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, 1999
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 POWER COMPANY
(Exact name of registrant as specified in its charter)
MINNESOTA 41-0462685
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
215 S. CASCADE ST., BOX 496, FERGUS FALLS, MN 56538-0496
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (218) 739-8200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
NONE NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON SHARES, par value $5.00 per share
PREFERRED SHARE PURCHASE RIGHTS
CUMULATIVE PREFERRED SHARES, without par value
(Title of class)
Indicate by check mark 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. (X)
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant.
$438,940,176 as of February 29, 2000
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of the latest practicable date (adjusted to reflect the
two-for-one stock split effective March 15, 2000):
23,849,974 Common Shares ($5 par value) as of February 29, 2000.
Documents Incorporated by Reference:
1999 Annual Report to Shareholders-Portions incorporated by reference into
Parts I and II
Proxy Statement dated March 10, 2000-Portions incorporated by reference into
Part III
PART I
Item 1. BUSINESS
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(a) General Development of Business
-------------------------------
Otter Tail Power Company (the Company) is an operating public utility
incorporated in 1907 under the laws of the State of Minnesota. The Company's
principal executive office is located at 215 South Cascade Street, Box 496,
Fergus Falls, Minnesota 56538-0496; its telephone number is (218) 739-8200.
Historically, the Company's primary business has been the production,
transmission, distribution and sale of electric energy. During the last
decade the Company, through its subsidiaries, has made significant investments
in other businesses which are referred to as Manufacturing Operations, Health
Services Operations and Other Business Operations. Manufacturing Operations
includes businesses involved in the production of polyvinyl chloride (PVC)
pipe, agricultural equipment, frame-straightening equipment and accessories
for the auto body shop industry, contract machining, and metal parts stamping
and fabrication. Health Services Operations consists of certain businesses
which are involved in the sale, service, rental, refurbishing, and operation
of medical imaging equipment and the sale of related supplies and accessories
to various medical institutions. Other Business Operations include businesses
involved in such areas as electrical and telephone construction contracting,
transportation, telecommunications, entertainment, energy services, and
natural gas marketing. Substantially all of these businesses are owned by the
Company's wholly owned subsidiary Varistar Corporation (Varistar).
The Company continues to investigate acquisitions of additional
non-electric businesses and expects continued growth in this area. On
September 1, 1999 the Company acquired the flatbed trucking operations of E.
W. Wylie Corporation (Wylie). Wylie is located in Fargo, North Dakota and
operates in 48 states and 6 Canadian provinces. Effective January 1, 2000 the
Company acquired the assets and operations of Vinyltech Corporation
(Vinyltech) located in Phoenix, Arizona. Vinyltech is a manufacturer of PVC
pipe.
In August 1999, as part of an agreement with the Minnesota Pollution
Control Agency (MPCA), the Company donated the assets of the Quadrant Co.
municipal waste burning facility to the City of Perham, Minnesota. On October
1, 1999 the Company completed the sale of certain assets of the radio stations
and video production company owned by KFGO, Inc. and the radio stations owned
by Western Minnesota Broadcasting Company. See "Other Business Operations" for
additional information regarding these subsidiaries.
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 20 through 26 of the
Company's 1999 Annual Report to Shareholders, filed as an Exhibit hereto.
(b) Financial Information About Industry Segments
---------------------------------------------
The Company and its subsidiaries are engaged in businesses that have
been classified into four segments: Electric Operations, Manufacturing
Operations, Health Services Operations, and Other Business Operations.
Financial information about the Company's industry segments is incorporated by
reference to note 4 of "Notes to consolidated financial statements" on pages
36 and 37 of the Company's 1999 Annual Report to Shareholders, filed as an
Exhibit hereto.
(c) Narrative Description of Business
---------------------------------
ELECTRIC OPERATIONS
-------------------
General
- -------
The Company derived 50 percent of its consolidated operating revenues
from the electric segment in 1999; 53 percent in 1998; and 51 percent in 1997.
In 1999 the Company derived approximately 50.8 percent of its retail electric
revenues from Minnesota, 41.3 percent from North Dakota, and 7.9 percent from
South Dakota.
The territory served by the Company is predominantly agricultural,
including a part of the Red River Valley. Although there are relatively few
large customers, sales to commercial and industrial customers are significant.
By customer category, 30.8 percent of 1999 electric revenue was derived from
commercial customers, 28.2 percent from residential customers, 17.4 percent
from industrial customers, and 23.6 percent from other sources, including
municipalities, farms and power pools.
No customer accounted for more than 10 percent of electric revenues in
1999. Power pool sales to other utilities, which accounted for 26.3 percent
of total 1999 kwh sales, increased from 25.5 percent in 1998. Hot summer
weather in the Midwest and North Central regions of the United States,
combined with increased emphasis on power marketing efforts and increased
generation at the Company's plants contributed to the increase in power pool
revenues. Activity in short-term energy sales is subject to change based on a
number of factors and the Company is unable to predict the 2000 level of
activity.
The aggregate population of the Company's retail electric service area
is approximately 230,000. In this service area of 423 communities and
adjacent rural areas and farms, approximately 123,600 people live in
communities having a population of more than 1,000, according to the 1990
census. The only communities served which have a population in excess of
10,000 are Jamestown, North Dakota (15,571); Fergus Falls, Minnesota (12,362);
and Bemidji, Minnesota (11,245). Since 1990 when the customer count was at a
low of 121,277, the Company has experienced an increase in customers. By year
end 1999 total customers had increased to 126,292. During 1999, the Company
experienced a net increase of 580 customers, with the majority of growth in
residential customers.
Competition
- -----------
The Company's 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. The Company's electricity
also competes with other forms of energy. The degree of competition may vary
from time to time depending on relative costs and supplies of other forms of
energy. The Company may also face competition as the restructuring of the
electric industry evolves. Proposals that are being considered by various
states and at the federal level, along with the National Energy Policy Act of
1992 (NEPA), are expected to bring more competition into the electric
industry. NEPA reduces restrictions on operation and ownership of independent
power producers (IPPs). It also allows IPPs and other wholesale suppliers and
purchasers increased access to transmission lines.
In 1996, FERC issued two closely related final rules. FERC Order No.
888 opened wholesale power sales to competition by requiring public utilities
who own, control, or operate transmission lines, to file nondiscriminatory
pro forma open access tariffs that offer others the same transmission service
they provide themselves. FERC Order No. 889 requires utilities to post or
make available information about their transmission system for their own
wholesale power transactions, such as capacity availability, by the same means
as their competitors would via an Open Access Same-time Information System
(OASIS), as well as separate their wholesale marketing and transmission
operation functions.
As the electric industry moves towards deregulation, the Company expects
the industry to become more competitive. The Company is taking a number of
steps to position itself for success in a competitive marketplace. The
Company has functionally unbundled its energy supply, energy delivery, and
energy services operations. Necessary accounting systems have been developed
to capture costs and determine the profitability of each of these business
units and to identify areas for improvement and opportunities for increased
profitability. Separate business plans have been created for each business
unit. The Company has established an energy services business unit to promote
the energy-related products and services traditionally offered to the
Company's customers and to develop new products and services to be offered to
current and potential customers in order to distinguish the Company for
competition. The Company offered a voluntary early retirement program in 1998
that reduced the electric utility staff by 55 employees. Furthermore, with the
goal of alleviating state tax inequities in the electric industry, the Company
is working with other utilities to develop tax reform proposals and testimony
for legislative committees studying competition in Minnesota and
North Dakota.
As the electric industry evolves and becomes more competitive, the
Company believes it is well positioned to be successful. The Company's
generation capacity appears poised for competition due to unit heat rate
improvements and reductions in fuel and freight costs. A comparison of the
Company's electric retail rates to the rates of other investor-owned
utilities, cooperatives, and municipals in the states the Company serves
indicates that the Company's rates are competitive. In addition, the Company
plans to attempt more flexible pricing strategies under an open, competitive
environment.
For the status of other regulatory initiatives relating to competition,
see "General Regulation".
Capability and Demand
- ---------------------
At December 31, 1999, the Company had base load net plant capability
totaling 566,593 kw, consisting of 254,731 kw from the jointly-owned Big Stone
Plant (constituting the Company's 53.9 percent share of the plant's total
capability), 156,825 kw from the Hoot Lake Plant, 149,450 kw from the jointly-
owned Coyote Station (constituting the Company's 35 percent share of the
station's total capability), and, under contract, 5,587 kw from a co-
generation plant near Bemidji, Minnesota. In addition to its base load
capability, the Company has combustion turbine and small diesel units, used
chiefly for peaking and standby purposes, with a total capability of 91,175
kw, and hydroelectric capability of 3,991 kw. During 1999, the Company
generated about 66 percent of its total kwh sales and purchased the balance.
The Company has made arrangements to help meet its future base load
requirements, and continues to investigate other means for meeting such
requirements. The Company has an agreement with another utility for the annual
exchange of 75,000 kw of seasonal capacity which runs through October 2004.
The Company 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 from May 1, 2000 to April 30, 2010. The Company also
has seasonal capacity agreements for the summers of 2000, 2001 and 2002. The
Company has a direct control load management system, which provides some
flexibility to the Company to effect reductions of peak load. The Company, in
addition, offers rates to customers which encourage off-peak usage.
The Company is a member of the Mid-Continent Area Power Pool (MAPP). The
objective of MAPP is to coordinate the planning and operation of generation
and interconnecting transmission facilities to provide reliable and economic
electric service to members' customers. Customers served by MAPP members may,
therefore, benefit from the regional high voltage interconnections, which are
capable of transferring large blocks of energy between systems. Also, high
voltage interconnections permit companies to engage in power transactions with
each other. The operating agreement for MAPP was restated in 1996 to open
membership to organizations outside the original Upper Midwest boundaries, to
establish a Regional Transmission Group and to add energy market functions.
In December 1999 the Federal Energy Regulatory Commission issued Order
No. 2000. This order requires public utilities that own, operate or control
interstate transmission to file by October 15, 2000 a proposal for a regional
transmission organization (RTO) or a description of any efforts made to
participate in an RTO, the reasons for not participating, and any plans for
further work towards participation. The Company, along with several other
companies and MAPP, are working with the Midwest Independent System Operator
(MISO) to become a part of MISO and to be compliant with Order No. 2000.
The Company traditionally experiences its peak system demand during the
winter season. For the calendar year 1999, the Company experienced a system
peak demand of 628,259 kw on January 13, 1999. The Company's highest sixty-
minute peak demand ever was 635,529 kw on January 7, 1997. Taking into account
additional capacity available to it in January 1999 under power purchase
contracts (including short-term arrangements), as well as its own generating
capacity, the Company's capability of then meeting system demand, including
reserve requirements computed in accordance with accepted industry practice,
amounted to 787,593 kw. The Company expects moderate load growth in peak demand
in 2000 as compared to 1999. The Company's additional capacity available under
power purchase contracts (as described above), combined with the Company's
generating capability and load management control capabilities, is expected to
meet 2000 system demand, including industry reserve requirements.
Fuel Supply
- -----------
Coal is the principal fuel burned by the Company at its Big Stone,
Coyote, and Hoot Lake generating plants. Coyote, a mine-mouth facility,
burns North Dakota lignite coal. Hoot Lake and Big Stone plants burn western
subbituminous coal. The following table shows, for 1999, the sources of energy
used to generate the Company's net output of electricity:
Net Kilowatt % of Total
Hours Kilowatt
Generated Hours
Sources (Thousands) Generated
------- ----------- ---------
Subbituminous Coal. . . . . . . . . . . 2,485,191 70.1%
Lignite Coal. . . . . . . . . . . . . . 1,027,045 29.0
Hydro . . . . . . . . . . . . . . . . . 25,035 .7
Oil . . . . . . . . . . . . . . . . . . 8,777 .2
--------- -----
Total . . . . . . . . . . . . . . . . . 3,546,048 100.0%
========= =====
The Company has a primary coal supply agreement with Kennecott Energy
Company for the supply of subbituminous coal to Big Stone Plant for 2000 and
2001. The coal comes from the Cordero Rojo Complex in Campbell County,
Wyoming. The Company is in final negotiations for the supply of subbituminous
coal as needed for the Hoot Lake Plant. A lignite coal contract with Knife
River Coal Mining Company for the Coyote Station expires in 2016, with a
15-year renewal option subject to certain contingencies. Knife River Coal
Mining Company is an affiliate of Montana-Dakota Utilities Co., which is a
co-owner of the Big Stone Plant and Coyote Station.
In September 1996, three of the four co-owners of the Coyote Station
filed a Demand and Notice of Arbitration complaint against Knife River Coal
Mining Company and MDU Resources Group, Inc. The three co-owners contended
that the 15-year-old pricing mechanism outlined in the original coal supply
contract had been abandoned by all parties over the past 8 years and no longer
resulted in fair, equitable, and competitive prices for the lignite coal used
to generate electricity at the plant. During 1999 settlement of the
arbitration resulted in (1) a reduction of fuel prices for Coyote Station,
beginning March 26, 1999, (2) modification of the price adjustment provision
of the contract for the future, and (3) a requirement that Knife River refund
excess amounts paid for coal delivered from September 13, 1996 through March
26, 1999. The Company received a refund of $2.7 million, representing its
share as a co-owner of Coyote Station. This refund and accumulated interest
has been recorded as a liability pending the outcome of regulatory filings in
each state to determine procedures for refunds to electric retail customers.
The regulatory filings include a request to recover arbitration costs incurred
by the Company. Responses to the Company's regulatory filings are expected by
mid-2000.
It is the Company'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.
The Company has two coal transportation agreements with The Burlington
Northern and Santa Fe Railway Company. The first agreement is for
transportation services to the Big Stone Plant which runs through 2001. The
second agreement is 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 1999, 1998, and 1997,
was $.956, $.960, and $.957, respectively.
The Company is permitted by the State of South Dakota to burn some
alternative fuels, including tire and refuse 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.
Rate Regulation
- ---------------
The Company is subject to electric rate regulation as follows:
Year Ended
December 31, 1999
-----------------
% of
Electric % of kwh
Rates Regulation Revenues Sales
----- ---------- -------- --------
MN retail sales MN Public Utilities
Commission 40.5% 38.1%
ND retail sales ND Public Service
Commission 33.0 30.0
SD retail sales SD Public Utilities
Commission 6.3 5.6
Transmission & sales FERC
for resale 20.2 26.3
----- -----
100.0% 100.0%
===== =====
The Company has obtained approval from the regulatory commissions in all
three states which it serves for lower rates for residential demand control
and controlled service, 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 Company
facilities, while encouraging use of cost-effective electricity instead of
other fuels and giving customers more control over the size of their electric
bill.
All of the Company's electric rate schedules now in effect, except for
wheeling, certain municipal and area lighting services and certain
interruptible rates, provide for adjustments in rates based upon the cost of
fuel delivered to the Company's generating plants, as well as for adjustments
based upon the cost of electric power energy purchased by the Company. Such
adjustments are presently based upon a two-month moving average in Minnesota
and under FERC regulation, a three-month moving average in South Dakota, and a
four-month moving average in North Dakota and are applied to the next billing
after becoming applicable.
The following summarizes the electric rate proceedings since January 1,
1995 and describes the procedures for rate requests with the Minnesota Public
Utilities Commission (MPUC), the South Dakota Public Utilities Commission
(SDPUC), the North Dakota Public Service Commission (NDPSC) and FERC:
Minnesota: On July 21, 1999, the MPUC approved the Company's 1998
financial incentive filing, which included the recovery of associated lost
margins and financial incentives of $1,829,000 from implementing conservation
programs and performance in meeting energy savings goals. The MPUC indicated
its intention to review the ongoing role of financial incentives for utility
investments in conservation. Due to the uncertain future of financial
incentives, no accrual was made for the 1999 financial incentives. On January
27, 2000, the MPUC approved a new Shared-Savings DSM Financial Incentive Plan
for 1999 and 2000, which awards utilities a small share of the total benefits
from investments in conservation.
Since 1995, the Company has recovered demand-side management related
costs, under Minnesota's Conservation Improvement Programs, through the use of
an annual recovery mechanism approved by the MPUC. In 1999, the MPUC approved
a 1.5 percent surcharge on all Minnesota customers' bills starting on July 1,
1999, for the recovery of conservation-related costs over and above those
being recovered in current rates. The previous 12-month period surcharge was
2.75 percent. The current surcharge rate will be in place until June 30,
2000 when it will be revised for subsequent years' program results.
The Company has not had a significant rate proceeding before the MPUC
since July 1987. Under Minnesota law, the MPUC must allow implementation of an
interim rate increase, subject to refund with interest, sixty days after the
initial filing date of a rate increase request, except that the MPUC is not
required to allow implementation of the interim rate increase until four
months after the effective date of a previous rate order. The amount of the
interim rate increase will be calculated using the proposed test year cost of
capital, the rate of return on common equity most recently granted to the
Company by the MPUC, and rate base and expense items allowed by a currently
effective MPUC order. In addition, if the MPUC fails to make a final
determination regarding any rate request within ten months after the initial
request is filed, then the requested rate is deemed to be approved, except if
(1) an extension of the procedural schedule (in case of a contested rate
increase request) has been granted, in which case the schedule of rates will
be deemed to have been approved by the MPUC on the last day of the extended
period of suspension of the rate increase, or (2) a settlement has been
submitted to and rejected by the MPUC, and the MPUC does not make a final
determination concerning the schedule of rates, in which case the schedule of
rates will be deemed to have been approved sixty days after the initial or,
if applicable, the extended period of suspension of the rate increase.
