
Capital Expenditures
Capital expenditures in the Plastics segment typically include
investments in extrusion machines, land and buildings and management information
systems. During 2002, capital expenditures of approximately $6 million were made
in the Plastics segment. Expenditures during 2002 included the purchase of land
and buildings by Vinyltech that were previously being leased. Total capital
expenditures during the five-year period 2003-2007 are estimated to be
approximately $14 million.
During 2003, Northern Pipe will be opening a new polyethylene (PE) pipe
plant in Hampton, IA. This new operation will require approximately $3.5 million
in pipe production equipment. Production of PE pipe will be a new product line
for the Plastics segment and will allow Northern Pipe to provide
14
its customers with additional product choices. The production process will
require using a new type of resin that will be purchased from different vendors
than those who provide the PVC resin. The new plant is expected to be producing
PE pipe by April 1, 2003.
Employees
At December 31, 2002 the Plastics segment had approximately 163
full-time employees.
MANUFACTURING
General
Manufacturing consists of businesses in the following manufacturing
activities: production of waterfront equipment, wind towers, frame-straightening
equipment and accessories for the auto repair industry, custom plastic pallets,
material and handling trays and horticultural containers; fabrication of steel
products; contract machining; and metal parts stamping and fabrication.
During 2002, two acquisitions were completed in this segment. In May,
the Company acquired the stock of ShoreMaster, Inc. and in October the Company
acquired the stock of Galva Foam Marine Industries, Inc. During 2002, Precision
Machine, Inc. was merged into BTD Manufacturing, Inc.
The Company derived 20% of its consolidated operating revenues from
this segment in 2002, 19% in 2001 and 17% in 2000. The following is a brief
description of each of these businesses:
BTD Manufacturing, Inc. (BTD), located in Detroit Lakes and Pelican
Rapids, MN, is a metal stamping and tool and die manufacturer that
provides its services mainly to customers in the Midwest. BTD stamps,
fabricates, welds and laser cuts metal components according to
manufacturers' specifications primarily for the recreation vehicle, gas
fireplace, health and fitness and enclosure industries.
Chassis Liner Corporation, located in Alexandria and Lucan, MN,
manufactures and markets vehicle frame-straightening equipment and
accessories used by the auto repair industry throughout the United
States.
DMI Industries Inc.(DMI), located in West Fargo, ND, engineers and
manufactures towers for the wind energy industry throughout the United
States.
T.O. Plastics, Inc., located in Minneapolis and Clearwater, MN, and
Hampton, SC, manufactures and sells plastic thermoformed products for
the horticulture industry throughout the United States. In addition,
T.O. Plastics produces products such as clamshell packing, blister
packs, returnable pallets and handling trays for shipping and storing
odd-shaped or difficult-to-handle parts for other industries.
ShoreMaster, Inc., located in Fergus Falls, MN, along with its wholly
owned subsidiary, Galva Foam Marine, Inc. located in Camdenton, MO,
produce and market residential and commercial waterfront equipment,
ranging from boatlifts and docks to full marina systems throughout the
United States.
St. George Steel Fabrication, Inc., located in St. George and Salt Lake
City, UT, fabricates structural steel members for buildings and
bridges, ductwork for the power and refining industries, conveyors and
hoppers for mining and industrial markets and plate steel products for
the wind tower industry, primarily for customers in the Western United
States.
15
Competition
The various markets in which the Manufacturing segment entities compete
are characterized by intense competition. These markets 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's manufacturing entities.
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's manufacturing entities intend to continue to compete
on the basis of their high-performance products, innovative technologies,
cost-effective manufacturing techniques, close customer relations and support,
and their strategy of increasing product offerings.
Some of the products sold by the companies in the Manufacturing segment
are purchased by companies in the recreational vehicle, wind energy and auto
repair markets. A downturn in these markets could have an adverse impact on the
financial results of the Company's Manufacturing segment.
Legislation
The failure of Congress to pass a broad energy bill in 2003 could have
an unfavorable impact on the Company's operations that manufacture towers for
the wind energy industry.
Capital Expenditures
Capital expenditures in the Manufacturing segment typically include
additional investments in new manufacturing equipment or expenditures to replace
worn-out manufacturing equipment. Capital expenditures may also be made in the
purchase of land and buildings for plant expansion and investments in management
information systems. During 2002, capital expenditures of approximately
$15 million were made in the Manufacturing segment. In 2002, structural
modifications and new equipment was purchased at BTD in connection with an
$8.7 million plant expansion and $3.8 million was spent on a plant expansion at
DMI. Total capital expenditures for the Manufacturing segment during the
five-year period 2003-2007 are estimated to be approximately $45 million.
Employees
At December 31, 2002 the Manufacturing segment had approximately 1,060
full-time employees.
HEALTH SERVICES
General
Health Services consists of the DMS Health Group, which includes
businesses involved in the sale of diagnostic medical equipment, supplies and
accessories. These businesses also provide service maintenance, mobile and
fixed-based diagnostic services, portable X-ray imaging and interim rental of
diagnostic medical imaging equipment.
During 2002, two acquisitions were completed in this segment. In May
2002, the Company acquired the stock of Computed Imaging Service, Inc. On
November 1, 2002 the Company acquired the assets and operations of Mobile
Diagnostic Services, Inc.
16
The Company derived 13% of its consolidated operating revenues from
this segment in 2002, 12% in 2001 and 11% in 2000. The companies comprising the
DMS Health Group include:
DMS Health Technologies, Inc., located in Fargo, ND, sells, services
and refurbishes diagnostic medical imaging equipment and related
supplies and accessories. DMS sells radiology equipment primarily
manufactured by Philips Medical Systems (Philips), a large
multi-national company based in the Netherlands. Philips manufactures
fluoroscopic, radiographic and mammography equipment, along with
ultrasound, computerized tomography (CT) scanners, magnetic resonance
imaging (MRI) scanners and cardiac cath labs. DMS is also a supplier of
medical film and related accessories. DMS markets mainly to hospitals,
clinics and mobile service companies in North Dakota, South Dakota,
Minnesota, Montana and Wyoming.
DMS Imaging, Inc., a subsidiary of DMS Health Technologies, Inc.
located in Osseo, MN, operates mobile and in-house diagnostic medical
imaging equipment, including CT, MRI, positron-emission tomography
(PET), nuclear medicine services and other similar radiology services
to hospitals, clinics, long-term care facilities and other medical
providers located in 40 states. During 2002, regional offices were
designated in Houston, TX; Minneapolis, MN; and Sioux Falls, SD. DMS
Imaging provides services in four different business units:
o DMS Imaging - provides shared diagnostic medical imaging
services (primarily mobile) for MRI, CT, nuclear medicine,
PET, ultrasound, mammography and bone density analysis.
o DMS Interim Solutions - offers interim and rental options for
diagnostic imaging services.
o DMS MedSource Partners - develops partnerships with
healthcare providers to offer dedicated diagnostic imaging
services, such as MRI.
o DMS Portable X-Ray - delivers portable X-ray, ultrasound and
electrocardiogram services to nursing homes and other
facilities.
Combined, the DMS Health Group covers the three basics of the medical
imaging industry: (1) ownership and operation of the imaging equipment for
healthcare providers; (2) sale, lease and/or maintenance of medical imaging
equipment and related supplies; and (3) scheduling, billing and administrative
support of medical imaging services.
Regulation
The healthcare industry is subject to federal and state regulations
relating to licensure, conduct of operation, ownership of facilities, addition
of facilities and services and payment of services.
The federal Anti-Kickback Act prohibits persons from knowingly and
willfully soliciting, receiving, offering or providing remuneration, directly or
indirectly, to induce the referral of an individual or the furnishing or
arranging for a good or service for which payment may be made under a federal
healthcare program such as Medicare or Medicaid. Several states have similar
statutes. The term "remuneration" has been broadly interpreted to include
anything of value, including, for example, gifts, discounts, credit
arrangements, payments of cash, waiver of payments and ownership interests.
Penalties for violating the Anti-Kickback Act can include both criminal
penalties and civil sanctions. By regulation, the U.S. Department of Health and
Human Services has created certain "safe harbors" under the Act. These safe
harbor regulations set forth certain provisions, which, if met, assure that
healthcare providers will not be subject to liability under the Act.
The Ethics and Patient Referral Act of 1989 (the Stark Act) prohibits
physician referrals of Medicare and Medicaid patients to an entity providing
certain designated health services, including services provided by the Health
17
Services companies. The Stark Act also prohibits an entity from billing for
prohibited services. A person who engages in a scheme to violate the Stark Act
or a person who presents a claim to Medicare or Medicaid in violation of the
Stark Act may be subject to civil fines and possible exclusion from
participation in federal healthcare programs.