North Dakota: On October 6, 1999, the NDPSC approved a settlement
agreement following an audit of the Company's electric operations in North
Dakota. The effect of this settlement decreased 1999 earnings by
approximately $441,000 after taxes or $0.02 per share. As part of the
settlement the Company is required to refund to North Dakota customers any
1999 regulated electric operations earnings from North Dakota over a 12.5
percent return on equity. While the final decision on any potential refund
relating to 1999 lies with the NDPSC, the Company expects that any refund
will not be significant. In addition, as part of the settlement agreement,
the Company filed a proposal for a performance-based ratemaking plan in 2000.
Rate requests filed with the NDPSC become effective thirty days after the
date of filing unless suspended by the NDPSC. Within seven months after the
date of suspension, the NDPSC must act on the request, and during the period
of consideration by the NDPSC a suspended rate can be implemented only with
the approval of the NDPSC. The NDPSC periodically performs audits of gas and
electric utilities over which it has rate setting jurisdiction to determine
reasonability of overall rate levels. In the past, these audits have
occasionally resulted in settlement agreements adjusting rate levels.
South Dakota: There have been no significant rate proceedings in South
Dakota since November 1987. Under South Dakota law a requested rate increase
can be implemented thirty days after the date of filing, unless its
effectiveness is suspended by the SDPUC. The SDPUC may suspend the
effectiveness of the proposed rate change for a period not longer than ninety
days beyond the time when the rate change would otherwise go into effect,
unless the SDPUC finds that a longer time is required, in which case the SDPUC
may extend the suspension for a period not to exceed a total of twelve months.
A public utility may not put a proposed rate change into effect until at least
forty-five days after the SDPUC has made a determination concerning any
previously filed rate change. In the event that a requested rate change is
suspended by the SDPUC, such requested rate change may be implemented by the
public utility six months after the date of filing (unless previously
authorized by the SDPUC), subject to refund with interest.
FERC: The Company's wholesale power sales and transmission rates are
subject to the jurisdiction of the FERC under the Federal Power Act of 1935,
as amended (FPA). Filed rates are effective after a one-day suspension
period, subject to ultimate approval by the FERC. Power pool sales are
conducted continuously through MAPP in accordance with schedules filed by
MAPP with the FERC.
On March 25, 1997, FERC issued an order approving a settlement
agreement in the Company's Open Access Transmission Tariff filing of July 9,
1996. This settlement sets the rates the Company can charge under its Open
Access Transmission Tariff. On May 29, 1997, FERC issued an order approving a
request for the waiver of the standards of conduct under Order 889.
General Regulation
- ------------------
Minnesota: Under the Minnesota Public Utilities Act, the Company is
subject to the jurisdiction of the MPUC with respect to rates, issuance of
securities, depreciation rates, public utility services, construction of major
utility facilities, establishment of exclusive assigned service areas,
contracts and arrangements with subsidiaries and other affiliated interests,
and other matters. The MPUC has the authority to assess the need for large
energy facilities and to issue or deny certificates of need, after public
hearings, within six months of an application to construct such a facility.
The Department of Commerce (DOC), formerly Department of Public Service,
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 conserva-
tion. The DOC acts as a state advocate in matters heard before the MPUC.
The DOC also has the power to prepare and adopt regulations to conserve and
allocate energy in the event of energy shortages and on a long-term basis.
Under Minnesota law, every public utility that furnishes electric service
must make annual investments and expenditures in energy conservation
improvements, or make a contribution to the state's energy and conservation
account, in an amount equal to at least 1.5 percent of its gross operating
revenues from service provided in Minnesota. The DOC may require the Company
to make investments and expenditures in energy conservation improvements
whenever it finds that the improvement will result in energy savings at a
total cost to the utility less than the cost to the utility to produce or
purchase an equivalent amount of a new supply of energy. Such 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. In 1995, the MPUC
approved an automatic recovery mechanism which allows the Company to collect
from customers any conservation-related expenditures not included in base
rates.
The MPUC requires the submission of a 15-year advance integrated resource
plan by utilities serving at 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 Company's
most recent plan was submitted to the MPUC in 1999, and was approved, without
modifications, early in 2000. The MPUC ordered the Company to complete a study
on the feasibility of offering its customers a green pricing program. Under
green pricing, customers may voluntarily choose to pay more per kilowatt-hour
for energy generated by renewable resources. The green pricing study is to
be filed with the MPUC no later than July 1, 2001. The MPUC also granted the
Company a one-year waiver in submitting its next integrated resource plan,
which will be completed in 2002.
The Minnesota legislature has enacted a statute that favors conservation
over the addition of new resources. In addition, it has mandated the use of
renewable resources where new supplies are needed, unless the utility proves
that a renewable energy facility is not in the public interest. It has
effectively prohibited the building of new nuclear facilities. The
environmental externality law requires the MPUC, to the extent practicable,
to quantify the environmental costs of each type of generation, and to use
such monetized values in evaluating resource plans. The MPUC must disallow
any nonrenewable rate base additions (whether within or 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 hearings, to select or designate in Minnesota sites for new electric power
generating plants (50,000 kw or more) and routes for transmission lines (200
kv or more) and to certify such sites and routes as to environmental
compatibility.
North Dakota: The Company is subject to the jurisdiction of the NDPSC with
respect to rates, services, certain issuances of securities and other matters.
The North Dakota Energy Conversion and Transmission Facility Siting Act grants
the NDPSC the authority to approve sites in North Dakota for large electric
generating facilities and high voltage transmission lines. This Act is
similar to the Minnesota Power Plant Siting Act described above and affects
new electric power generating plants of 50,000 kw or more and new transmission
lines of more than 115 kv. The Company is required to submit a ten-year plan
to the NDPSC annually.
South Dakota: The South Dakota Public Utilities Act subjects the Company
to the jurisdiction of the SDPUC with respect to rates, public utility
services, establishment of assigned service areas, and other matters. The
Company is currently exempt from the jurisdiction of the 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.
FERC: The Company is also subject to regulation by the FERC, successor to
the Federal Power Commission, created pursuant to the FPA. The FERC is an
independent agency which has jurisdiction over rates for sales for resale,
transmission and sale of electric energy in interstate commerce,
interconnection of facilities, and accounting policies and practices.
General: The United States Congress ended its 1999 legislative session
without taking action on proposed electric industry restructuring legislation.
The Company expects that during 2000 Congress will continue to debate
proposed legislation which, if enacted, would promote customer choice and a
more competitive electric market.
The MPUC issued its Wholesale Competition Report in 1996 and its Retail
Competition Report in 1997 and continues to work on specific topics in the
areas of potential stranded costs, unbundled rates and affiliated
transactions. The Minnesota legislature did not take any significant
legislative action on electric utility restructuring in 1999, and no
significant action is expected during 2000. However, the DOC plans to draft
comprehensive retail access legislation that could be introduced in early
2001. Company personnel have been actively involved in working with the
DOC-sponsored work groups and a legislative task force. The Minnesota State
Chamber of Commerce introduced legislation in 2000 relating to the separation
of costs for generation, transmission and distribution on electric service
statements. In 1997, the North Dakota legislature created a subcommittee to
investigate the impact of electric utility industry restructuring on North
Dakota. The North Dakota legislature plans to deal first with tax issues
surrounding restructuring. Currently, South Dakota is not undertaking any
legislative activity regarding electric utility restructuring.
The Company is subject to various federal and state laws, including the
Federal Public Utility Regulatory Policies Act and the Energy Policy Act of
1992, which are intended to promote the conservation of energy and the
development and use of alternative energy sources.
The Company is unable to predict the impact on its operations resulting
from future regulatory activities by any of the above agencies, from any
future legislation or from any future tax that may be imposed upon the source
or use of energy.
Environmental Regulation
- ------------------------
Impact of Environmental Laws: The Company's existing generating plants
are subject to stringent federal and state standards and regulations
regarding, among other things, air, water and solid waste pollution. The
Company estimates that it has expended in the five years ended December 31,
1999, approximately $2,565,000 for environmental control facilities. Included
in the 2000-2004 construction budget are approximately $5,065,000 for
environmental equipment for existing and new facilities, including $276,000
for 2000.
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.
All primary fuel burned by the Company at its steam generating plants is
North Dakota lignite or western subbituminous coal. Electrostatic
precipitators have been installed at the principal units at the Hoot Lake
Plant and at the Big Stone Plant. A fabric filter to collect particulates
from stack gases has been installed on a smaller unit at Hoot Lake Plant. As
a result, the units at the Big Stone Plant and the Hoot Lake Plant currently
meet all presently applicable federal and state air quality and emission
standards.
The Coyote Station is substantially the same design as the Big Stone
Plant, except for site-related items and the inclusion of sulfur dioxide
removal equipment. The removal equipment--referred to as a dry scrubber--
consists of a spray dryer, followed by a fabric filter, and is designed to
desulfurize hot gases from the stack without producing sludge, an unwanted
by-product of a conventional wet scrubber system. 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 oxide (NOx).
The national SO2 emission reduction goals are achieved through a new
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. The SO2 emission
reduction requirements were imposed in two phases. Phase one was imposed in
1995 and phase two was imposed in 2000.
The phase one requirements did not apply to any of the Company's plants.
The phase two requirements will apply to the Company's plants. The Company
believes that its current use of low sulfur coal at the Hoot Lake Plant and
the dry scrubbers installed at the Coyote Station will enable the facilities
to comply with anticipated phase two limitations on SO2 emissions. The
subbituminous coal burned at the Big Stone Plant replaced lignite, which had
been used since inception of plant operation in 1975 as the primary fuel. The
Company intends that the Big Stone Plant will maintain current levels of
operation and meet phase two requirements by burning low sulfur subbituminous
coal.
The national NOx emission reduction goals are to be achieved by imposing
mandatory emissions standards on individual sources. The NOx emissions
regulations that were issued by the EPA in 1995 apply to phase one boilers of
the same design as those used at the Hoot Lake Plant units 2 and 3. The Act
allowed the EPA to retain the standard as it currently applies to phase one
boilers or adopt more stringent standards for phase two boilers by January 1,
1997. The EPA adopted more stringent standards on December 19, 1996. The
Company had the option of complying with the phase one standards beginning on
January 1, 1997, under EPA's early opt-in provision, or complying with any
revised standard for phase two boilers. The Company elected the early opt-in
provision for Hoot Lake Plant unit 2. The unit is governed by the phase one
standard until January 1, 2008. The Company did not elect the early opt-in
provision for Hoot Lake Plant unit 3. Installation of low-NOx equipment was
completed on Hoot Lake Plant unit 3 to meet the NOx emission requirements.
On December 19, 1996, the EPA also adopted NOx emissions regulations
that would be applicable to cyclone-fired boilers such as those used at the
Big Stone Plant and Coyote Station. The regulations require that the emission
standard be met by cyclone boilers beginning on January 1, 2000. The Company
has evaluated the Big Stone Plant and Coyote Station NOx emissions with
respect to the December 19, 1996 rules. Existing emissions monitoring data
indicate that the Coyote Station meets the emissions requirements. During
1997, the Company conducted tests at the Big Stone Plant to determine if
emissions can be reduced through modifications to existing equipment. The
results of the tests were positive and modifications have been completed.
As a result of the modifications, the Company believes the NOx emissions
regulations have been met.
The Act contains a list of regulated toxic air pollutants, which
includes certain substances believed to be emitted by the Company's plants.
The Act calls for EPA studies of the effects of emissions of the listed
pollutants by electric utility steam generating plants. The EPA has completed
the studies and sent reports to Congress. Because promulgation of rules by
the EPA has not been completed, it is not possible to assess at this time
whether, or to what extent, this legislation will ultimately impact the
Company.
Water Quality: The Federal Water Pollution Control Act Amendments of
1972, and amendments thereto, provide for, among other things, the imposition
of effluent limitations to regulate discharges of pollutants, including
thermal discharges, into the waters of the United States, and the EPA has
established effluent guidelines for the steam electric power generating
industry. Discharges must also comply with state water quality standards.
The Company has all federal and state water permits presently necessary
for the operation of the Big Stone Plant. Water discharge permits for the
Hoot Lake Plant and Coyote Station were renewed in 1997 and 1998,
respectively, each for a five-year term. The Company owns five small dams
on the Otter Tail River, which are subject to FERC licensing requirements.
A license for all five dams was issued on December 5, 1991. Total nameplate
rating of the five dams is 3,450 kw (net unit capability of 3,441 kw at
December 31, 1999).
Solid Waste: Permits for disposal of ash and other solid wastes have
been issued for the Big Stone Plant and Coyote Station. A renewal permit is
pending for the Hoot Lake Plant, and the Company anticipates that it will
obtain this renewal in due course. The Company estimates that the current
ash disposal site at the Hoot Lake Plant will be filled to capacity within two
to three years. The Company is evaluating its options, including increased
marketing of the ash for construction purposes and building a new ash disposal
site adjacent to the current site within the same permitted area. Although an
estimate of the engineering costs required to construct a new facility has not
been completed, the Company believes that the investment required will not
have a significant impact on future plant operating costs.
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 Company of the various solid and
hazardous waste statutes and regulations enacted by the federal government or
the states of Minnesota, North Dakota and South Dakota is not certain at this
time. To date, the Company has incurred no significant costs as a result of
these laws.
In 1980, the United States enacted the Comprehensive Environmental
Response, Compensation and Liability Act, commonly known as the Federal
Superfund law, 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 Company is unable to determine the total impact of the Superfund laws on
its operations at this time but has not incurred any significant costs to
date related to these laws.
The Federal Toxic Substances Control Act of 1976 regulates, among other
things, polychlorinated byphenyls (PCBs). The EPA has enacted regulations
concerning the use, storage and disposal of PCBs. The Company completed a
program for the removal of PCB-filled transformers and capacitors by the end
of 1987 and received Certificates of Disposal in 1989. The Company completed
a removal program of PCB-contaminated mineral oil dielectric fluid from
substation transformers and voltage regulators and continues to remove such
oil from other electrical equipment.
Health Effects of Electric and Magnetic Fields (EMF): In 1996, the
National Research Council of the National Academy of Sciences, after
evaluating more than 500 studies on the effects of EMF, found insufficient
evidence to consider electric and magnetic fields a threat to human health.
Although research conducted to date has found no conclusive evidence that
electric and magnetic fields affect health, a few studies have suggested a
possible connection with cancer. The utility industry continues to fund
studies. The ultimate impact, if any, of this issue on the Company and the
utility industry is impossible to predict.
Capital Expenditures
- --------------------
The Company is continually expanding, replacing and improving its
electric utility facilities. During 1999, the Company invested approximately
$21,486,000 for additions to its electric utility properties. During the
five years ended December 31, 1999, the Company had gross electric property
additions, including construction work in progress, of approximately
$129,530,000 and gross retirements of approximately $49,534,000.
The Company estimates that during the five years 2000 through 2004 it
will invest approximately $125 million for electric utility construction.
The Company continuously reviews options for increasing its generating
capacity, but at this time has no firm plans for additional base load
generating plant construction. The majority of electric utility expenditures
for the five-year period 2000 through 2004 will be for work related to the
Company's transmission and distribution system.
Franchises
- ----------
At December 31, 1999, the Company had franchises 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 Company serves.
MANUFACTURING OPERATIONS
------------------------
General
- -------
Manufacturing Operations consists of businesses involved in the
following manufacturing activities: production of PVC pipe, agricultural
equipment, frame-straightening equipment and accessories for the auto body
shop industry, contract machining, and metal parts stamping and fabrication.
In January 2000, the Company through Varistar acquired the assets and
operations of Vinyltech Corporation. The Company derived 20 percent of its
consolidated operating revenues from this segment in 1999, 20 percent in
1998, and 21 percent in 1997.
The following is a brief description of each of these businesses:
Precision Machine, Inc., located in West Fargo, ND and Pelican Rapids,
MN, provides machining, foundry, and metal work for farm implement and
industrial equipment industries and produces parts to customers'
specifications from prototype to final production.
Dakota Machine, Inc., located in West Fargo, ND, manufactures sugar beet
pilers, continuous-pan sugar refiners, diffusion towers, and nearly all
other types of equipment used by sugar beet refineries.
BTD Manufacturing, Inc. (BTD), located in Detroit Lakes, MN, is a metal
stamping and tool and die manufacturer. BTD stamps, machines, and
assembles metal parts according to manufacturers' specifications
primarily for the recreation vehicle industry and industrial
manufacturers.
Northern Pipe Products, Inc., located in Fargo, ND, manufactures and
sells polyvinyl-chloride (PVC) pipe for municipal, rural water,
irrigation and other uses in a fifteen-state area.
Chassis Liner Corporation, located in Alexandria and Lucan, MN,
manufactures and sells vehicle frame-straightening equipment and
accessories used by the auto body shop industry.
Mid-States Testing Company, located in Moorhead, MN, sells and tests
rubber protective equipment for the electrical utility industry and
other electrical workers.
Vinyltech Corporation, located in Phoenix, AZ, manufactures and sells
PVC pipe in Arizona, California, Nevada, and other southwestern states.
Each of the subsidiaries described above are owned by Varistar.
Competition
- -----------
The various markets in which the Company's manufacturing 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 market, sugar beet
industry, auto body shop industry and PVC pipe market. The growth in these
markets has provided strong growth for the Company's manufacturing segment.
A downturn in these markets could have an adverse impact on the financial
results of the Company's manufacturing segment. In addition, Northern Pipe
Products and Vinyltech's gross margin percentages are related to PVC resin
prices. Due to the commodity nature of PVC resin and the dynamic supply and
demand factors worldwide, it is difficult to predict gross margin percentages
or assume that historical trends will continue.
Capital Expenditures
- --------------------
During 1999, capital expenditures of approximately $6.9 million were
made in Manufacturing Operations. Total capital expenditures for
Manufacturing Operations during the five-year period 2000-2004 are estimated
to be approximately $26 million.
HEALTH SERVICES OPERATIONS
--------------------------
General
- -------
Health Services Operations consists of businesses involved in the sale,
service, rental, refurbishing, and operation of medical imaging equipment and
the sale of related supplies and accessories to various medical institutions.
The Company derived 15 percent of its consolidated operating revenues from
this segment in 1999, 16 percent in 1998 and 17 percent in 1997.
Subsidiaries comprising Health Services Operations include the
following:
Diagnostic Medical Systems, Inc. (DMS), located in Fargo, ND, sells,
services, and refurbishes diagnostic medical imaging equipment and
related supplies and accessories. DMS sells radiology equipment
manufactured by several entities, including Philips Medical Systems
(Philips) a large multi-national company based in the Netherlands.
Philips manufacturers 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 located in Bemidji MN, operates
mobile and in-house diagnostic medical imaging equipment, including CT,
MRI, nuclear medicine services and other similar radiology services to
hospitals, clinics and other medical providers located in 23 states.
Combined, the Health Services subsidiaries cover the three basics of the
medical imaging industry: (1) ownership and operation of the imaging
equipment for health care 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.
Each of the subsidiaries described above are owned by Varistar.
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 the health
services segment compete with free-standing imaging centers and health care
providers that have their own diagnostic imaging systems and with equipment
manufacturers that sell imaging equipment to health care providers for full-
time installation. Some of their direct competitors, which provide contract
MRI services, have access to greater financial resources than the health
services companies. In addition, some of the health services companies'
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 within this segment compete against
other contract providers on the basis of quality of services, quality and
magnetic field strength of imaging systems, price, availability and
reliability.
Capital Expenditures
- --------------------
During 1999 capital expenditures of approximately $1 million were made
in Health Services. Total capital expenditures during the five-year period
2000-2004 are estimated to be $42 million.
OTHER BUSINESS OPERATIONS
-------------------------
General
- -------
The Company's Other Business Operations consists of businesses that are
diversified in such areas as electrical and telephone construction
contracting, transportation, telecommunications, entertainment, energy
services, and natural gas marketing. During August 1999, the assets of the
Quadrant municipal waste burning facility were donated to the City of Perham,
Minnesota. On September 1, 1999, the Company acquired through Varistar, the
flatbed trucking operations of E. W. Wylie Corporation. The Company completed
the sale of certain assets of the radio stations and video production company
owned by KFGO, Inc. and the radio stations owned by Western Minnesota
Broadcasting Company during October, 1999. The Company derived 15 percent of
its consolidated operating revenues from these diversified businesses in 1999,
11 percent in 1998, and 11 percent in 1997.
The following is a brief description of each of these businesses:
Moorhead Electric, Inc., located in Moorhead, MN, installs data cable
for commercial and industrial computer networks, underground fiber-optic
and copper cable for the telecommunications industry, and electrical
wiring in residential, commercial, and industrial settings.
Aerial Contractors, Inc., located in West Fargo, ND, builds and repairs
overhead and underground electric distribution and transmission lines
and substations, and installs underground fiber-optic, copper and
coaxial cable for the telecommunications industry.
Midwest Information Systems, Inc., headquartered in Parkers Prairie, MN,
operates telephone and cable television businesses that together operate
approximately 7,000 access lines.
E. W. Wylie Corporation, located in Fargo, ND, is a contract and common
carrier that operates a fleet of tractors and trailers in 48 states and
6 Canadian provinces.
Otter Tail Energy Services Company (OTESCO), headquartered in Fergus
Falls, MN was established in 1997 to pursue opportunities in the natural
gas and electricity markets. It offers technical services, engineering
services, performance-based service contracting and financial services
related to these products. OTESCO has one subsidiary, Otter Tail Energy
Management Company (OTEMCO), which was formed as a result of the
acquisition of PAM Natural Gas, Inc. OTEMCO is a marketer of natural
gas to commercial and institutional customers in Iowa, South Dakota,
North Dakota and Minnesota.
With the exception of OTESCO, Varistar owns each of the subsidiaries
described above. OTESCO is a wholly owned subsidiary of Minnesota-Dakota
Generating Company, which in turn is a wholly owned subsidiary of the Company.
General Regulation
- ------------------
The Company's operating telephone subsidiaries are subject to the
regulatory authority of the MPUC regarding rates and charges for telephone
services, as well as other matters. The operating telephone subsidiaries must
keep on file with the 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 FCC. The Company's operating 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.
Capital Expenditures
- --------------------
During 1999, capital expenditures of approximately $4.7 million were
made in Other Business Operations. Capital expenditures during the five-year
period 2000-2004 are estimated to be approximately $17 million for Other
Business Operations.
FINANCING
---------
The Company estimates that funds internally generated net of forecasted
dividend payments, combined with funds on hand, will be sufficient to meet
sinking fund payments on First Mortgage Bonds and preferred stock redemption
requirements in the next five years and to provide for its estimated 2000-2004
consolidated capital expenditures. Additional short-term or long-term
financing will be required in the period 2000 through 2004 for the maturity
of long-term debt, in the event the Company decides to refund or retire early
any of its presently outstanding debt or Cumulative Preferred Shares, or for
other corporate purposes.
The foregoing estimates of capital expenditures and funds internally
generated may be subject to substantial changes due to unforeseen factors,
such as changed economic conditions, interest rates, demand for energy,
availability of energy within the power pool, cost of capacity charges
relative to cost of new generation, competitive conditions, technological
changes, acquisitions or divestitures of subsidiary companies, new
environmental and other governmental regulations, tax law changes, and rate
regulation.
The Company's operating subsidiaries have been responsible for obtaining
their own financing after the Company's initial equity investment and have
developed financing arrangements with various banks. The Company has not
typically made or guaranteed loans to its subsidiaries, or cosigned on any
subsidiary's borrowing.
The Company has access to short-term borrowing resources. As of December
31, 1999, the Company and its subsidiaries had unused credit lines totaling
$32.7 million.
EMPLOYEES
---------
The Company and its subsidiaries had approximately 1,973 full-time
employees at December 31, 1999. A total of 496 employees are represented by
local unions of the International Brotherhood of Electrical Workers, of which
389 are employees of the Electric Operations segment and are covered by a
three-year labor contract that was renewed in 1999 and expires November 1,
2002. The Company has never experienced any strike, work stoppage, or strike
vote, and considers its present relations with employees as very good.
Forward Looking Information - Safe Harbor Statement Under the Private
---------------------------------------------------------------------
Securities Litigation Reform Act of 1995
----------------------------------------
In connection with the "safe harbor" provisions of the Private
Securities Litigation Reform Act of 1995 (the Act), the Company has filed
cautionary statements identifying important factors that could cause the
Company's actual results to differ materially from those discussed in forward-
looking statements made by or on behalf of the Company. When used in this
Form 10-K and in future filings by the Company with the Securities and
Exchange Commission, in the Company's press releases and in oral statements,
words such as "may", "will", "expect", "anticipate", "continue", "estimate",
"project", "believes" or similar expressions are intended to identify forward-
looking statements within the meaning of the Act. Factors that might cause
such differences include, but are not limited to, governmental and regulatory
action, the competitive environment, economic factors, weather conditions, and
other factors discussed under "Factors affecting future earnings" on pages 24
and 25 of the Company's 1999 Annual Report to Shareholders, filed as an
Exhibit hereto. These factors are in addition to any other cautionary
statements, written or oral, which may be made or referred to in connection
with any such forward-looking statement or contained in any subsequent filings
by the Company with the Securities and Exchange Commission.
Item 2. PROPERTIES
----------
The Coyote Station, which commenced operation in 1981, is a 414,000 kw
(nameplate rating) mine-mouth plant located in the lignite coal fields near
Beulah, North Dakota and is jointly owned by the Company, Northern Municipal
Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service
Company. The Company has a 35 percent interest in the plant and was the
project manager in charge of construction. On July 1, 1998, the Company
became the operating agent of the Coyote Station.
The Company, jointly with Northwestern Public Service Company and
Montana-Dakota Utilities Co., owns the 414,000 kw (nameplate rating) Big
Stone Plant in northeastern South Dakota which commenced operation in 1975.
The Company, for the benefit of all three utilities, was in charge of
construction and is now in charge of operations. The Company owns 53.9
percent 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
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, 1999, the Company's transmission facilities, which are
interconnected with lines of other public utilities, consisted of 48 miles of
345 kv lines; 363 miles of 230 kv lines; 684 miles of 115 kv lines; and 4,179
miles of lower voltage lines, principally 41.6 kv. The Company owns the
uprated portion of the 48 miles of the 345 kv line, with Minnkota Power
Cooperative retaining title to the original 230 kv construction.
In addition to the properties mentioned above, the Company owns and has
investments in offices and service buildings. Through Varistar, the Company
owns facilities and equipment used to manufacture polyvinyl chloride pipe and
perform metal stamping, fabricating, and contract machining; construction
to equipment and tools, medical imaging equipment, a fleet of flatbed trucks,
and the infrastructure to maintain approximately 7,000 access lines in its
telecommunication companies.
Management of the Company believes that the facilities and equipment
described above are adequate for the Company's present businesses.
All of the Company's electric utility properties, with minor exceptions,
are subject to the lien of the Company's Indenture of Mortgage dated July 1,
1936, as amended and supplemented, securing its First Mortgage Bonds. All of
the common shares of the companies owned by 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, 1999.
Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2000)
----------------------------------------------------------
Set forth below is a summary of the principal occupations and business
experience during the past five years of executive officers of the Company:
DATES ELECTED
-------------
NAME AND AGE TO OFFICE PRESENT POSITION AND BUSINESS EXPERIENCE
- ------------ ------------- ----------------------------------------
John C. MacFarlane (60) 4/8/91 Present: Chairman, President and Chief
Executive Officer
John D. Erickson (41) 10/26/98 Present: Vice President, Finance and
Chief Financial Officer
Prior to
10/26/98 Director, Market Strategies &
Regulation
Marlowe E. Johnson (55) 4/12/93 Present: Vice President, Customer
Service, North Dakota
Douglas L. Kjellerup (58) 2/1/99 Present: Chief Operating Officer,
Energy Delivery; Vice President,
Marketing and Development
Prior to
2/1/99 Vice President, Marketing and
Development
LeRoy S. Larson (54) 4/12/93 Present: Vice President, Customer
Service, Minnesota and South
Dakota
Jay D. Myster (61) 10/1/98 Present: Corporate Secretary
Prior to
10/1/98 Senior Vice President,
Governmental and Legal,
and Corporate Secretary
Rodney C.H. Scheel (50) 4/10/95 Present: Vice President, Electrical
Prior to
4/10/95 Director, Information Services
Ward L. Uggerud (50) 2/1/99 Present: Chief Operating Officer,
Energy Supply; Vice President,
Operations
Prior to
2/1/99 Vice President, Operations
Jeffrey J. Legge (43) 4/10/95 Present: Controller
Prior to
4/10/95 Manager, Tax Department
The term of office of each of the officers is one year. Any officer
elected may be removed by the vote of the Board of Directors at any time
during the term.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
-----------------------------------------------------------------
MATTERS
-------
The information required by this Item is incorporated by reference to
the first sentence under "Otter Tail Power Company stock listing" on Page 50,
to "Selected consolidated financial data" on Page 19 and to "Quarterly
information" on Page 43 of the Company's 1999 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 19 of the Company's 1999
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 20 through 26 of the Company's 1999 Annual Report to
Shareholders, filed as an Exhibit hereto.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
----------------------------------------------------------
The Company does not have material market risk exposure related to
foreign currency exchange rate risk, commodity price risk or interest rate
risk.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-------------------------------------------
The information required by this Item is incorporated by reference to
"Quarterly information" on Page 43 and the Company's audited financial
statements on Pages 27 through 43 of the Company's 1999 Annual Report to
Shareholders excluding "Report of Management" on Page 27, 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 "Nominees for Election as
Directors" in the Company's definitive Proxy Statement dated March 10, 2000.
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 10, 2000.
Item 11. EXECUTIVE COMPENSATION
----------------------
The information required by this Item is incorporated by reference to
the information under "Summary Compensation Table," "Option/SAR Grants in Last
Fiscal Year," "Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal
Year-End Option/SAR Values," "Pension and Supplemental Retirement Plans,"
"Severance Agreements," and "Directors' Compensation" in the Company's
definitive Proxy Statement dated March 10, 2000.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------------------------------------
The information required by this Item is incorporated by reference to
the information under "Outstanding Voting Shares" and "Security Ownership of
Management" in the Company's definitive Proxy Statement dated March 10, 2000.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
----------------------------------------------
None.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
---------------------------------------------------------------
(a) List of documents filed:
(1) and (2) See Table of Contents on Page 22 hereof.
(3) See Exhibit Index on Pages 23 through 28 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 POWER COMPANY
By /s/ John D. Erickson
------------------------
John D. Erickson
Vice President, Finance
and Chief Financial
Officer
Dated: March 28, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature and Title
- -------------------
John C. MacFarlane )
Chairman, President and )
Chief Executive Officer )
(principal executive officer) )
and Director )
)
John D. Erickson )
Vice President, Finance and )
Chief Financial Officer )
(principal financial officer) )
)
Jeffrey J. Legge ) By /s/ John D. Erickson
Controller ) -------------------------
(principal accounting officer) ) John D. Erickson
) Pro Se and Attorney-in-Fact
) Dated March 28, 2000
Thomas M. Brown, Director )
)
Dayle Dietz, Director )
)
Dennis R. Emmen, Director )
)
Maynard D. Helgaas, Director )
)
Arvid R. Liebe, Director )
)
Kenneth L. Nelson, Director )
)
Nathan I. Partain, Director )
)
Robert N. Spolum, Director )
OTTER TAIL POWER COMPANY
TABLE OF CONTENTS
-----------------
FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL FINANCIAL
SCHEDULES INCLUDED IN ANNUAL REPORT (FORM 10-K) FOR THE YEAR ENDED
DECEMBER 31, 1999
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,
1999:
Page in
Annual
Report to
Shareholders
------------
Financial Statements:
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . 27
Consolidated Balance Sheets, December 31, 1999 and 1998. . . . . .28 & 29
Consolidated Statements of Income for the Three Years
Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 30
Consolidated Statements of Changes in Common Shareholders' Equity for the
Three Years Ended December 31, 1999. . . . . . . . . . . . . . . . . . 31
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 32
Consolidated Statements of Capitalization, December 31, 1999
and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Notes to Consolidated Financial Statements . . . . . . . . . . . . .34-43
Selected Consolidated Financial Data for the Five Years
Ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 19
Quarterly Data for the Two Years Ended
December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Schedules are omitted because of the absence of the conditions under which
they are required or because the information required is included in the
financial statements or the notes thereto.
Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 1999
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
3-A 10-Q for quarter 3 --Restated Articles of
ended 6/30/99 Incorporation, as amended
(including resolutions
creating outstanding series
of Cumulative Preferred Shares).
3-C 33-46071 4-B --Bylaws as amended through
April 11, 1988.
4-D-1 2-14209 2-B-1 --Twenty-First Supplemental
Indenture from the Company to
First Trust Company of Saint
Paul and Russel M. Collins, as
Trustees, dated as of July 1,
1958.
4-D-2 2-14209 2-B-2 --Twenty-Second Supplemental
Indenture dated as of
July 15, 1958.
4-D-3 33-32499 4-D-7 --Thirty-Second Supplemental
Indenture dated as of
January 18, 1974.
4-D-4 33-46070 4-D-12 --Forty-Third Supplemental
Indenture dated as of
February 1, 1991.
4-D-5 33-46070 4-D-13 --Forty-Fourth Supplemental
Indenture dated as of
September 1, 1991.
4-D-6 8-K dated 4-D-15 --Forty-Fifth Supplemental
7/24/92 Indenture dated as of
July 1, 1992.
4-D-7 8-A dated 1 --Rights Agreement, dated as of
1/28/97 January 28, 1997 (the Rights
Agreement), between the
Company and Norwest Bank Minnesota,
National Association.
4-D-8 8-A/A dated 1 --Amendment No. 1, dated as of
9/29/98 August 24, 1998, to the Rights
Agreement.
10-A 2-39794 4-C --Integrated Transmission
Agreement dated August 25,
1967, between Cooperative
Power Association and the
Company.
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-A-1 10-K for year 10-A-1 --Amendment No. 1, dated as
ended 12/31/92 of September 6, 1979, to
Integrated Transmission
Agreement, dated as of
August 25, 1967, between
Cooperative Power Associa-
tion and the Company.
10-A-2 10-K for year 10-A-2 --Amendment No. 2, dated as of
ended 12/31/92 November 19, 1986, to Integ-
rated Transmission Agreement
between Cooperative Power
Association and the Company.
10-C-1 2-55813 5-E --Contract dated July 1, 1958,
between Central Power Elec-
tric Corporation, Inc.,
and the Company.
10-C-2 2-55813 5-E-1 --Supplement Seven dated
November 21, 1973.
(Supplements Nos. One
through Six have been super-
seded and are no longer in
effect.)
10-C-3 2-55813 5-E-2 --Amendment No. 1 dated
December 19, 1973, to
Supplement Seven.
10-C-4 10-K for year 10-C-4 --Amendment No. 2 dated
ended 12/31/91 June 17, 1986, to Supple-
ment Seven.
10-C-5 10-K for year 10-C-5 --Amendment No. 3 dated
ended 12/31/92 June 18, 1992, to Supple-
ment Seven.
10-C-6 10-K for year 10-C-6 --Amendment No. 4 dated
ended 12/31/93 January 18, 1994, to Supple-
ment Seven.
10-D 2-55813 5-F --Contract dated April 12,
1973, between the Bureau of
Reclamation and the Company.