The Health Services companies believe that their operations comply with
the Anti-Kickback Act and the Stark Act. However, if the Health Services
companies were to engage in conduct in violation of these statutes, the sanction
imposed could adversely affect the Company's financial results.
The Health Insurance Portability and Accountability Act of 1996 (HIPPA)
created federal crimes related to healthcare fraud and to making false
statements related to healthcare matters. HIPPA prohibits knowingly and
willfully executing a scheme to defraud any healthcare benefit program including
a program involving private payers. Further, HIPPA prohibits knowingly and
willfully falsifying, concealing or covering up a material fact or making any
materially false statement in connection with the delivery of or payment for
healthcare benefits or services. A violation of HIPPA is a felony and may result
in fines, imprisonment or exclusion from government-sponsored programs such as
Medicare and Medicaid. Finally, HIPPA creates federal privacy standards for
individually identifiable health information and computer security standards for
all health information. These standards become applicable in 2003. The Health
Services companies believe that they are in compliance and will be in compliance
with the requirements of HIPPA. However, if the Health Services companies were
to engage in conduct in violation of these statutes, the sanction imposed could
adversely affect the Company's financial results.
In some states a certificate of need or similar regulatory approval is
required prior to the acquisition of high-cost capital items or services,
including diagnostic imaging systems or provisions of diagnostic imaging
services by companies or its customers. Certificate of need laws were enacted to
contain rising healthcare costs by preventing unnecessary duplication of health
resources. Certificate of need regulations may limit or preclude the Health
Services companies from providing diagnostic imaging services or systems.
Conversely, a repeal of existing certificate of need regulations in states where
the Health Services companies have obtained certificates of need could adversely
affect their financial performance.
The Health Services companies continue to monitor developments in
healthcare law and modify their operations from time to time as the business and
regulatory environment changes. However, there can be no assurances that the
Health Services companies will always be able to modify their operations to
address changes in the regulatory environment without any adverse effect to
their financial performance.
Reimbursement
The companies in the Health Services segment derive most of their
revenues directly from healthcare providers rather than third-party payers, such
as Medicare, Medicaid or private health insurance companies. The Health
Services' customers who are healthcare providers receive the majority of their
payments from third-party payors. Payments by third-party payors depend upon
their policies. Because unfavorable reimbursement policies have limited and may
continue to limit the profit margins of hospitals and clinics the Health
Services companies bill directly, it may be necessary to lower fees to retain
existing customers and attract new ones.
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 companies within Health Services
compete with free-standing imaging centers and health care providers
18
that have their own diagnostic imaging systems and with equipment manufacturers
that sell imaging equipment to healthcare providers for full-time installation.
Some of the direct competitors, which provide contract MRI services, have access
to greater financial resources than the Health Services companies. In addition,
some of Health Services' 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 companies in the Health Services segment may
also experience greater competition in states that currently have certificate of
needs laws should these laws be repealed, reducing barriers to entry in that
state. The companies within this segment compete against other contract
providers on the basis of quality of services, quality and magnetic field
strength of imaging systems, relationships with health care providers, knowledge
and service quality of technologists, price, availability and reliability.
Environmental, Health or Safety Laws
Positron emission tomography services and some other imaging services
require the use of radioactive material. While this material has a short life
and quickly breaks down into inert, or non-radioactive substances, using such
materials presents the risk of accidental environmental contamination and
physical injury. Federal, state and local regulations govern the storage, use
and disposal of radioactive material and waste products. The Company believes
that its safety procedures for storing, handling and disposing of these
hazardous materials comply with the standards prescribed by law and regulation;
however the risk of accidental contamination or injury from those hazardous
materials cannot be completely eliminated. The companies in the Health Services
segment have not had any material expenses related to environmental, health or
safety laws or regulations.
Capital Expenditures
Capital expenditures in this segment principally relate to the
acquisition of diagnostic imaging equipment used in the mobile imaging business.
During 2002, capital expenditures of approximately $4 million were made in the
Health Services segment. Total capital expenditures during the five-year period
2003-2007 are estimated to be approximately $9 million. Operating leases are
also used to finance the acquisition of medical equipment used by Health
Services companies. Operating lease payments during the five-year period
2003-2007 are estimated to be $48 million.
Employees
At December 31, 2002 the Health Services segment had approximately 440
full-time employees.