10-E-1 2-55813 5-G --Contract dated January 8,
1973, between East River
Electric Power Cooperative
and the Company.
10-E-2 2-62815 5-E-1 --Supplement One dated
February 20, 1978.
10-E-3 10-K for year 10-E-3 --Supplement Two dated
ended 12/31/89 June 10, 1983.
10-E-4 10-K for year 10-E-4 --Supplement Three dated
ended 12/31/90 June 6, 1985.
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-E-5 10-K for year 10-E-5 --Supplement No. Four, dated
ended 12/31/92 as of September 10, 1986.
10-E-6 10-K for year 10-E-6 --Supplement No. Five, dated
ended 12/31/92 as of January 7, 1993.
10-E-7 10-K for year 10-E-7 --Supplement No. Six, dated
ended 12/31/93 as of December 2, 1993.
10-F 10-K for year 10-F --Agreement for Sharing
ended 12/31/89 Ownership of Generating
Plant by and between the
Company, Montana-Dakota
Utilities Co., and North-
western Public Service
Company (dated as of
January 7, 1970).
10-F-1 10-K for year 10-F-1 --Letter of Intent for pur-
ended 12/31/89 chase of share of Big Stone
Plant from Northwestern
Public Service Company
(dated as of May 8, 1984).
10-F-2 10-K for year 10-F-2 --Supplemental Agreement No. 1
ended 12/31/91 to Agreement for Sharing
Ownership of Big Stone Plant
(dated as of July 1, 1983).
10-F-3 10-K for year 10-F-3 --Supplemental Agreement No. 2
ended 12/31/91 to Agreement for Sharing
Ownership of Big Stone Plant
(dated as of March 1, 1985).
10-F-4 10-K for year 10-F-4 --Supplemental Agreement No. 3
ended 12/31/91 to Agreement for Sharing
Ownership of Big Stone Plant
(dated as of March 31, 1986).
10-F-5 10-K for year 10-F-5 --Amendment I to Letter of
ended 12/31/92 Intent dated May 8, 1984, for
purchase of share of Big Stone
Plant.
10-G --Big Stone Plant Coal Agreement
by and between the Company, Northwestern
Public Service, Montana-Dakota
Utilities Co., and Kennecott
Energy Company (dated as of
December 16, 1999). **
10-G-1 10-Q for quarter 10-B --Big Stone Coal Transportation
ended 9/30/94 Agreement by and between the
Company, Montana-Dakota
Utilities, Northwestern Public
Service Co., and Burlington
Northern Railroad Company
(dated as of July 18, 1994).
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-G-2 10-K for year 10-G-2 --Amendment No. 1, dated as of
ended 12/31/95 December 27, 1995, to Big
Stone Coal Transportation
Agreement (dated as of
July 18, 1994).
10-G-3 --Amendment No. 2, dated as of
June 10, 1999, to Big Stone
Stone Coal Transportation
Agreement (dated as of
July 18, 1994). **
10-H 2-61043 5-H --Agreement for Sharing Owner-
ship of Coyote Station
Generating Unit No. 1 by and
between the Company, Minnkota
Power Cooperative, Inc.,
Montana-Dakota Utilities Co.,
Northwestern Public Service
Company, and Minnesota Power
& Light Company (dated as of
July 1, 1977).
10-H-1 10-K for year 10-H-1 --Supplemental Agreement No.
ended 12/31/89 One dated as of November 30,
1978, to Agreement for Sharing
Ownership of Coyote Generating
Unit No. 1.
10-H-2 10-K for year 10-H-2 --Supplemental Agreement No.
ended 12/31/89 Two dated as of March 1, 1981,
to Agreement for Sharing
Ownership of Coyote Generating
Unit No. 1 and Amendment No. 2
dated March 1, 1981, to Coyote
Plant Coal Agreement.
10-H-3 10-K for year 10-H-3 --Amendment dated as of
ended 12/31/89 July 29, 1983, to Agreement
for Sharing Ownership of
Coyote Generating Unit No. 1.
10-H-4 10-K for year 10-H-4 --Agreement dated as of Sept.
ended 12/31/92 5, 1985, containing Amendment
No. 3 to Agreement for Sharing
Ownership of Coyote Generating
Unit No.1, dated as of July 1,
1977, and Amendment No. 5 to
Coyote Plant Coal Agreement,
dated as of January 1, 1978.
10-I 2-63744 5-I --Coyote Plant Coal Agreement
by and between the Company,
Minnkota Power Cooperative,
Inc., Montana-Dakota
Utilities Co., Northwestern
Public Service Company,
Minnesota Power & Light
Company, and Knife River
Coal Mining Company (dated
as of January 1, 1978).
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-I-1 10-K for year 10-I-1 --Addendum, dated as of March
ended 12/31/92 10, 1980, to Coyote Plant
Coal Agreement.
10-I-2 10-K for year 10-I-2 --Amendment (No. 3), dated as
ended 12/31/92 of May 28, 1980, to Coyote
Plant Coal Agreement.
10-I-3 10-K for year 10-I-3 --Fourth Amendment, dated as
ended 12/31/92 of August 19, 1985, to
Coyote Plant Coal Agreement.
10-I-4 10-Q for quarter 19-A --Sixth Amendment, dated as of
ended 6/30/93 February 17, 1993, to Coyote
Plant Coal Agreement.
10-K 10-K for year 10-K --Diversity Exchange Agreement
ended 12/31/91 by and between the Company
and Northern States Power
Company, (dated as of May 21,
1985) and amendment thereto
(dated as of August 12, 1985).
10-K-1 10-Q for quarter 10 --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 --Hoot Lake Coal Transportation
Agreement by and between the
Company and The Burlington
Northern and Santa Fe Railway
Company (dated as of July 19, 1999).**
10-N-1 10-K for year 10-N --Deferred Compensation Plan
ended 12/31/91 for Directors, dated
April 9, 1984.*
10-N-2 10-K for year 10-N-2 --Executive Survivor and Sup-
ended 12/31/94 plemental Retirement Plan,
as amended.*
10-N-3 --Form of Severance
Agreement.*
Previously Filed
----------------
As
Exhibit
File No. No.
-------- -------
10-N-4 10-K for year 10-N-5 --Nonqualified Profit Sharing
ended 12/31/93 Plan.*
10-N-5 10-K for year 10-N-6 --Nonqualified Retirement
ended 12/31/93 Savings Plan.*
10-N-6 10-K for year 10-N-6 --1999 Employee Stock
ended 12/31/98 Purchase Plan.
10-N-7 10-K for year 10-N-7 --1999 Stock Incentive Plan.*
ended 12/31/98
13-A --Portions of 1999 Annual
Report to Shareholders
incorporated by reference
in this Form 10-K.
21-A --Subsidiaries of Registrant.
23 --Consent of Deloitte & Touche LLP.
24-A --Powers of Attorney.
27 --Financial Data Schedule.
- --------
* Management contract or compensatory plan or arrangement required to be filed
pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.
** Confidential information has been omitted from such Exhibit and filed
separately with the Commission pursuant to a confidential treatment request
under Rule 24b-2.
EXHIBIT 10-G
Confidential information has been omitted from this Exhibit and filed
separately with the Commission pursuant to a confidential treatment
request under Rule 24b-2.
COAL SUPPLY AGREEMENT
by and between
OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE,
MONTANA-DAKOTA UTILITIES CO.
and
KENNECOTT ENERGY COMPANY
2000 - 2001
December 16, 1999
TABLE OF CONTENTS
Page No.
--------
1. TERM . . . . . . . . . . . . . . . . . . . . . 1
2. QUANTITY . . . . . . . . . . . . . . . . . . . 2
3. SOURCE . . . . . . . . . . . . . . . . . . . . 3
4. COAL QUALITY . . . . . . . . . . . . . . . . . 3
5. PRICING . . . . . . . . . . . . . . . . . . . 4
6. BILLING AND PAYMENT . . . . . . . . . . . . . 5
7. SAMPLING AND ANALYSIS . . . . . . . . . . . . 6
8. WEIGHING AND LOADING . . . . . . . . . . . . . 8
9. FORCE MAJEURE . . . . . . . . . . . . . . . . 9
10. TITLE . . . . . . . . . . . . . . . . . . . . 10
11. TERMINATION AND CANCELLATION . . . . . . . . . 10
12. INDEMNITY AND LIABILITY . . . . . . . . . . . 10
13. LAWS AND REGULATIONS . . . . . . . . . . . . . 10
14. NOTICES . . . . . . . . . . . . . . . . . . . 10
15. CONFIDENTIALITY . . . . . . . . . . . . . . . 11
16. WARRANTY AND LIABILITY . . . . . . . . . . . . 11
17. DISPUTE RESOLUTION . . . . . . . . . . . . . . 11
18. MISCELLANEOUS . . . . . . . . . . . . . . . . 13
COAL SUPPLY AGREEMENT
by and between
OTTER TAIL POWER COMPANY, NORTHWESTERN PUBLIC SERVICE,
MONTANA-DAKOTA UTILITIES CO.
and
KENNECOTT ENERGY COMPANY
THIS COAL SUPPLY AGREEMENT ("Agreement") is made and entered into as
of December 16, 1999 (the "Effective Date"), by and between OTTER TAIL
POWER COMPANY, NORTHWESTERN PUBLIC SERVICE, a Division of Northwestern
Corporation, MONTANA-DAKOTA UTILITIES CO., a Division of MDU Resources
Group, Inc., hereinafter together called "Buyers or Buyer" and CORDERO
MINING COMPANY AND CABALLO ROJO INC., wholly owned subsidiaries of Kennecott
Energy and Coal Company, and Kennecott Energy Company, an affiliate of
Kennecott Energy and Coal Company, hereinafter together called "Seller."
BACKGROUND:
A. Seller desires to sell coal from its Cordero Rojo Complex,
consisting of the Cordero and Caballo Rojo mines located in Campbell County,
Wyoming ("the Mine"), under the terms and conditions herein set forth; and
B. Buyers are public utilities engaged in the production of
electricity and the furnishing of electric service to the public;
C. Buyers, pursuant to the Agreement for Sharing Ownership of
Generating Plant dated as of January 7, 1970, own and operate the Big Stone
Power Plant located near Milbank, South Dakota (the "Plant");
D. To produce electricity at the Plant, Buyers need to secure an
adequate supply of coal of the quality and quantity as set forth in this
Agreement; and
NOW, THEREFORE, for and in consideration of the mutual covenants and
agreements of the parties contained herein, Seller agrees to sell and
deliver to Buyers and Buyers agree to purchase, receive and pay for coal
from Seller upon the following terms and conditions:
1. TERM
----
The Term of this Agreement shall be for * years commencing on
January 1, 2000 and terminating on * unless sooner terminated as provided in
Section 11 of this Agreement.
2. QUANTITY
--------
(a) Minimum and Maximum Amounts
---------------------------
Throughout the Term, Seller shall supply and sell and Buyer shall
purchase a minimum of * tons and a maximum of * tons of coal each
calendar year. Buyer shall provide Seller a written nomination of the
annual tonnage amount within ten (10) days of the Effective Date for
calendar year 2000 and *. Said nominated amounts shall be within the range
of the above referenced minimum and maximum amounts and shall be the annual
quantity ("Annual Quantity") of coal that Buyer is obligated to purchase and
Seller is obligated to sell and supply for such calendar year.
(b) Delivery Schedule
-----------------
Deliveries shall be scheduled to occur in monthly quantities during
each calendar year, with the first shipments of coal to be delivered to the
Plant in sufficient quantities to allow the Plant to begin burning the coal
on or before January 1, 2000. Within ten (10) days of the Effective Date,
Buyer shall provide Seller with its written monthly schedule for calendar
year 2000; *. In providing the monthly schedules to Seller, Buyer shall use
its best faith efforts to provide an accurate estimate of its projected need
for coal on a monthly basis. Buyer shall use best efforts to keep monthly
quantities approximately equal except for scheduled overhaul and test burn
periods. However, the parties agree that the monthly schedules are for the
convenience of the parties and in no way binding on the Buyer and that no
penalty of any kind shall accrue to Buyer if for any reason the Buyer is (1)
unable to take delivery of the amount of monthly coal scheduled or (2) takes
delivery of more coal than scheduled in order to make-up for any previous
months' deficiencies. Except as provided in Section 2(c) below, any
variance in the amount of monthly coal scheduled and actually delivered
shall not relieve either Seller or Buyer from their respective obligations
to sell and purchase the minimum amounts of coal set forth in Section 2(a).
(c) Reduction in Quantities
-----------------------
Where, through fault of the Buyer, Buyer fails to take delivery of the
amount of coal scheduled for any month because an appropriate amount of
suitable and compatible unit trains is not provided to Seller, the following
shall apply: Seller shall have the option at its discretion to reduce, in
the affected calendar year, the amount of coal that it is obligated to
provide under Section 2(a) in the amount that Buyer fails to take delivery.
Seller may reduce its supply obligation only by giving Buyer written notice
of its intent to do so within 10 days of the end of the calendar quarter in
which the failure to take delivery occurs. When Seller provides such notice
to Buyer, such notice shall also relieve Buyer of any further obligation
with regard to purchasing or taking delivery of the reduced amount. Seller's
option to reduce its supply obligation as provided above does not apply when
the failure to provide an appropriate amount of suitable and compatible unit
trains is not through any fault of Buyer. Failure by the rail car carrier
to provide an appropriate amount of suitable and compatible unit trains to
Seller shall not be considered the fault of the Buyer. Buyer agrees,
however, to use its best efforts to assure that the appropriate amount of
suitable and compatible unit trains is provided to the Seller by the rail
car carrier, in order to take the amount of coal scheduled for delivery
during each calendar month.
(d) Additional or Lesser Quantities
-------------------------------
Buyer and Seller may agree to increase or decrease the Annual Quantity
as nominated by Buyer in Section 2(a) throughout the Term by designating any
such increase or decrease in a written instrument signed by duly authorized
representatives of the parties.
(e) Additional Cost to Buyer through Fault of Seller
------------------------------------------------
Where Seller fails, through no fault of the Buyer or rail car carrier,
to load Buyer's rail cars with coal on a timely basis that causes coal to be
delivered to Buyer on an untimely basis or not at all, and where, as a
result, Buyer incurs additional costs in a commercially prudent and
verifiable manner, either because Buyer must use coal that it did not plan
to use from its outside, inactive storage stockpile or secure coal from
other sources, Seller shall be responsible to Buyer for these prudent and
verifiable additional costs. Seller shall have the right of first refusal
to provide the coal to replenish Buyer's outside inactive storage stockpile.
Any additional coal provided by Seller under this section will increase the
nominated amount of coal (pursuant to Section 2(a)) on a ton-per-ton basis.
3. SOURCE
------
The source of coal to be sold pursuant to this Agreement shall be
mined and supplied from the Mine. Seller represents and warrants that the
Mine contains coal of a quality and in quantities which will be sufficient
to satisfy the requirements of this Agreement. Seller further warrants that
the title to all coal delivered under this Agreement shall be good and that
such coal shall be delivered free from any claim, lien or other encumbrance.
4. COAL QUALITY
------------
Coal supplied hereunder will be substantially free from impurities and
foreign matter such as, but not limited to, dirt, bone, slate, earth, rock,
pyrite, wood, tramp metal and mine debris prior to leaving the Mine. Coal
will be raw, run-of-mine, crushed to 2" x 0" (ASTM). Seller represents that
typical values of BTUs, moisture, ash, sulfur, and the values for other
quality characteristics are as set forth in Exhibit A to this Agreement.
Seller shall make its best commercial efforts to provide Buyer by facsimile
transmission an analysis of the trainload of coal within twenty-four hours
of loading the coal on the train for shipment to the Plant, Sunday through
Thursday, and within forty-eight hours Friday and Saturday. Where the
analysis shows that the coal fails to meet the minimum of the specification
set forth in Exhibit A for BTUs by * or maximums of the specifications set
forth in Exhibit A by the following amounts - * Ash; * Sulfur; or * Moisture
- - Buyer shall have the right but not the obligation to reject the coal within
twenty-four (24) hours of receiving the analysis from Seller.1 In the event
Buyer rejects such non-conforming coal, title to and risk of loss of the coal
shall be considered to have never passed to Buyer and Buyer may, at its sole
option, stop the shipment of the non-conforming coal in route, prevent the
unloading of the non-conforming coal, return the coal to Seller, or agree
with Seller on a different disposition for such coal, all at Seller's cost
and risk. Within twenty (20) working days from notice of rejection Seller
shall replace the non-conforming coal with coal conforming to the
specifications set forth above.
5. PRICING
-------
The price of coal supplied hereunder shall be based on the following
schedule. Prices will be per ton F.O.B. Buyer's railcars at the Mine (the
"Base Price"). The Base Price for each year includes all Governmental
Impositions as of December 16, 1999.
BASE PRICE
YEAR PER TON
- ---- -------
* *
* *
(a) Base Price
----------
The Base Price may be adjusted only in accordance with Paragraph b and
c of this Section 5.
(b) Governmental Impositions and Taxes
----------------------------------
Seller represents that the Mine is in compliance with all governmental
laws, rules and regulations in effect as of December 16, 1999, and that the
cost of such compliance, including Mine closure and all reclamation costs,
is included in the Base Price set forth in Section 5(a). If the imposition
or repeal of any law, regulation or ruling (including changes in
interpretations or administration of existing laws, regulations or rulings),
or change in tax rate, is adopted or becomes effective on or after
December 16, 1999 (hereinafter called "Governmental Imposition") and the
imposition, repeal, or change in tax rate was not known as of the Effective
Date, Seller shall demonstrate to Buyer, to Buyer's satisfaction, that such
Governmental Imposition has
____________
1 For example, Buyer shall have the right but not the obligation to
reject the coal where the analysis shows that the BTUs are less than *
or has an Ash content of more than *.
increased or decreased the cost of owning or operating the Mine as it
relates to the production of coal from the Mine for sale to Buyer under
this Agreement. Upon agreement of the parties, the then effective Base
Price shall be adjusted by adding or subtracting the per ton cost of the
Governmental Imposition to determine an adjusted Base Price. If the
Governmental Imposition will continue for the life of this Agreement,
then the Base Price, to be included in an extension of the term of this
Agreement, if any, shall also be adjusted by the per ton amount of the
Governmental Imposition.
Seller shall submit to Buyer in writing, an analysis identifying the
Governmental Imposition causing the cost impact and the extent of such cost
impact on ownership or operation of the Mine or on the production of coal
purchased hereunder and showing the calculation of the amount of change in
the Base Price. The effective date of any price increase or decrease
pursuant to this Section 5(b) shall be the effective date of the
Governmental Imposition causing the cost increase or decrease but, in no
event prior to the date of actual expenditure or accrual thereof by Seller.
(c) Adjustment for Calorific Value
------------------------------
The Base Price is calculated on the assumption of an average monthly
calorific coal value of * per pound (the "Specified Average");
provided, however, the parties recognize that the calorific value of coal
actually delivered hereunder may vary from such Specified Average. If the
weighted average calorific value of the coal furnished in any month deviates
from the Specified Average, then an adjustment will be made to the Base
Price of coal according to the following equation:
A = (B/C) X (D)
Where:
A - Adjusted Price rounded to the nearest mil ($.001)
B - Weighted average (BTUs per pound) calorific value of coal
delivered during the month.
C - Specified Average (BTUs per pound) calorific value of coal
which is * per pound.
D - Base Price
6. BILLING AND PAYMENT
-------------------
On or before the fifth (5th) and twentieth (20th) working day of each
month, Seller shall render to Buyer at its Plant address provided in Section
14 a semi-monthly invoice which shall indicate the actual tonnage and
weighted average calorific value of coal shipped during the previous billing
period and the Adjusted Price which takes calorific value into account as
defined in Section 5(c) and changes resulting from the changes in
Governmental Impositions, if any.
Buyer shall electronically pay such invoice within ten (10) working
days after receipt thereof. Unless advised in writing to send all payments
to another address, payment shall be sent by electronic means to:
First Security Bank of Utah
ABA No. 124000012
Account Number: 060-00064-56
Account Name: Cordero Mining Company/Caballo Rojo Inc. Receipts
If Buyer defaults on any payment, Buyer shall pay simple interest
thereon at the rate, not to exceed applicable State of Wyoming and Federal
laws, that shall be equal to two percent (2%) over the base rate of interest
charged by Citibank of New York or any successor bank on new ninety-day
loans to responsible and substantial commercial borrowers on the date the
interest charge begins. Such interest shall run from the date the payment
was due until it is paid.
If any invoice is in dispute, Buyer nevertheless shall pay the
undisputed amount, and if Buyer or Seller is due any credit or payment
pursuant to the resolution of the dispute, the simple interest on the credit
or payment shall be paid by the party owing such credit or payment at the
rate, not to exceed applicable State of Wyoming and Federal laws, that shall
be equal to two percent (2%) over the base rate of interest charged by
Citibank of New York or any successor bank on new ninety-day loans to
responsible and substantial commercial borrowers on the date of Buyer's
payment or credit from Seller of the disputed invoice and shall run until
the date payment or credit is made following resolution of the dispute.
Should Buyer fail to pay Seller for any amount due and owing in
accordance with this Section 6 within thirty (30) days after its receipt of
Seller's written demand for payment, then Seller shall also have the right,
but not the obligation, to suspend deliveries under this Agreement by so
notifying Buyer in writing. Should Buyer fail to pay Seller for any amount
due and owing in accordance with this Section 6 within ninety (90) days
after its receipt of Seller's written demand for payment, then Seller shall
have the right, but not the obligation to terminate this Agreement by so
notifying Buyer in writing.
Such suspension or termination shall become effective as of the date
that said written notice is received by Buyer. Neither Party shall accrue
any additional rights against the other as a result of a suspension or
termination permitted in this Section 6. Seller shall lose the right
provided in this Section 6 to suspend or terminate if it has not sent
written notice of such suspension or termination prior to Buyer's payment of
the amount due and owing. Seller's failure to exercise its right to suspend
or terminate as provided in this Section 6 shall not be deemed a waiver of
its right to suspend or terminate for any subsequent default by Buyer to
perform as provided in this Section 6.
7. SAMPLING AND ANALYSIS
---------------------
(a) Seller shall cause, at its expense, each shipment of coal to be
sampled and analyzed at the applicable mine in accordance with applicable
ASTM standards. Buyer shall have the right, at its risk and expense, to
have a representative present at any and all times to observe sampling and
analysis procedures. All samples shall be divided into three (3) parts and
put in suitable airtight containers. One part shall be furnished to Buyer
for its analysis, one part shall be retained for analysis by Seller or its
designee (which analysis shall be the basis for payment), and the third part
shall be retained by Seller or its designee in one of the aforesaid
containers properly sealed and labeled for a period forty-five (45) days
after the date of sample collection. Buyer's samples are to be clearly
labeled as to mine, date of sampling, date of preparation, and other
identification as to shipment (such as train identification number) and are
to be sent within forty-eight (48) hours of train loading, or prior to
arrival of train at destination, whichever comes first, to Buyer at the
address provided in Section 14.
(b) Seller shall perform at Seller's cost a "short proximate"
analysis (for moisture, ash, sulfur, sodium, and calorific value) for each
trainload sample and will forward such analysis to Buyer by a mutually
agreed upon method of electronic communication.
(c) If a dispute arises between Buyer and Seller concerning a
trainload sample due to a difference between Buyer's and Seller's analyses
within forty-five (45) days of the date on which the subject trainload was
loaded, an analysis of the third part shall be made by an independent
commercial testing laboratory, mutually chosen by Buyer and Seller. The
average of the results of the two (2) closest analyses with respect to the
disputed quality characteristic (among Seller's, Buyer's and the independent
laboratory's analyses) shall be controlling for purposes of the trainload in
question. The cost of analysis made by such independent commercial
laboratory shall be borne by the party whose analysis is not used in the
final determination; provided, however, in the event the commercial
laboratory's results are inconclusive and therefore not used, the cost of
the analysis shall be shared equally by the parties hereto.
(d) Seller shall provide Buyer the results of the proximate analysis
for each trainload of coal as soon as the results are available, but in any
event prior to the arrival of the subject train at the Plant. Upon Buyer's
written request and at Buyer's cost, Seller shall analyze shipments
designated by Buyer for mercury and chlorine content and submit such
analysis to Buyer.
(e) The results of the sampling and analysis performed by Seller
shall govern for purposes of determining any adjustments to the Base Price
of coal set forth in Section 5(c) for variations in calorific value, except
in the event a dispute arises under Section 7(c), in which event Section
7(c) shall control.
8. WEIGHING AND LOADING
--------------------
(a) Point of Delivery
-----------------
Coal will be delivered F.O.B. Buyer's railcars at Seller's railroad
loadout facility at the Mine. Upon completion of the loading of each
railcar, title and risk of loss for all coal loaded therein will pass to
Buyer. Buyer will arrange for the provision of suitable and compatible unit
trains of open-top railcars for the transportation of coal purchased by
Buyer under this Agreement.
(b) Loading Facilities and Procedure
--------------------------------
Seller will operate its loading facilities twenty-four (24) hours per
day, 365 days per year. Seller will load each unit train at Seller's
expense as closely as practicable to its full visible capacity. Seller will
complete the loading of each unit train within four (4) hours after the
first empty railcar is placed into position for loading. Unless excused by
Force Majeure as provided below, Seller will pay Buyer for any increased
transportation charges incurred as a result of Seller's failure to comply
with the freetime, overloading and underloading set forth in the excerpts
from Buyer's transportation agreement provisions as set forth in Exhibit C.
The parties agree that "Actual Placement," as set forth in Exhibit C
(section 10(B)(2)), means when the first empty railcar is placed under the
spout and ready for loading.
(c) Weighing
--------
The weight of coal sold and delivered under this Agreement shall be
determined on a per shipment basis by certified commercial scales at
Seller's train loading facility at the Mine. The weights thus determined
shall be accepted as the quantity of coal for which invoices are to be
rendered and payments made in accordance with Section 6. Seller shall
furnish the railroad company transporting the coal with copies of the
weights determined under this Agreement. Coal supplied under this Agreement
will be weighed at Seller's expense. Seller's scales used to determine such
weight shall be tested, calibrated and certified in accordance with
intervals of approximately every six (6) months by a qualified testing
agency. Seller shall use its best efforts to give Buyer no less than ten
(10) days notice of the anticipated time of scale test. Buyer shall also
have the right, at Buyer's expense and upon reasonable notice, to have the
scales checked for accuracy at any reasonable time or frequency. If the
scales are found to be over or under the tolerance range allowable for the
scale based on ASTM standards, either party shall pay to the other any
amounts owed due to such inaccuracy for a period not to exceed thirty (30)
days before the time any inaccuracy of scales is determined.
Buyer shall have the right, at its own cost and expense, to have a
representative present at any and all times to observe the weighings or
scale test, and in a manner that does not interfere with Seller's operation
of its Mines.
(d) Data Transmission
-----------------
Seller shall provide to Buyer within 48 hours of completion of loading
each train a train loading manifest for each train by a mutually agreed upon
method of electronic transmission.
9. FORCE MAJEURE
-------------
(a) Definition
----------
For purposes of this Agreement, the term "Force Majeure" is defined as
any cause or causes beyond the reasonable control and without the
intentional fault or willful negligence of the party affected thereby which
is the proximate cause of a party's whole or partial inability to perform
its obligations under this Agreement. For purposes of this Agreement, Force
Majeure includes, without limitation, Acts of God, unusual accumulations of
snow or ice, floods, frozen coal, interruptions of transportation,
interruptions or breakdowns of the power facilities connecting with Buyer or
Seller's facilities, embargoes, acts of civil authority (including State and
Federal agencies and courts of competent jurisdiction), acts of military
authority, war, insurrections, riots, strikes, lockouts, work stoppages,
labor or material shortages, or explosions, fires or unanticipated or non-
routine mechanical breakdowns (including shutdowns for emergency maintenance
or the like which may be necessary to mitigate or eliminate the imminent
threat of explosions, fires, or mechanical breakdowns) at the Mine or at
Buyer's Plant . Force Majeure also includes other causes of a similar
nature which wholly or partially prevent the mining, hauling, processing, or
loading of coal by Seller or the receiving, transporting, storing, unloading
or utilizing of coal by Buyer.
(b) Effect of Force Majeure
-----------------------
If, because of an event of Force Majeure, either Seller or Buyer is
unable to carry out any of its obligations under this Agreement, except
obligations to pay money to the other party due to coal already sold, and if
such party shall promptly give to the other party written notice of such
event of Force Majeure, then the obligations under this Agreement of the
party giving such notice shall be suspended to the extent made necessary by
such event of Force Majeure and will continue throughout the continuance of
such event; provided, however, that the party giving such notice shall use
good faith efforts to eliminate such event of Force Majeure or its effect
insofar as possible with a minimum of delay. Nothing herein contained shall
cause the party invoking Force Majeure to submit to what it considers to be
unreasonable conditions or restrictions, to make an unreasonable expenditure
of money or to submit to a labor Agreement it deems unfavorable, and it is
agreed that any settlement of labor strikes or difference with workmen shall
be entirely within the sole discretion of the affected party. Deficiencies
in receiving coal caused by a Force Majeure event shall be made up only upon
mutual consent between Buyer and Seller.
10. TITLE
-----
Title, right of possession and risks of loss of the coal shall pass
From Seller to Buyer upon loading into the railcar. Seller agrees to load in
equipment supplied by Buyer or Buyer's agent in accordance with industry
standards or rail carrier's instructions.
11. TERMINATION AND CANCELLATION
----------------------------
Either party to this Agreement may cancel this Agreement upon
written notice to the other party of such party's failure to comply with any
of the material provisions or obligations in this Agreement, provided that
notice of such failure has been given and not less than thirty (30) days
have elapsed with no curative action having commenced. Seller and Buyer may
terminate this Agreement immediately upon written notice to the other in the
event the other becomes insolvent or files for protection under any
applicable bankruptcy laws. Buyer shall remain obligated to pay for all
coal delivered by Seller and accepted by Buyer prior to the date of
termination or cancellation.
12. INDEMNITY AND LIABILITY
-----------------------
Each party hereby agrees to indemnify, save and hold harmless the
other, from and against all liability from damage to property or injury or
death of any person or persons arising out of or resulting from the willful
or negligent acts or omissions of such party, its agents and employees;
provided however, that when employees or agents of either party hereto enter
upon the premises of the other party, such entry shall be at the sole risk
of the party who is the employer of such employee or agent, and such
employer shall hold harmless the other party from all claims by its
employees or agent, unless such injury or death or damage to property is a
result of gross negligence.
13. LAWS AND REGULATIONS
--------------------
The Seller and Buyer shall comply with all applicable federal, state
and local laws, ordinances, statutes, codes, rules, and regulations in the
performance of its obligations under this Agreement.
14. NOTICES
-------
All notices required hereunder will be in writing and will be deemed
properly given when sent by telecopy, to the addresses as provided below, or
to such other addresses as Buyer or Seller may hereafter specify for such
purpose, provided that all notices will be confirmed immediately by
commercial delivery service, e.g., Federal Express or U.P.S. or registered
certified mail.
Buyer's address is: Seller's address is;
- ------------------- --------------------
Big Stone Plant Kennecott Energy Company
c/o Otter Tail Power Company 505 S. Gillette Avenue
P.O. Box 218 Caller box 3009
Big Stone City, SD 57216 Gillette, Wyoming 82717
Attn: Fuel Supervisor Attn: Contract Administration
Fax (605) 862-6344 Fax (307) 687-6009
With a courtesy notice to: With a courtesy notice to:
- -------------------------- --------------------------
Attn: Production Services John Turyn, Manager Sales
Otter Tail Power Company Kennecott Energy Company
215 South Cascade Street Suite 433, 6300 South Syracuse
Fergus Falls, MN 56537 Englewood, CO 80111
Fax: (218) 739-8629
15. CONFIDENTIALITY
---------------
Except as hereinafter provided, the terms and conditions set forth in
this Agreement, and all information supplied to the other party pursuant to
this Agreement, are considered by both Buyer and Seller to be confidential,
and neither party shall disclose any such information to any third party
without the advance written consent of the other party, which consent shall
not be unreasonably withheld, except where such disclosure may be required
by law or in connection with the assertion of a claim or defense in judicial
or administrative proceedings involving the parties hereto, in which event
the party required to make such disclosure shall advise the other in advance
in writing and shall cooperate to the extent practicable to minimize the
disclosure of any such information.
16. WARRANTY AND LIABILITY
----------------------
OTHER THAN THE WARRANTIES EXPRESSLY SET FORTH IN THIS AGREEMENT,
SELLER MAKES NO OTHER EXPRESS OR IMPLIED WARRANTIES, INCLUDING WITHOUT
LIMITATION, WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE
OR ARISING FROM A COURSE OF DEALING OR TRADE USAGE AND SELLER SHALL NOT BE
LIABLE, WHETHER AS TO COAL SHIPPED OR FOR THE FAILURE TO SHIP COAL
HEREUNDER, FOR ANY EXEMPLARY, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES
WHATSOEVER.
17. DISPUTE RESOLUTION
------------------
(a) No Party to this Agreement shall be entitled to take legal action
with respect to any dispute arising from or relating to the Agreement until
it has complied, in good faith, with the procedures set forth in sections
(b) and (c) below.
(b) Negotiation
-----------
(1) The parties shall attempt promptly and in good faith to
resolve any dispute arising out of or relating to this Agreement through
negotiations between representatives who have the authority to settle the
controversy. All negotiations pursuant to this clause shall be confidential
and treated as compromise and settlement negotiations for the purpose of the
federal and state rules of evidence.
(2) Either party may give the other written notice of any
dispute not resolved in the normal course of business. As soon as mutually
agreeable after delivery of this notice, representatives of the parties
shall meet at a mutually acceptable time and place (or by telephone), and
thereafter as often as they reasonably may deem necessary to attempt to
resolve the dispute. Unless the parties to the dispute agree that the
dispute cannot be resolved through unassisted negotiation, negotiations
shall not be deemed at an impasse until 60 days after the first settlement
conference.
(3) If a negotiator intends to be accompanied at a meeting by
any attorney, the other negotiator(s) shall be given at least three working
days' notice of such intention and may also be accompanied by an attorney.
(c) Alternative dispute resolution procedure
----------------------------------------
(1) If a dispute has reached impasse, either party may suggest
use of alternative dispute resolution ("ADR") procedures. Once that party
has notified the other of desire to initiate ADR, the parties may select the
ADR method they may wish to use by mutual agreement. That ADR method may
include arbitration, mediation, mini-trial, or any other method that best
suits the circumstances of the dispute. The parties shall agree in writing
to an ADR method selected and to the procedural rules to be followed as
promptly as possible. To the extent the parties are unable to agree on
procedural rules in whole or in part, the current center for public
resources ("CPR") model procedure for mediation of business disputes, CPR
model mini-trial procedure, or CPR commercial arbitration rules-whichever
applies to the chosen ADR method-shall control, to the extent such rules are
consistent with the provisions of this section.
(2) If the parties are unable to agree on an ADR method or
unwilling to use ADR to resolve the dispute, either party shall be free to
resort to litigation.