OTHER BUSINESS OPERATIONS
General
Other Business Operations consists of businesses engaged in electrical
and telephone construction contracting, transportation, telecommunications,
entertainment and energy services and natural gas marketing as well as the
portion of corporate administrative and general expenses that are not allocated
to the other segments. The Company derived 12% of its consolidated operating
revenues from these businesses in 2002 and 2001 and 13% in 2000.
The following is a brief description of each of these businesses:
Midwest Construction Services, Inc., is a holding company for three
subsidiaries: Aerial Contractors, Inc., located in West Fargo, ND;
Moorhead Electric, Inc., located in Moorhead, MN; and Dakota Direct
Control, Inc., located in Sioux Falls, SD. Services provided in the
Upper Midwest by these companies include electric contracting for
19
industrial, commercial and healthcare sites; installing data network
cabling as well as underground copper cable and fiber optics;
constructing and repairing overhead and underground electric
distribution and transmission lines and substations; and providing
building control systems including heating/cooling and security
systems.
Midwest Information Systems, Inc., headquartered in Parkers Prairie,
MN, provides telephone, cable and internet services with over 9,900
access lines for phone, internet and cable television to homes in rural
western Minnesota communities through its subsidiaries Midwest
Telephone Company, Osakis Telephone Company, Peoples Telephone Company
of Big Fork and Data Video Systems, Inc.
Otter Tail Energy Services Company, headquartered in Fergus Falls, MN,
was established in 1997 to provide unregulated energy-based products
and services to commercial, industrial and institutional clients
throughout the Upper Midwest. It offers technical and engineering
services, energy efficient lighting, water conservation,
performance-based service contracting and financial services centered
on the management and reduction in demand and consumption of gas,
electric and water/sewer utilities. Otter Tail Energy Services Company
owns one subsidiary, Otter Tail Energy Management Company, which is a
retail marketer of natural gas and energy management services to
commercial, industrial and institutional customers in Iowa, South
Dakota, North Dakota and Minnesota.
E. W. Wylie Corporation (Wylie), located in Fargo, ND, is a contract
and common carrier operating a fleet of tractors and trailers in 48
states and 6 Canadian provinces. During 2002, Wylie opened new trucking
terminals in Des Moines, IA, and Fort Worth, TX, to expand freight
brokerage businesses.
Regulation
The telephone subsidiaries are subject to the regulatory authority of
the MPUC regarding rates and charges for telephone services, as well as other
matters. The telephone subsidiaries must keep on file with the MPUC 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 promulgated by the Federal Communications
Commission. The cable television subsidiary is regulated by federal and local
authorities.
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. The construction companies in this segment must compete
with other construction companies in the Upper Midwest when bidding on new
projects. The Company believes the principal competitive factors in the
construction segment are price, quality of work and customer services.
The trucking industry, in which Wylie competes, is highly competitive.
Wylie competes primarily with other short- to medium-haul, flatbed truckload
carriers, internal shipping conducted by existing and potential customers and,
to a lesser extent, railroads. Competition for the freight transported by Wylie
is based primarily on service and efficiency and to a lesser degree, on freight
rates. There are other trucking companies that have greater financial resources,
operate more equipment or carry a larger volume of freight than Wylie and these
companies compete with Wylie for qualified drivers.
Capital Expenditures
Capital expenditures in this segment typically include investments in
additional trucks and flat bed trailers, infrastructure to support the
20
telephone, cable and internet services and construction equipment. During 2002,
capital expenditures of approximately $5 million were made in Other Business
Operations. Capital expenditures during the five-year period 2003-2007 are
estimated to be approximately $26 million for Other Business Operations. Almost
all of the $26 million will be used to replace existing equipment with the
majority to be invested in the transportation and telecommunication companies.
Employees
At December 31, 2002 there were approximately 720 full-time employees
in Other Business Operations. 84 employees of Moorhead Electric, Inc. are
represented by local unions of the International Brotherhood of Electrical
Workers and are covered by a two-year labor contract expiring May 31, 2003.
Moorhead Electric, Inc. has not experienced any strike, work stoppage or strike
vote, and considers its present relations with employees to be 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 and are included, along
with this statement, for purposes of complying with the safe harbor provision of
the Act. Factors that might cause such differences include, but are not limited
to, the Company's ongoing involvement in diversification efforts, the timing and
scope of deregulation and open competition, growth of electric revenues, impact
of the investment performance of the Utility's pension plan, changes in the
economy, governmental and regulatory action, weather conditions, fuel and
purchased power costs, environmental issues, resin prices, and other factors
discussed under "Critical Accounting Policies Involving Significant Estimates"
and "Factors Affecting Future Earnings" on pages 24 through 28 of the Company's
2002 Annual Report to Shareholders, filed as an Exhibit hereto. These factors
are in addition to any other cautionary statements, written or oral, which may
be made or referred to in connection with any such forward-looking statement or
contained in any subsequent filings by the Company with the Securities and
Exchange Commission.
Item 2. PROPERTIES
The Coyote Station, which commenced operation in 1981, is a 414,000 kw
(nameplate rating) mine-mouth plant located in the lignite coal fields near
Beulah, North Dakota and is jointly owned by the Utility, Northern Municipal
Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service
Company. The Utility owns 35% of the plant and on July 1, 1998, became the
operating agent of the Coyote Station.
The Utility, 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
Utility is the operating agent of Big Stone Plant and 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 nameplate 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
21
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, 2002, the Utility's transmission facilities, which are
interconnected with lines of other public utilities, consisted of 48 miles of
345 kv lines; 403 miles of 230 kv lines; 727 miles of 115 kv lines; and 4,133
miles of lower voltage lines, principally 41.6 kv. The Utility 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.
In addition to the properties mentioned above, the Company owns and has
investments in offices and service buildings. The Company's subsidiaries own
facilities and equipment used to manufacture PVC pipe and perform metal
stamping, fabricating and contract machining; construction equipment and tools;
medical imaging equipment; a fleet of flatbed trucks and trailers; and the
infrastructure to maintain approximately 9,900 access lines for phone, internet
and cable television in its telecommunication companies.
Management of the Company believes the facilities and equipment
described above are adequate for the Company's present businesses.
All of the common shares of the companies owned by Varistar are pledged
to secure indebtedness of Varistar.
Item 3. LEGAL PROCEEDINGS
Not Applicable.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
three months ended December 31, 2002.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2003)
Set forth below is a summary of the principal occupations and business
experience during the past five years of executive officers of the Company.
Except as noted below, each of the executive officers has been employed by the
Company for more than five years in an executive or management position either
with the Company or its wholly owned subsidiary, Varistar.
DATES ELECTED
NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE
- ------------- ------------- ----------------------------------------
John D. Erickson (44) 4/8/02 Present: President and Chief
Executive Officer
4/9/01 President
4/10/00 Executive Vice President,
Chief Financial Officer and Treasurer
10/26/98 Vice President, Finance and
Chief Financial Officer
Prior to Director, Market
10/26/98 Strategies & Regulation
22
DATES ELECTED
NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE
- ------------- ------------- ----------------------------------------
George A. Koeck (50) 4/10/00 Present: Corporate Secretary
and General Counsel
8/2/99 General Counsel
Prior to
8/2/99 Partner, Dorsey & Whitney LLP
Lauris N. Molbert (45) 6/10/02 Present: Executive Vice President and
Chief Operating Officer
4/9/01 Executive Vice President, Corporate
Development and Varistar President and
Chief Operating Officer
4/10/00 Vice President, Chief Operating
Officer, Varistar; President and Chief
Operating Officer, Varistar
Prior to President and Chief Operating
4/10/00 Officer, Varistar
Kevin G. Moug (43) 4/9/01 Present: Chief Financial Officer and
Treasurer
Prior to Varistar Chief Financial Officer
4/9/01 and Treasurer
The term of office of each of the officers is one year. Any officer
elected may be removed by the vote of the Board of Directors at any time during
the term. There are no family relationships between any of the executive
officers.
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 Corporation Stock Listing" on Page 53, to
"Selected Consolidated Financial Data" on Page 17 and to "Quarterly Information"
on Page 49 of the Company's 2002 Annual Report to Shareholders, filed as an
Exhibit hereto.
Item 6. SELECTED FINANCIAL DATA
The information required by this Item is incorporated by reference to
"Selected Consolidated Financial Data" on Page 17 of the Company's 2002 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 18 through 30 of the Company's 2002 Annual Report to
Shareholders, filed as an Exhibit hereto.
23
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is incorporated by reference to
"Quantitative and Qualitative Disclosures About Market Risk" on Page 30 of the
Company's 2002 Annual Report to Shareholders, filed as an Exhibit hereto.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item is incorporated by reference to
"Quarterly Information" on Page 49 and the Company's audited financial
statements on Pages 31 through 49 of the Company's 2002 Annual Report to
Shareholders excluding "Report of Management" on Page 31, 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 regarding Directors is
incorporated by reference to the information under "Election of Directors" in
the Company's definitive Proxy Statement dated March 6, 2003. The information
regarding executive officers is set forth in Item 4A hereto. The information
regarding Section 16 reporting is incorporated by reference to the information
under "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's
definitive Proxy Statement dated March 6, 2003.