(3) If the parties agree on an ADR method other than
arbitration, the decision rendered in that proceeding shall not be binding
on any party except by agreement of the parties, and either party may seek
resolution of the dispute through litigation. If the parties agree on
arbitration as an ADR method, the decision of the arbitrator(s) shall be
binding on all parties, pursuant to the United States Arbitration Act 9 USCA
Sec. 1 et seq. The arbitrator(s) shall not award punitive or exemplary
damages against either party.
18. MISCELLANEOUS
-------------
(a) Governing Law. This Agreement shall be subject to and governed
by the laws of the State of Minnesota.
(b) Binding Effect. This Agreement shall inure to the benefit of and
be binding on the parties hereto, their successors and assigns.
(c) Assignment. Neither party hereto may assign this Agreement or
any rights or obligations hereunder, in whole or in part, without the prior
written consent of the other party, which consent shall not be unreasonably
withheld or denied. However, consent shall not be required for merger,
consolidation or sale of all or substantially all of the assets of a party.
(d) Severability. If any provision of this Agreement is found to be
contrary to law or unenforceable by a court of competent jurisdiction, the
remaining provisions shall be severable and enforceable in accordance with
their terms, unless such unlawful or unenforceable provision is material to
the transactions contemplated hereby, in which case the parties shall
negotiate in good faith a substitute provision.
(e) Amendments. Except as otherwise provided herein, this Agreement
may not be amended, supplemented or otherwise modified except by written
instrument signed by duly authorized representatives of the parties hereto.
(f) Headings. The descriptive headings contained in this Agreement
are for convenience only and do not constitute a part of this Agreement.
(g) Entire Agreement. This Agreement contains the entire agreement
and understanding between the parties hereto with respect to the subject
matter hereof and there are no representations, understandings or
agreements, oral or written, expressed or implied, that are not included
herein.
(h) Survival. At the time of termination of this Agreement or any
cancellation hereof, the appropriate provisions hereof shall survive as
necessary to complete any payment or credit provided for hereunder with
respect to coal sold and delivered prior to the date of such termination or
cancellation.
(i) Agreement Drafted Jointly. The parties agree that both parties
shared equally in the drafting of the Agreement and/or had full opportunity
to provide suggestions and/or language that reflects the intent of the
parties.
OTTER TAIL POWER COMPANY NORTHWESTERN PUBLIC SERVICE,
COMPANY a Division of
Northwestern Corporation
By: /s/ Ward Uggerud By: /s/ Glen R. Herr
------------------------------ -----------------------------------
Chief Operating Officer,
Title: Energy Supply Title: Executive Vice President & COO
--------------------------- ------------------------------
MONTANA-DAKOTA UTILITIES KENNECOTT ENERGY COMPANY, as
CO., a Division of Agent for and on behalf of
MDU Resources Group, Inc. Cordero Mining Company and
Caballo Rojo Inc.
By: /s/ Bruce Imsdahl By: /s/ Malcolm R. Thomas
------------------------------- ---------------------------------
Bruce Imsdahl
Title: Vice President Energy Supply Title: Vice President Market & Sales
----------------------------- ------------------------------
EXHIBIT A
1999-2001 CORDERO/ROJO COMPLEX FORECAST QUALITY 12/09/998
*
EXHIBIT B
(Estimated Governmental Impositions as of December 9, 1999)
*
Exhibit C - Attached
Excerpt from Coal Transportation Agreement By and Between Otter Tail Power
Company, Northwestern Public Service Company, Montana-Dakota Utilities Co.,
and Burlington Northern Railroad Company.
SECTION 9. WEIGHING
9(A) Weighing.
The parties agree that the weight of the Coal in the Coal Cars will be
determined at Origins by the UTILITIES' Origin Mine operator. BN shall not
be responsible for such weight determinations. The weights ascertained by
said operators pursuant to Section 11(J) shall be used for the assessment of
the freight charges thereunder. Weighing shall be performed on scales
inspected semi-annually, at no cost to BN, in accordance with the then-
current AAR Scale Handbook specifications for such scales, and subject to
supervision and verification by BN or its agent.
9(B) Breakdown Of Scales.
If weights cannot be determined due to a breakdown of the scales at Origins,
the weight per Train to be used for the assessment of freight charges
thereunder shall be determined by averaging the per car weights on the ten
(10) immediately preceding weighed shipments from the same Origin to
Destination, adjusted to any variance in the number of cars per shipment.
9(C) Gross Load Limit and Overloads.
If a loaded Coal Car is found by BN to weigh in excess 270,000 pounds, BN
shall, if necessary, switch said overloaded Coal Car and remove it from the
Train. BN retains the right to refuse to accept or transport overloaded
Car(s). BN is not be obligated to reduce the lading of such Car(s), which
obligation is solely UTILITIES' under this Agreement. After UTILITIES, at no
expense to BN, cause any excess Coal to be removed from the overloaded Coal
Car, BN shall replace the Coal Car into the Train. For such services in
removing and replacing each such Coal Car, UTILITIES shall pay a charge to
BN of $372.00 per Coal Car. If the excess Coal is removed during the Free
Time at Origin without removing the Coal Car from a Train, there shall be
no charge to UTILITIES. BN reserves the right to increase the maximum
gross weight on rail above 270,000 pounds. UTILITIES are not obligated
to ship in excess of 270,000 pounds.
SECTION 10. LOADING AND UNLOADING
10(A) Advance Notice and Loading.
(1) BN will make Trains of empty Coal Cars available at Origins for
loading. BN shall furnish the Origin Mine Operator not less than
four (4) hours advance notice by radio, telex, telephone or other
reasonable means of the arrival of such Trains of Coal Cars at
Origin for loading.
(2) UTILITIES and/or its Mine Operator shall be responsible for the
loading of Coal Cars. The parties agree to cooperate with the
Mine Operator to provide for the efficient loading of the Coal
Cars at an Origin. BN shall provide Locomotives and Train crews
to move Trains through the Loading Facility at a controlled
speed as designated by UTILITIES Mine Operator; PROVIDED,
HOWEVER, that BN will not be required to move Cars at a speed
less than five tenths (.5) mile per
CONFIDENTIAL CONTRACT ICC-BN-C-2913
10
hour, but to the extent it is able to operate at a lesser speed,
will upon request use its best efforts to do so.
10(B) Placement and Free Time - Origin.
(1) Four (4) hours free time will be allowed to load all empty Coal
Cars in a Train, commencing after the Actual or Constructive
Placement of the Train at the designated notification point at
the Origin ready for loading "Loading Free Time"); PROVIDED,
HOWEVER, that Loading Free Time shall be extended for a period
of time equivalent to that by which loading was prevented as a
result of (i) a Loading Disability, or (ii) any occurrence
attributable to BN which prevents loading. If BN fails to
provide four (4) hours advance notice of arrival at Origin, a
Train's Loading Free Time shall be extended by the additional
amount of time (but not to exceed four (4) hours) that it
takes to load a Train due to BN's failure to provide the required
notice. If a Train is not loaded and released during the
applicable Loading Free Time, BN may collect from UTILITIES an
Origin Detention Charge of $308.00 per hour (including any
fraction of an hour) until such time as the Train is loaded and
released.
(2) For purposes of this Section 10. "Actual Placement" is made
when a Unit Train arrives at Origin Mine's designated
notification point (as described in the BN timetable and the
Train crew has requested loading instructions. In the event a
Train cannot be Actually Placed at an Origin, notice shall be
given immediately to Origin Mine Operator by radio, telex,
telephone or other reasonable means, and BN may place
the Train at an available hold point until such time as Origin
Mine Operator notifies BN that Actual Placement can be made,
whereupon it shall be moved to Origin.
(3) For purposes of this Section 10, "Constructive Placement" begins
when a Train is placed at an available hold point because it is
prevented from being Actually Placed; PROVIDED, HOWEVER, that
Constructive Placement shall not take place when Actual
Placement is prevented (i) due to any cause that would extend
Loading Free Time, or (ii) because the Loading Free Time for
another Train ahead of the Train in question has not expired
("Origin Bunching"). The time required for the movement of a
Constructively Placed Train from a hold point to an Origin will
not be included in the computation of Free Time.
(4) "Loading Disability" means any of the following events which
directly result in the inability to load Coal into a Train at an
Origin: (i) an Act of God; (ii) a strike or other labor
disturbance; (iii) a riot or other civil disturbance; (iv) rain,
snow and/or ice accumulation sufficient to immobilize Train or
Mine operations or prevent loading of such Train; (v) an act of
regulation of local, state or federal government authorities;
or (vi) mechanical or electrical breakdown, explosion or fire
(including shutdown for emergency maintenance or the like which
may be necessary to mitigate or eliminate the imminent threat of
explosion, fire or mechanical or electrical breakdown), or
accident affecting a Loading Facility at the Origin then being
utilized by UTILITIES or affecting BN's locomotives or other
railroad equipment. UTILITIES or UTILTIES' Mine Operator shall
notify BN by telephone, telegraph, radio or other reasonable
means (i) within one and one-half (1.5) hours of the
commencement of a Loading Disability as to the nature and time
of commencement of the Loading Disability, and (ii) within one
and one-half (1.5) hours after the termination of a Loading
Disability as to the time of termination of the Loading
Disability, except that the notifications in (i) and (ii) above
shall not be necessary if the Loading Disability lasts for a
period of one and one-half (1.5) hours or less
(*) Confidential information has been omitted and filed separately with the
Commission pursuant to Rule 24b-2.
EXHIBIT 10-G-3
Confidential information has been omitted from this Exhibit and filed
separately with the Commission pursuant to a confidential treatment
request under Rule 24b-2.
SECOND AMENDMENT TO TRANSPORATION AGREEMENT
NUMBER ICC-BN-C-2913
This second Amendment to Coal Transportation Agreement numbered
ICC-BN-C-2913 is made pursuant to 49 U.S.C. Section 10709, between THE
BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY (BNSF), as successor to
Burlington Northern Railroad Company, and OTTER TAIL POWER COMPANY,
NORTHWESTERN PUBLIC SERVICE COMPANY, and MONTANA-DAKOTA UTILITIES
COMPANY, (hereinafter jointly referred to as "UTILITIES").
WHEREAS, BNSF and UTILITIES are parties to Transportation Agreement
numbered ICC-BN-C-2913, dated July 18, 1994, and amended on December 27,
1995, governing transportation of Coal in unit trains from Montana and
Wyoming Mine Origins to UTILITIES' Big Stone City steam electric power plant
near Big Stone City, SD (hereinafter referred to as the "Original Agreement");
WHEREAS, the parties desire to amend the Original Agreement to increase
its term.
NOW, THEREFORE, in consideration of the premises, covenants and
provisions set out herein, the parties hereto agree as follows:
1. EFFECTIVE DATE: This Second Amendment shall be effective on the date
last signed below, and shall continue in force through *.
2. From sub-section "2(B). Term of Agreement" delete the sentence "This
Agreement shall terminate at 11:59 p.m. Central Standard Time on December
31, 1999." and in its place substitute the following:
This Agreement shall terminate at midnight on *.
3. From the second paragraph of "Section 2. Effective Date and Term" of
the First Amendment of the Original Agreement delete the sentence "The term
of this First Amendment shall end at 11:59 p.m. Central Standard Time on
December 31, 1999." And in its place substitute the following:
This First Amendment shall terminate at midnight on *.
4. At the end of Sub-Section "3(A) Covered Mines, Origins or Mine Origins"
add the following Mine and BNSF Origin to Group D:
MINE BNSF ORIGIN
---- -----------
* *
5. From the first sentence of first paragraph of Sub-Section "7(C) Minimum
Tonnage Requirement or BTU Equivalent" delete the date "December 31, 1999"
and in its place substitute *.
6. From the first paragraph of Sub-Section "7(C) Minimum Tonnage
Requirement or BTU Equivalent" delete the term * and in its place
substitute *.
7. From the first paragraph of Sub-Section "7(C ) Minimum Tonnage
Requirement or BTU Equivalent" delete the example "EXAMPLE: Group B Origin
* and in its place substitute the following:
EXAMPLE: Group B Origin:
*
8. Delete the last sentence of subsection "14(C) Effect on Minimum Tonnage
Requirement or BTU Equivalent" and in its place substitute the following:
Force Majeure days shall be carried over into succeeding years for
purposes of calculating compliance with the Minimum Tonnage
Requirement or BTU Equivalent thereunder.
9. As amended and supplemented by this Second Amendment, The Original
Agreement shall remain in full force and effect.
IN WITNESS WHEREOF, the parties hereto have caused the Second Amendment
to Contract ICC-BN-C-2913 to be executed by their duly authorized
representatives on the date last written below.
OTTER TAIL NORTHWESTERN PUBLIC
POWER COMPANY SERVICE COMPANY
By: /s / Ward Uggerud By: /s/ Michael J. Hanson
--------------------------------- ------------------------------
Title: Chief Operating Officer Title: President & CEO
Energy Supply
----------------------------- ------------------------
Date: 6/4/99 Date: 6/1/99
----------------------------- ------------------------
MONTANA-DAKOTA THE BURLINGTON NORTHERN AND
UTILITIES COMPANY SANTA FE RAILWAY COMPANY
By: /s/ Bruce Imsdahl By /s/ David S. Quilici
--------------------------------- ----------------------------
Title: V. P. Energy Supply Title: VP Coal Marketing
----------------------------- ------------------------
Date: 6/2/99 Date: 6-10-99
----------------------------- ------------------------
(*) Confidential information has been omitted and filed separately with the
Commission pursuant to Rule 24b-2.
EXHIBIT 10-M
Confidential information has been omitted from this Exhibit and filed
separately with the Commission pursuant to a confidential treatment
request under Rule 24b-2.
THE BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY
TRANSPORTATION AGREEMENT BNSF-C-12221
This Agreement made pursuant to 49 U.S.C. Section 10709 between THE
BURLINGTON NORTHERN AND SANTA FE RAILWAY COMPANY, (hereinafter referred to
as "BNSF"), and OTTER TAIL POWER COMPANY (hereinafter referred to as "OTP").
WHEREAS, OTP owns and operates a stream electric generating plant
described herein, known as the Hoot Lake Steam Plant (as defined
hereinafter); and BNSF is a common carrier by rail with railroad track
extending from coal mines in Wyoming and Montana to the vicinity of Hoot Lake
Steam Plant; and
WHEREAS, OTP desires BNSF to transport, and BNSF desires to transport
for OTP, pursuant to the terms of this Agreement, certain tonnage of coal in
Unit Trains to Hoot Lake Steam Plant;
NOW, THEREFORE, in consideration of the premises and the agreements and
conditions which hereinafter follow, the parties hereto agree as follows:
SECTION 1. DEFINITIONS
Actual Placement: When a Unit Train arrives at the Origin Mine's or
Destination's designated notification point (as described in the BNSF
timetable) and the Train crew has requested loading instructions or
unloading car placement instructions.
Adjusted Rate: The Base Rate specified in Section 4 herein, plus all
increases and decreases made pursuant to Section 5 herein, applicable in
determining the Effective Rate.
Base Rate: The rate as set forth in Section 4 of this Agreement, expressed
in United States dollars, cents per net Ton applicable to the transportation
of Coal from Mine Origin(s) to Destination.
Bunching Time, Train Bunching or Bunching: When a Unit Train arrives at or
attempts to arrive at Origin or Destination and another Unit Train (or Unit
Trains) occupies the Origin or Destination which prevents the Actual
Placement for loading or unloading of the Unit Train for a period of one
hour or more, not due to any cause attributable to BNSF (the "Bunched Unit
Train"). Bunching shall be accounted for by BNSF's computer train records
and BNSF's Coal Desk logs. Bunching time may or may not include time in
which a train is under Constructive Placement.
Coal: That mineral substance, untreated except for additives used to reduce
freezing or dusting problems and currently designated as STCC Code 11212 by
the Association of American Railroads.
Coal Cars or Cars: Open-top, bottom dump, coal railroad cars having a net
capacity of approximately 100 Tons per car, supplied by OTP, or temporarily
substituted by BNSF, suitable for use in Unit Train service between Origin
and Destination. Said Coal Cars must comply with the Field Manual of
Interchange Rules and Office Manual of the Interchange Rules adopted by the
Association of American Railroads ("AAR Interchange Rules") presently in
effect and as they may be changed hereafter from time to time. Said Coal
Cars must comply with any rules and regulations of the Federal Railroad
Administration applicable to such Coal Cars.
*
Declared Annual Volume: The total annual tonnage volume, equal to or above
the Minimum Annual Volume, declared by OTP by October 1 of the preceding
calendar year that OTP intends to tender for transport under the terms
specified herein in a given calendar year.
CONFIDENTIAL CONTRACT BNSF-C-12221
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07/15/1999 at 1:56 PM
Destination: Hoot Lake Steam Plant (hereafter referred to as "Hoot Lake")
located near Fergus Falls, MN.
Effective Rate: The annually Adjusted Rate specified in Section 4 and
Section 5 herein, or the Base Rate, whichever is greater, and applicable to
the transportation of Coal on the date the loaded Train is released to BNSF
for transport to Destination pursuant to this Agreement.
Free Time: The time allowed for a Unit Train to load or unload free of train
detention charges. Free Time may be extended under conditions described in
this Agreement.
Loading Facility: All equipment necessary for loading of Trains at Origins
including; rail track, raw Coal hopper, crusher, storage/load-out silos, and
conveyor systems.
Minimum Annual Volume: * Tons of coal in each calendar year during the term
of this Agreement, subject to adjustment due to Force Majeure pursuant to
the terms of this Agreement).
Origin(s), Mine(s) or Mine Origin(s): The Coal Unit Train Loading Facilities
located at the mines identified in Subsection 3(A) of this Agreement.