Item 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to
the information under "Summary Compensation Table," "Aggregated Option/SAR
Exercises in Last Fiscal Year and Fiscal Year-End Options/SAR Values," "Pension
and Supplemental Retirement Plans," "Severance and Employment Agreements," and
"Director Compensation" in the Company's definitive Proxy Statement dated
March 6, 2003.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The security ownership information set forth under "Outstanding Voting
Shares" and "Management's Security Ownership" in the Company's definitive Proxy
Statement dated March 6, 2003 is incorporated herein by reference.
24
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2002
about the Company's common stock that may be issued under all of its equity
compensation plans:
Number of securities to be Weighted-average Number of securities remaining
issued upon exercise of exercise price of available for future issuance under
outstanding options, warrants outstanding options, equity compensation plans (excluding
Plan Category and rights warrants and rights securities reflected in column (a))
- ------------------------------- ------------------------------ ------------------------ --------------------------------------
(a) (b) (c)
Equity compensation plans
approved by security holders
1999 Stock
Incentive Plan 1,360,721 $24.68 930,602 (1)
1999 Employee
Stock Purchase Plan -- N/A 231,761 (2)
Equity compensation plans not
approved by security holders -- -- --
------------------------------ ------------------------ --------------------------------------
Total 1,360,721 $24.68 1,162,363
============================== ======================== ======================================
(1) The 1999 Stock Incentive Plan provides for the issuance of any shares
available under the plan in the form of restricted stock, performance
awards and other types of stock-based awards, in addition to the granting
of options, warrants or stock appreciation rights.
(2) Shares are issued based on employees' election to participate in the plan.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
Item 14. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. Under the
supervision and with the participation of the Company's management, including
the Chief Executive Officer and the Chief Financial Officer, the Company
evaluated the effectiveness of the design and operation of its disclosure
controls and procedures (as defined in Rule 13a-14(c) under the Securities
Exchange Act of 1934) as of a date (the "Evaluation Date") within 90 days prior
to the filing date of this report. Based on that evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that the Company's disclosure
controls and procedures were effective as of the Evaluation Date.
(b) Changes in Internal Controls. There were no significant changes in
the Company's internal controls or in other factors that could significantly
affect those controls subsequent to the date of their most recent evaluation.
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) List of documents filed:
(1) and (2) See Table of Contents on Page 29 hereof.
25
(3) See Exhibit Index on Pages 30 through 35 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:
None
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 CORPORATION
By /s/ Kevin G. Moug
-------------------------------------
Kevin G. Moug
Chief Financial Officer and Treasurer
Dated: March 26, 2003
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 D. Erickson )
President and )
Chief Executive Officer )
(principal executive officer) )
)
Kevin G. Moug )
Chief Financial Officer and Treasurer )
(principal financial and accounting officer) )
) By /s/ John D. Erickson
) -----------------------------
John C. MacFarlane ) John D. Erickson
Chairman of the Board and Director ) Pro Se and Attorney-in-Fact
) Dated March 26, 2003
Thomas M. Brown, Director )
)
Dennis R. Emmen, Director )
)
Maynard D. Helgaas, Director )
)
Arvid R. Liebe, Director )
)
Kenneth L. Nelson, Director )
)
Nathan I. Partain, Director )
)
Gary J. Spies, Director )
)
Robert N. Spolum, Director )
26
CERTIFICATIONS
I, John D. Erickson, certify that:
1. I have reviewed this annual report on Form 10-K of Otter Tail
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 26, 2003
/s/ John D. Erickson
- -------------------------------------
John D. Erickson
President and Chief Executive Officer
27
I, Kevin G. Moug, certify that:
1. I have reviewed this annual report on Form 10-K of Otter Tail
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 26, 2003
/s/ Kevin G. Moug
- -------------------------------------
Kevin G. Moug
Chief Financial Officer and Treasurer
28
OTTER TAIL CORPORATION
TABLE OF CONTENTS
FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA,
SUPPLEMENTAL FINANCIAL SCHEDULES INCLUDED IN ANNUAL REPORT
(FORM 10-K) FOR THE YEAR ENDED
DECEMBER 31, 2002
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, 2002:
Page in
Annual
Report to
Shareholders
------------
Financial Statements:
Independent Auditors' Report.........................................31
Consolidated Balance Sheets, December 31, 2002 and 2001.........32 & 33
Consolidated Statements of Income for the Three Years
Ended December 31, 2002..............................................34
Consolidated Statements of Common Shareholders' Equity for the
Three Years Ended December 31, 2002..................................35
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 2002..............................................36
Consolidated Statements of Capitalization, December 31, 2002
and 2001 ............................................................37
Notes to Consolidated Financial Statements........................38-49
Selected Consolidated Financial Data for the Five Years
Ended December 31, 2002...........................................17
Quarterly Data for the Two Years Ended
December 31, 2002 ................................................49
Schedules are omitted because of the absence of the conditions under which they
are required, because the amounts are insignificant or because the information
required is included in the financial statements or the notes thereto.