Route of Movement: The BNSF rail route of loaded and empty Trains moving
pursuant to this Agreement from or to any Wyoming or Montana Mine Origins
specified in Subsection 3(A) through Huntley, MT, to or from Destination.
STB: The Surface Transportation Board or its successor agency or body having
the same or similar jurisdiction over rail common carriers operating in
interstate commerce.
Ton: A ton of 2,000 pounds avoirdupois.
Tender: An offer by OTP or its mine operator to BNSF of Coal loaded in a Unit
Train and ready for movement from one Origin to one Destination pursuant to
the terms of this Agreement.
Train or Unit Train or Train Set: A specialized train consisting of a
specified number of Coal Cars furnished as a unit for shipment from one
Origin to one Destination on one bill of lading at one time.
Unloading Facility: All equipment necessary for unloading of Trains at
Destination including: railroad track; dumper, including feeders and hopper;
and dumper conveyors.
SECTION 2. EFFECTIVE DATE AND TERM
2(A) Effective Date of Agreement.
This Agreement is made pursuant to 49 U.S.C. Section l0709 and shall
be effective on the date last signed below.
2(B) Date of Transportation under Agreement.
The terms and conditions of this Agreement shall apply to all
shipments of Coal made on or after July 15, 1999, in OTP furnished
cars as described under the terms of this Agreement.
2(C) Term of Agreement.
The term of this Agreement shall commence on the Effective Date in
Subsection 2(A) above and shall expire at midnight MST on *.
SECTION 3. MOVEMENTS COVERED BY THE AGREEMENT
3(A) Covered Mines, Origins or Mine Origins.
BNSF will transport Coal to Destination from any of the Montana or
Wyoming Mine Origins specified in Section 4(A) herein; provided that
these Origins have adequate Loading Facilities and
CONFIDENTIAL CONTRACT BNSF-C-12221
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procedures as contemplated under this Agreement capable of
consistently loading at least 113 Coal Cars in continuous motion
in four (4) hours or less.
3(B) Exception to Route of Movement.
BNSF may use any available alternate route when operating conditions
exist which make use of the route identified herein inadvisable or
impractical; provided, however, that when using alternate routes,
BNSF shall use its best efforts to select the least circuitous
routing and to otherwise minimize delays to OTP and shall not operate
any Train on a route which goes outside the States of Wyoming,
Montana, North Dakota, and South Dakota without OTP's prior consent;
provided, however, that such consent shall not be unreasonably
withheld.
3(C) Movement of Empty Trains and Change of Origin.
BNSF will move empty Trains from Destination to one of the Origins as
part of the service included under the rates provided in Section 4.
OTP's notice of any change in Origin from the last loaded movement
must be given to BNSF prior to departure of empty Trains from Hoot
Lake. Notice may be given by telephone, or other means of direct
communication with BNSF's Coal Operating Department. BNSF will use
best efforts to accommodate OTP should it become necessary to change
the Origin in the empty return Route of Movement.
SECTION 4. TRANSPORTATION RATES
4(A) Base Rate.
OTP shall pay to BNSF the following Base Rates (expressed in US
dollars and cents per net ton) as of July 15, 1999, for the
transportation of Coal from Origins to Destination under this
Agreement, which rates shall be subject to adjustment beginning
January 1, 2000 in accordance with Section 5:
BASE RATES
MONTANA MINE ORIGINS
*
NORTHERN MINE ORIGINS
*
CENTRAL MINE ORIGINS
*
SECTION 5. ADJUSTMENT OF RATES
5(A) Periodic Adjustments.
Except as otherwise provided in this Agreement, the transportation
rate set forth in this Agreement (that is, the Base Rate set forth
in Section 4) shall be adjusted annually, upward or downward, by
an amount equal to * of the change in the Rail Cost Adjustment Factor
unadjusted for Railroad Productivity (RCAF-U) ("Adjustment Index")
as defined in Ex Parte 290 Sub No. 4 (and further described in
Subsection 5B) to produce the "Adjusted Rate."
Adjustments shall become effective annually on January 1 of each
calendar year, with the first adjustment to become effective on
January 1, 2000. BNSF shall notify OTP in writing of all
adjustments and furnish supporting calculations, prior to the
effective date of the adjustment, or, as soon thereafter as the
information necessary to calculate the adjustment is made by the
STB. The new Adjusted Rate (and subsequent Effective Rate) so
determined shall be effective retroactive to the applicable
adjustment date in question.
CONFIDENTIAL CONTRACT BNSF-C-12221
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5(B) Adjustment Percentage Change Application.
Commencing on January 1, 2000, the Annual Percentage Change shall be
equal to the *. The Annual Percentage Change (in decimal) will be
multiplied by * to produce the Adjustment Percentage Change (in
decimal). The previous annual Adjusted Rate is multiplied by the
Adjustment Percentage Change to produce the "Change Amount." The
previous Adjusted Rate plus the Change Amount will equal the new
quarter's Adjusted Rate. The Effective Rate shall be equal to the
Adjusted Rate if the Adjusted Rate is equal to or greater than the
Base Rate else the Effective Rate shall be equal to the Base Rate.
For example:
*
In no event shall the Effective Rate move below the Base Rate under
this Agreement; if the Adjustment Index produces Adjusted Rates that
are lower than the Base Rate, then the Effective Rate shall be equal
to the Base Rate. In subsequent years, the Adjusted Rates that are
below the Base Rate shall continue to be adjusted upward or
downward, as applicable, and shall not be used to determine the
Effective Rate until the level of the Adjustment Index produces
Adjusted Rates that are above the Base Rate.
5(C) Rounding.
All calculated numbers shall be rounded to the nearest sixth digit
after the decimal point (i.e. .000001499 = .000001). All final
adjustment computations shall be rounded to the nearest one cent
by going to the lower cent when computations result in a balance of
less than one-hag cent and to the next higher whole one cent when
computations result in a balance of one-half cent or more (i.e.
.044999 = $0.04 and .045000 = $0.05).
5(D) Elimination or Material Alteration of Index.
If the STB or any successor organizations cease to publish the RCAF-U
index required for the calculations outlined in this Section, or
materially alters the methodology by which the index is derived, the
parties shall mutually determine and agree upon the most appropriate
substitute index which most closely matches the economic structure of
the discontinued or altered index to be used for adjustments for the
remainder of the Agreement term immediately following such action.
If the parties do not come to an agreement as to the substitute index
by an adjustment date, the Effective Rate shall not be adjusted until
such time as the index is agreed to, at which time a retroactive
adjustment shall be made retroactive to said adjustment date. If the
parties do not reach agreement on the substitute index after 60 days
following an adjustment date, eighty percent (80%) of the United
States Gross Domestic Product - Implicit Price Deflator shall be the
substitute index. The parties agree that the RCAF index adjusted for
productivity (RCAF-A) (or other future RCAF indexes adjusted for
productivity in some manner) will not be used under this Subsection
5(D) as a substitute index.
SECTION 6. ENTIRE COMPENSATION
The rates and charges specified in this Agreement shall constitute the
entire compensation payable to BNSF for the rail transportation services
specified in this Agreement. BNSF shall not seek to collect from OTP,
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except as provided herein, any additional amounts in connection with such
specified services. The adjustment mechanism specified in Section 5 of this
Agreement shall constitute the sole means of adjusting the rates specified
in this Agreement during the term hereof. If OTP requests BNSF to perform
additional services, not specified in this Agreement or incorporated herein
by reference, charges for such services shall be established by separate
agreement.
SECTION 7. DESCRIPTION OF TRANSPORTATION
AND TONNAGE REQUIREMENTS
7(A) Transportation Services and Obligations of the Parties.
BNSF agrees to transport Coal subject to the terms of this Agreement.
The transportation services to be provided by BNSF pursuant to this
Agreement shall include all rail services and operations required for
movements in Trains of loaded Coal Cars from Origin to Destination
and the return movement in Trains of the empty Coal Cars to Origin,
both via Route of Movement. These services are described as follows:
(1) Transportation services including such switching and Car handling
at Origin and Destination as may be required for loading and
weighing at Origin and Unloading at Destination and, if requested
by OTP, reversing the Train within the Free Time period at
Destination.
(2) Transportation services required for rail movements in Trains
between Origin and Destination, including all marshaling of Cars,
line-haul transportation, switching for Coal Car maintenance
performed by BNSF, inspection of Coal Cars, storage of active
spare Cars on the Route of Movement and other customary
accessorial services required for efficient Train operations.
BNSF shall provide the necessary locomotives, cabooses (if
required), rear-end devices, materials, supplies and labor to
enable it to transport the Coal tonnage to be Tendered to it
pursuant to this Agreement.
7(B) Coal Cars.
OTP hereby agrees to supply at least one hundred and thirteen (113)
Coal Cars plus at least five spare Coal Cars suitable for interchange
under Interchange Rules adopted by the Association of American
Railroads for each Unit Train Tendered, for use by BNSF in accordance
with the terms of this Agreement in order to allow BNSF to transport
the Coal tonnage to be Tendered hereunder. Said Coal Cars shall be
provided at no cost to BNSF.
7(C) Minimum Annual Volume.
(1) Within each calendar year during the term of this Agreement
after year 1999, OTP agrees to Tender, in reasonably equal
monthly quantities, the Minimum Annual Volume of * Tons
of Coal, as adjusted pursuant to this Agreement, under the
conditions and in the manner specified herein, provided however,
in calendar year 1999, the Minimum Annual Volume will be equal
to * tons. OTP may Tender tonnage in excess of the Minimum
Annual Volume.
(2) Commencing in calendar year 2000, OTP shall provide to BNSF by
October 1 of each preceding year during the term of this
Agreement a written notice specifying the amount of Coal it
intends to Tender under this Agreement during the calendar year
("Declared Annual Volume"). The Declared Annual Volume shall
equal the Minimum Annual Volume plus any additional coal above
the Minimal Annual Volume. The Declared Annual Volume shall
indicate the amount of Coal OTP intends to ship during each
quarter of the year. The Declared Annual Volume shall be for
informational purposes only and is not binding.
(3) If in any calendar year during the term of this Agreement, OTP
does not Tender to BNSF the Minimum Annual Volume, OTP agrees to
pay BNSF as liquidated damages, agreed as reasonable and not as
a penalty, an amount equal to * of the applicable Effective Rate
as of the end of such calendar year times the difference between
the Minimum Annual Volume and the total tonnage Tendered by OTP
to BNSF during such calendar year.
CONFIDENTIAL CONTRACT BNSF-C-12221
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The Minimum Annual Volume shall be adjusted by Force Majeure
events as provided for in Section 14(C). OTP shall not reduce
the Minimum Annual Volume by shipping any or all of the
Minimum Annual Volume via another rail carrier and by paying
liquidated damages to BNSF to satisfy the Minimum Annual Volume
as adjusted pursuant to this Agreement, and in the event that
OTP does so, said percentage of the applicable Effective Rate
shall not be construed as an agreed upon measure of damages.
(4) Any Tons which are not actually moved, but for which charges are
paid pursuant to Subsection 11(J), will be considered as Tons
received in meeting the Minimum Annual Volume.
7(D) BNSF Service Commitment.
For the Minimum Annual Volume in Subsection 7(C) and Tendered for
shipment from the Mine Origins, BNSF agrees to provide a minimum of
* round trips per year (* trips in calendar year 1999), if OTP
unloads in * hours and Origin Mines load the train in * hours.
BNSF shall be granted relief from the * trips per year for the
following reasons:
(1). Train Bunching time and/or Constructive Placement time at the
Mine Origin.
(2). Train Bunching time and/or Constructive Placement time at
Destination if there is a train not ready for release at the
Destination preventing placement of the loaded train.
(3). Any two week period where the Long Unload Cycle is used by OTP.
(4). Delays caused by Force Majeure as defined in Section 14.
(5). Any delay caused by OTP, OTP's loading or unloading operator.
If the Deficit Tonnage is due to BNSF's failure to make the * round
trips yearly, and as a result thereof, OTP does not ship the Minimum
Annual Volume, BNSF shall take all reasonable steps, including the
addition of locomotives, rail owned Coal Cars and crews to transport
the Deficit Tonnage at a schedule consistent with the ability of the
Origin Mine operator to load and OTP to unload (including the ability
to store or consume) the Deficit Tonnage. The freight charges for
transporting such Deficit Tonnage shall be the Effective Rate
applicable in the calendar quarter that the Deficit Tonnage accrued.
*
BNSF will use best efforts to ship tonnage above Declared Annual
Volume but no liquidated damages will be due on Deficit Tonnage
above the Declared Annual Volume.
SECTION 8. FURNISHING OF SHIPMENTS;
CONFLICTING TERMS IN BILLS OF LADING.
OTP shall arrange for shipments of Coal to be furnished to BNSF on
a standard bill of lading in accordance with the Uniform Straight
Bill of Lading or other shipping documents approved by BNSF,
subject to the conditions of this Agreement. Each bill of lading
or shipping document shall contain a reference to the contract
number assigned to this Agreement, i.e., BNSF-C-12221. The rates
identified in this Agreement shall not appear on the bill of lading.
In the event there is a conflict between the terms of this Agreement,
the terms of a bill of lading or other shipping documents, the terms
of this Agreement shall govern and control.
CONFIDENTIAL CONTRACT BNSF-C-12221
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SECTION 9. WEIGHING
9(A) Weighing.
The parties agree that the weight of the Coal in the Coal Cars will
be determined at Origin by OTP's Origin Mine operator. BNSF shall
not be responsible for such weight determinations. The weights
ascertained by said operators shall be used for the assessment of
the freight charges hereunder pursuant to Subsection 11(J). Weighing
shall be performed on scales inspected semi-annually in accordance
with the then-current AAR Scale Handbook specifications for such
scales, and subject to supervision and verification by BNSF or BNSF's
agent.
9(B) Breakdown Of Scales.
If weights cannot be determined due to a breakdown of the scales at
Origin, the weight per Train to be used for the assessment of freight
charges hereunder shall be determined by averaging the per Car
weights on the ten (10) immediately preceding weighed shipments
(containing similar capacity Coal Cars) from the same Origin to
Destination, adjusted for any variance in the number of Cars per
shipment.
If scales are determined by a scale test to be in error in excess of
the AAR Scale Handbook tolerance of one percent (1.0%), said scales
shall be recalibrated to be within one percent. The weights used by
BNSF for purpose of assessing freight charges for Coal transported
pursuant to this Agreement during the period since the last preceding
inspection and calibration of such scales shall be used without any
resulting payments or refunds.
9(C) Gross Load Limit and Overloads.
If a loaded Coal Car is found by BNSF to weigh in excess of the
maximum gross load limit for Cars or weighs in excess of the maximum
gross weight on rail of 286,000 pounds, BNSF shall, if necessary,
switch said overloaded Coal Car and remove it from the Train.
BNSF retains the right to refuse to accept or transport overloaded
Cars. BNSF shall not be obligated to reduce the lading of such Cars,
which obligation is solely OTP's under this Agreement. After OTP,
at no expense to BNSF, causes any excess Coal to be removed from the
overloaded Coal Car, BNSF shall replace the Coal Car into the Train.
For such services in removing and replacing each such Coal Car, OTP
shall pay a switch charge to BNSF of *. If the excess Coal is
removed during the Free Time at Origin without removing the Coal Car
from a Train, there shall be no charge to OTP. BNSF reserves the
right to increase the maximum gross weight on rail above 286,000
pounds and will notify OTP in writing of any increases in the maximum
gross weight standard.
SECTION 10. LOADING AND UNLOADING
10(A) Loading.
*
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BNSF receives notice from OTP or its Origin Mine operator that the
Train is released for movement back to Destination. However, if two
or more Unit Trains are halted or delayed due to any cause
attributable to BNSF, OTP shall be allowed additional Free Time at
Origin until such time as the Bunched Unit Train is actually placed
for loading, whereupon the Free Time at Origin will commence.
10(B) Advance Notice of Unloading.
BNSF shall notify OTP's dumper building personnel at Destination of
the estimated time of arrival of each Train at least four (4) hours
prior to such estimated time of arrival at Destination. Normally,
BNSF will telephone OTP; however, in the future and when installed,
BNSF may make notification by electronic mail and/or BNSF installed
software with the approval of OTP.
10(C) Unloading.
*
10(D) Extended Unloading.
OTP shall have unlimited Free Time to unload each Unit Train upon
OTP's election to pay a release of power fee of * per train
("Extended Unloading"). The first three elections of Extended
Unloading in each calendar year shall be free and without charge to
OTP. OTP shall notify BNSF by fax or other electronic means of its
election of Extended Unloading at the time of its election. OTP
shall be responsible for the accounting of Extended Unloading charges
and OTP shall pay to BNSF said charges within 30 days (and without
BNSF billing) after the end of each calendar quarter.
10(E) Frozen Coal.
If it is determined by OTP that Coal is frozen in the Coal Cars, OTP
shall notify BNSF as soon as practical and OTP shall be granted as
much Free Time as necessary to unload the Unit Train.
10(F) Residual Coal.
As used in this Agreement, Residual Coal means Coal which remains in
a Coal Car after the completion of the unloading process at
Destination, including Coal which remains in a Coal Car after
OTP has attempted to loosen or thaw frozen Coal. OTP will be
responsible for the complete unloading of Coal Cars prior to
departure of an empty Train from Destination. If BNSF discovers
Residual Coal in any Coal Car in the Train after such Train has
departed Destination, and such Residual Coal results in an unsafe
condition (e.g., Residual Coal accumulated on one side or end of
Car causing the Coal Car to become unstable), BNSF may remove such
Coal Car from the Train at a charge to OTP of * per hour or fraction
thereof for the removal service, such charge to include the return
of such Coal Car to the Train after OTP has advised BNSF that such
Coal Car has been made safe for movement.