29
EXHIBIT INDEX
TO
ANNUAL REPORT
ON FORM 10-K
FOR YEAR ENDED DECEMBER 31, 2002
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
3-A 8-K 3 -- Restated Articles of
dated 4/10/01 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 8-A dated 1 -- Rights Agreement, dated as of
1/28/97 January 28, 1997 (the Rights
Agreement), between the
Company and Norwest Bank Minnesota,
National Association.
4-D-2 8-A/A dated 1 -- Amendment No. 1, dated as of
9/29/98 August 24, 1998, to the Rights
Agreement.
4-D-3 10-K for year 4-D-7 -- Note Purchase Agreement dated
ended 12/31/01 as of December 1, 2001.
4-D-4 -- First Amendment dated as
of December 1, 2002 to Note
Purchase Agreement dated as
of December 1, 2001.
4-D-5 333-90952 99-A-1 -- Credit Agreement dated as of
April 30, 2002.
4-D-6 8-K dated 99-A -- First Amendment dated as of
9/27/02 September 19, 2002 to Credit
Agreement dated as of April 30, 2002.
10-A 2-39794 4-C -- Integrated Transmission
Agreement dated August 25,
1967, between Cooperative
Power Association and the
Company.
10-A-1 10-K for year 10-A-1 -- Amendment No. 1, dated as
ended 12/31/92 of September 6, 1979, to
Integrated Transmission
Agreement, dated as of
August 25, 1967, between
Cooperative Power
Association and the
Company.
10-A-2 10-K for year 10-A-2 -- Amendment No. 2, dated as of
ended 12/31/92 November 19, 1986, to Integrated
Transmission Agreement between
Cooperative Power Association
and the Company.
30
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
10-C-1 2-55813 5-E -- Contract dated July 1, 1958,
between Central Power Electric
Corporation, Inc., and the Company.
10-C-2 2-55813 5-E-1 -- Supplement Seven dated
November 21, 1973.
(Supplements Nos. One through
Six have been superseded
and are no longer in effect.)
10-C-3 2-55813 5-E-2 -- Amendment No. 1 dated
December 19, 1973, to
Supplement Seven.
10-C-4 10-K for year 10-C-4 -- Amendment No. 2 dated
ended 12/31/91 June 17, 1986, to Supplement
Seven.
10-C-5 10-K for year 10-C-5 -- Amendment No. 3 dated
ended 12/31/92 June 18, 1992, to Supplement
Seven.
10-C-6 10-K for year 10-C-6 -- Amendment No. 4 dated
ended 12/31/93 January 18, 1994, to Supplement
Seven.
10-D 2-55813 5-F -- Contract dated April 12,
1973, between the Bureau of
Reclamation and the Company.
10-E-1 2-55813 5-G -- Contract dated January 8,
1973, between East River
Electric Power Cooperative
and the Company.
10-E-2 2-62815 5-E-1 -- Supplement One dated
February 20, 1978.
10-E-3 10-K for year 10-E-3 -- Supplement Two dated
ended 12/31/89 June 10, 1983.
10-E-4 10-K for year 10-E-4 -- Supplement Three dated
ended 12/31/90 June 6, 1985.
10-E-5 10-K for year 10-E-5 -- Supplement No. Four, dated
ended 12/31/92 as of September 10, 1986.
10-E-6 10-K for year 10-E-6 -- Supplement No. Five, dated
ended 12/31/92 as of January 7, 1993.
10-E-7 10-K for year 10-E-7 -- Supplement No. Six, dated
ended 12/31/93 as of December 2, 1993.
31
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
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
ended 12/31/89 purchase 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-B -- Big Stone Plant Coal Agreements
ended 09/30/01 by and between the Company, Northwestern
Public Service, Montana-Dakota
Utilities Co., and RAG Coal West, Inc.
(dated as of September 28, 2001).
10-H 2-61043 5-H -- Agreement for Sharing
Ownership 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.
32
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
10-H-2 10-K for year 10-H-2 -- Supplemental Agreement No.
ended 12/31/89 Two dated as of March 1, 1981,
to Agreement for Sharing
Ownership of Coyote Generating
Unit No. 1 and Amendment No. 2
dated March 1, 1981, to Coyote
Plant Coal Agreement.
10-H-3 10-K for year 10-H-3 -- Amendment dated as of
ended 12/31/89 July 29, 1983, to Agreement
for Sharing Ownership of
Coyote Generating Unit No. 1.
10-H-4 10-K for year 10-H-4 -- Agreement dated as of Sept.
ended 12/31/92 5, 1985, containing Amendment
No. 3 to Agreement for Sharing
Ownership of Coyote Generating
Unit No.1, dated as of July 1,
1977, and Amendment No. 5 to
Coyote Plant Coal Agreement,
dated as of January 1, 1978.
10-H-5 10-Q for quarter 10-A -- Amendment dated as of
ended 9/30/01 June 14, 2001, to Agreement for
Sharing Ownership of
Coyote Generating Unit No. 1.
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 10,
ended 12/31/92 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-I-5 10-K for year 10-I-5 -- Agreement and Consent to
ended 12/31/01 Assignment of the Coyote Plant
Coal Agreement.
33
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
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 -- Power Sales Agreement
ended 9/30/99 between the Company and
Manitoba Hydro Electric
Board (dated as of July 1, 1999).
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 10-K for year 10-M -- Hoot Lake Coal Transportation
ended 12/31/99 Agreement by and between the
Company and The Burlington
Northern and Santa Fe
Railway Company (dated as
of July 19, 1999).
10-N-1 -- Deferred Compensation Plan
for Directors, as amended.*
10-N-2 10-Q for quarter 10-C -- Executive Survivor and
ended 3/31/02 Supplemental Retirement Plan,
as amended.*
10-N-3 10-K for year 10-N-5 -- Nonqualified Profit Sharing
ended 12/31/93 Plan.*
10-N-4 10-Q for quarter 10-B -- Nonqualified Retirement
ended 3/31/02 Savings Plan, as amended.*
10-N-5 10-K for year 10-N-6 -- 1999 Employee Stock
ended 12/31/98 Purchase Plan.
10-N-6 10-K for year 10-N-7 -- 1999 Stock Incentive Plan.*
ended 12/31/98
34
PREVIOUSLY FILED
-------------------------------
AS
EXHIBIT
FILE NO. NO.
------------- --------
10-O-1 10-Q for quarter 10-A -- Executive Employment Agreement,
ended 6/30/02 John Erickson.*
10-O-2 10-Q for quarter 10-B -- Executive Employment Agreement
ended 6/30/02 and amendment no. 1, Lauris Molbert.*
10-O-3 10-Q for quarter 10-C -- Executive Employment Agreement,
ended 6/30/02 Kevin Moug.*
10-O-4 10-Q for quarter 10-D -- Executive Employment Agreement,
ended 6/30/02 George Koeck.*
10-P-1 10-Q for quarter 10-E -- Change in Control Severance
ended 6/03/02 Agreement, John Erickson.*
10-P-2 10-Q for quarter 10-F -- Change in Control Severance
ended 6/03/02 Agreement, Lauris Molbert.*
10-P-3 10-Q for quarter 10-G -- Change in Control Severance
ended 6/03/02 Agreement, Kevin Moug.*
10-P-4 10-Q for quarter 10-H -- Change in Control Severance
ended 6/03/02 Agreement, George Koeck.*
13-A -- Portions of 2002 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.
99-A -- Certification Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act
of 2002 as to the Annual Report on Form
10-K for the year ended December 31, 2002,
by John D. Erickson, President and Chief
Executive Officer, Otter Tail Corporation.
99-B -- Certification Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act
of 2002 as to the Annual Report on Form
10-K for the year ended December 31, 2002,
by Kevin G. Moug, Chief Financial Officer
and Treasurer, Otter Tail Corporation.
- --------
* Management contract or compensatory plan or arrangement required to be filed
pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.
35