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SECTION 11. SUPPLY OF EQUIPMENT AND SERVICE; MAINTENANCE;
CAR DAMAGE AND DESTRUCTION; MINIMUM TRAIN SIZE
11(A) Applicable Rules.
The parties agree that each party hereto will assume separate
responsibilities for the Coal Cars as those responsibilities are
designated in the Field Manual of Interchange Rules and Office Manual
of the Interchange Rules adopted by the Association of American
Railroads ("AAR Interchange Rules") presently in effect and as they
may be changed hereafter from time to time. The parties further
agree to comply with any rules and regulations of the Federal
Railroad Administration applicable to such Coal Cars.
Notwithstanding any provision to the contrary, BNSF shall not be
liable for any loss of or damage to Coal or OTP's Coal Cars due to
defects in said Coal Cars or due to improper loading thereof, or to
defects in manufacture, design or workmanship.
11(B) Damage to Coal Cars.
If OTP furnished Coal Cars are damaged under circumstances in which
the AAR Interchange Rules make BNSF responsible for such damage, BNSF
will give OTP written notification of the damage and will provide the
Car initial and numbers. BNSF will repair or cause to be repaired
such damaged Coal Cars at its expense and shall transport such Coal
Cars for repairs and return them to Train service pursuant to the AAR
Interchange Rules. BNSF shall do so and will use its best efforts to
make such repairs in a timely fashion. While said Coal Cars are
being repaired, BNSF shall furnish suitable substitute Coal Cars for
use hereunder at no cost to OTP until said Coal Cars are repaired
and returned to service, PROVIDED, HOWEVER, that if, at OTP's
request, said Coal Cars are repaired at a shop of OTP's choosing,
BNSF shall furnish suitable substitute Coal Cars until damaged Coal
Cars are repaired and returned to service or until 365 days from the
date of damage, whichever event occurs first.
11(C) Destruction of Coal Cars.
In the event that Coal Cars are destroyed under circumstances in
which the AAR Interchange Rules make BNSF responsible for such
destruction, BNSF will give OTP written notification of such
destruction and provide the Coal Car initials and numbers of each
affected Coal Car. BNSF shall furnish suitable substitute Coal Cars,
for use hereunder at no cost to OTP for a period not to exceed
365 days following the date BNSF furnishes suitable substitute Coal
Cars or until the date replacement Coal Cars are in service.
Settlement to OTP for any such destroyed Coal Car shall be in
accordance with the applicable rule(s) of the Field Manual of the
AAR Interchange Rules in effect on the date of such destruction.
Such amounts so determined and undisputed will be paid to OTP within
thirty (30) days of BNSF's receipt of OTP's invoice therefor.
11(D) Substitute Coal Cars.
For the purpose of Subsections 11(B) and 11(C) "suitable substitute
Coal Cars" shall mean open top, bottom dump, Coal Cars of
approximately 100 Ton lading capacity which are compatible with
Hoot Lake's unload facility.
11(E) Removal and Replacement of Cars for Storage or Maintenance.
Upon request of OTP, BNSF will, on the return movement from
Destination to Origin, stop a Train at a OTP designated maintenance
facility at an intermediate point on the Route of Movement where
track is available to remove or replace Cars from such Train. OTP
shall pay BNSF a switching charge for removal and replacement of Coal
Cars in such Train of * per hour, or fraction thereof, to be
computed from the time the Train stops for removal or replacement of
individual Coal Cars until such time as the last Coal Car is removed
from the Train or until the last Coal Car is placed into the Train.
11(F) Removal and Replacement of Trains for Storage or Maintenance.
Upon request of OTP, BNSF will, on the return movement from
Destination to Origin, place an entire empty Train at a OTP
designated maintenance facility at an intermediate point on the Route
of Movement. Upon subsequent request of OTP, BNSF will remove the
entire Train from such maintenance facility and return it to service.
OTP will pay * in total to BNSF for its services in placing such
Train at such maintenance facility and removing such Train from
such maintenance
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facility and returning it to service. In addition, OTP shall pay BNSF
at the rate of * per hour required for such placement or removal,
with such charges to commence when the Train crew starts such
placement and ends when the Train is set for departure.
11(G) Switching to Connecting Rail Carrier.
If a Car maintenance facility selected by OTP is served by another
rail carrier which necessitates, at an intermediate point on the
Route of Movement, a switch movement of Coal Cars, or a switch
movement of a Train, to or from a connecting railroad, BNSF will
provide the necessary switching services. BNSF will be paid by OTP
in accordance with Subsection 11(E) for a switch movement of
Coal Cars, and in accordance with Subsection 12(B) for a switch
movement of Trains. Any switching or any other charges imposed by
the connecting railroad shall be paid by OTP.
11(H) Maintenance Facility Off Route of Movement
If a Car maintenance facility selected by OTP is located at a point
which is not on the Route of Movement, BNSF will be paid the
following line-haul charge, covering any movement on the BNSF system
not on the Route of Movement, in addition to the charges specified in
Subsections 11(E), 11(F) or 11(G), as appropriate:
Rates in Dollars Per
Car, Per Mile,
Minimum 75 Miles Number of Coal Cars
---------------------------------------------------
* 25 or Less
* 26 to 75
* More Than 75
The charges set out in Subsections 11(E), 11(F), 11(G) and 11(H)
shall not apply to the movement of Coal Cars damaged by BNSF to a
maintenance facility for repair.
11(I) Bad Order Switching.
No charges will be assessed by BNSF for switching occasioned by bad
ordering of Coal Cars by BNSF personnel, including both switching out
of bad ordered Coal Cars and/or switching in of spare Coal Cars in
substitution for bad ordered Coal Cars.
11(J) Minimum Train Size.
(1) Minimum Tender: Each Train furnished at Origin for loading shall
contain no less than 113 Cars ("Minimum Train Size"), except as
provided in this Section 11. The weight for determination of
freight charges shall be the greater of (1) the actual weight of
the lading of the Train as determined pursuant to Section 9; or
(2) 97 tons per Car times 113 Coal Cars in the Train (except as
provided in Section 11(J) herein).
(2) Damaged or Destroyed Cars Exception: If OTP is prevented from
furnishing at least 113 Coal Cars because its Coal Cars have
been damaged or destroyed by BNSF and BNSF is liable therefor,
and if BNSF is unable to furnish sufficient suitable substitute
Coal Cars pursuant to Subsections 11(B), 11(C) and 11(D),
Minimum Train Size shall be reduced to the number of
suitable Coal Cars OTP and BNSF together are able to provide;
however, the Minimum Train Size under this Subsection (J)(2)
shall be 75 Coal Cars.
(3) En Route Exception: In the event OTP is unable to furnish at
least 113 Coal Cars because certain Coal Cars are found en route
or at Origin to be unsuitable for loading, excluding open
doors which can be secured, the Minimum Train Size shall be
reduced by the number of Coal Cars found to be unsuitable for
loading; however, the Minimum Train Size under this Subsection
11(J)(3) shall be 100 Coal Cars.
(4) Insufficient BNSF Substitute Cars: If OTP's Coal Cars are
damaged or destroyed by BNSF and BNSF is unable to furnish
sufficient suitable substitute Coal Cars as provided for in
Subsections 11(B), 11(C), and 11(D) the Minimum Annual Volume
shall be reduced by 97 Tons
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for each Coal Car less than 113 in any Train shipment resulting
from BNSF's inability to furnish suitable substitute Coal Cars.
(5) Insufficient OTP Substitute Cars: If, due only to the unexcused
fault of OTP, sufficient Coal Cars are not available for loading
to meet the Minimum Train Size, BNSF will accept loaded Coal
Cars furnished for transportation and the Effective Rate shall
be assessed on actual Tons loaded plus 97 Tons per Coal Car for
each Car short of the Minimum Train Size. Such Tons which are
not actually moved but for which charges are paid pursuant to
this Subsection 11(J)(5) will be considered as Tons received in
meeting the Minimum Annual Volume and the Declared Quarterly
Volume. OTP will use reasonable efforts to maximize the tonnage
per Car and, BNSF and OTP will use reasonable efforts to
maximize the number of Cars in each train.
SECTION 12. HOLDING OF EMPTY TRAINS
12(A) Storage On the Route of Movement.
If storage track is available at a location on the Route of Movement
(for Train storage at Destination, see Section 10(D)), upon request
of OTP, BNSF will, on the return movement from Destination to
Origin, move an empty Train to such storage track and place the Train
there for storage. BNSF will be paid * in total (billable at
the time the Train is placed) for its services in placing and
removing such Train. In addition, OTP shall pay a storage charge of
* for each 24 hour period or fraction thereof that the Train is
stored on any such storage track owned by BNSF.
12(B) Switching to Connecting Carrier.
OTP shall pay * per Train for each switch to or from a connecting
carrier. In addition, OTP shall pay BNSF at the rate of
* per hour required for any such switching, with such charges
to commence when the Train crew starts such switching and shall end
when the last car is released to the connecting railroad by BNSF.
Any switching or other charges imposed by the connecting railroad
shall be paid by OTP. However, none of the charges in this
Subsection 12(B) shall apply if such switch is for the purpose of
continuing the movement of Unit Trains on the Route of Movement.
12(C) Storage Off Route of Movement.
If OTP's owned or leased storage track is located at a point which
is not on the Route of Movement, BNSF will move OTP's Trains to and
from such storage track and OTP shall pay the line haul charges
specified in Subsection 11(H) for any such movement on the BNSF
system in addition to the charges specified in Subsection 12(B) as
appropriate. If OTP elects to move consist sizes of * cars
or more from the state of Illinois to Wyoming Mines origins, or from
Wyoming Mines to the state of Illinois, a total charge of * per
car will be applicable and the charges specified in Subsection 11(H)
and Subsection 12(B) shall not apply.
SECTION 13. BILLING AND PAYMENT
All undisputed payments for transportation of Coal due hereunder shall be due
and payable on or within five (5) working days of the receipt of a written
or electronic statement of charge or charges, with the exception of
ancillary charges specified in Subsection 7(C) and 7(D) which shall be due
within 30 calendar days of receipt. OTP shall make all payments to BNSF
for transportation of Coal under this Agreement by wire transfer or by
electronic funds transfer. Other charges due to BNSF by OTP or OTP by
BNSF may be paid by mail.
OTP will audit freight bills and contact, if necessary, a BNSF Accounting
Department representative assigned to OTP's account, to make corrections or
adjustments to bills prior to the wire transfer. If corrections or
adjustments to freight bills cannot be agreed upon within said 5 day period,
OTP shall wire transfer the undisputed amounts billed, and the balance, if
any, will be transferred within 5 calendar days of the date the parties
agree as to the appropriate corrections or adjustments. When resolved, by
agreement, the balance owing, if any, shall be accompanied by interest at
10% per annum on the unpaid balance from the date the original bill was
partially unpaid to the date of the wire transfer of the agreed balance.
CONFIDENTIAL CONTRACT BNSF-C-12221
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If a party fails to make undisputed payments for Coal transportation on or
within 5 working days of receipt of written statements of charge or charges,
or fails to make undisputed payment for ancillary charges within 30 calendar
days of receipt, it agrees to pay a late charge to compensate the other
party for its administrative costs at a rate of two percent (2%) of any
amount due and unpaid, for each 30 day period or portion thereof, or at the
maximum rate permitted by law, if lower, commencing from the expiration of
said 10 working days or 30 calendar days, respectively, of receipt of
written statement of such freight charges or ancillary charges.
SECTION 14. FORCE MAJEURE
14(A) Defined.
The term "Force Majeure" as used herein shall mean any cause or
causes beyond the reasonable control of the party affected thereby
which, by exercise of due diligence, it shall be unable to overcome,
including, without limitation:
Acts of God; acts of the public enemy; blockades; strikes; lockouts;
labor disputes or other industrial disturbances; riots; disorders;
storms; landslides; floods; washouts; earthquake; lightning;
unusually large snow accumulation; civil disturbances; restraint,
acts or decisions by court or governmental or other public authority
directly affecting either party; boycotts; embargoes, including
embargoes pursuant to AAR service orders; war or acts of military
authorities; unavailability of diesel fuel for locomotives or
generator start-up; derailments; failure of mine operators to supply
coal (whether excused by reason of a Force Majeure condition under
OTP's coal purchase contract with such mine operator; or unexcused
and in violation of such contract); frozen coal; or fire or
explosion or mechanical breakdown or damage affecting BNSF's
facilities or equipment, availability of Coal Cars from
manufacturers, OTP's Hoot Lake Steam Plant or equipment or
facilities related thereto including the Unloading Facilities, or
affecting the mine(s) of OTP's coal supplier(s), or equipment or
facilities related thereto, including Loading Facilities (extending
for periods beyond one hour, including emergency outages of equipment
or facilities for the purpose of making repairs to avoid breakdown
thereof or damage thereto other than regularly scheduled repairs or
regular maintenance).
14(B) Effect Hereunder.
If because of Force Majeure, either party hereto is unable to carry
out its obligations under this Agreement, and if such party shall
promptly give to the other party written notice of such Force
Majeure, then the obligation of the party giving such notice shall
be suspended to the extent made necessary by such Force Majeure and
during its continuance. However, the party giving such notice
shall use its best efforts to eliminate such Force Majeure insofar
as possible with a minimum of delay, and thereupon promptly give
notice to the other party when the Force Majeure has terminated.
Nothing herein contained shall cause the party affected by an event
of Force Majeure to submit to what it believes to be an unfavorable
labor agreement, and it is agreed that any settlement of labor
strikes or differences with workmen shall be entirely within the
sole discretion of the affected party.
14(C) Effect on Minimum Annual Volume.
In the event shipments of Coal cannot be made due to Force Majeure,
as defined in this Section affecting either party, the Minimum
Annual Volume shall be reduced by 1/365th for each day during
which the event of Force Majeure continues. The above reductions
shall take into account the effects of partial and full disability
events. Any day in which two or more such events occur shall be
considered as one day. An event of Force Majeure shall last for a
continuous 24 hour period before the Minimum Annual Volume shall be
reduced. Force Majeure days shall not be carried over into
succeeding years for purposes of calculating compliance with the
Minimum Annual Volume.
SECTION 15. LIMITATIONS ON ACTIONS FOR COAL LOSS OR DAMAGE
15(A) Liability.
Standard common carrier liability pursuant to 49 U.S.C. Section 11706
shall apply to loss of or damage to the Coal being transported
pursuant to this Agreement. In the event of a conflict between said
terms and this Agreement, this Agreement shall govern.
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15(B) Claims.
Claims for loss of or damage to Coal en route must be made in writing
by OTP to BNSF within 9 months after receipt of BNSF's written
statement of charges for transporting such Coal. Suits must be filed
against BNSF within two years and one day from the day when notice in
writing from BNSF is received by OTP stating that BNSF has disallowed
OTP's claim or any part or parts thereof as specified in BNSF's
notice. If claims are not made and/or suits are not instituted
thereon in accordance with the foregoing provisions, BNSF shall not
be liable and such claims will not be paid. This Subsection 15(B)
shall not apply in the event of a material breach of this Agreement
by BNSF. This Subsection 15(B) shall only apply to loss of or damage
to Coal which occurs while such Coal is being transported by BNSF
between Origin and Destination.
SECTION 16. TERMINATION
If either party hereto shall default in any material obligation of this
Agreement which is not excused as Force Majeure as defined in Section 14,
and continues in such default for a period of sixty (60) days after written
notice thereof is given by the non-defaulting party to such other party of
the existence of such default, or, if more than sixty (60) days are required
to correct with reasonable diligence the default set forth in said notice
and such defaulting party shall fail within said sixty (60) day period to
commence the action necessary to correct such matters and thereafter
prosecute the same to completion with reasonable diligence, the non-
defaulting party may, at its option, and without prejudice to its other
rights and remedies hereunder, at law or in equity, terminate this Agreement
by written notice thereof to the party in default.
SECTION 17. ASSIGNMENT AND BINDING EFFECT
This Agreement shall bind and inure to the benefit of the parties and their
successors and assigns. Either party hereto may assign any receivable due
them under this Agreement, provided however, such assignment shall not
relieve the assignor of any of its rights or obligations under this
Agreement. With the exception of assignment of: (a) said receivables; or
(b) either party's right to assign to a successor where such assignment or
delegation occurs by way of sale or transfer of all or substantially all of
a party's assets by way of merger, consolidation, or combination; neither
party may assign this Agreement or any other rights or obligations hereunder
without the prior written consent of the other party; provided however, that
such written consent shall not be unreasonably withheld and that no
assignment shall be effective unless and until the assignee shall assume in
writing the obligation of the assignor.
SECTION. 18. ENTIRETY AND AMENDMENTS
This Agreement comprises the entire Agreement, and merges and supersedes all
prior oral and written understandings and representations between OTP and
BNSF concerning the subject matter hereof. All amendments of the terms of
this Agreement shall be in writing, signed by the parties hereto and shall
comply with any applicable laws and regulations.
SECTION 19. WAIVERS AND REMEDIES
The failure of either party hereto to insist in any one or more instances
upon strict performance of any of the obligations of the other party
pursuant to this Agreement or to take advantage of any of its rights
hereunder shall not be construed as a waiver of the performance of any such
obligation or the relinquishment of any such rights for the future, but the
same shall continue and remain in full force and effect.
Upon a material breach of this Agreement, all remedies provided by law or in
equity, including specific performance of this Agreement, shall be available
to the affected party.
SECTION 20. NOTICE
Any notice required or permitted hereunder, including an event of Force
Majeure, except for invoices and payments and as otherwise provided in this
Agreement, shall be made in writing and shall be deemed effective when
delivered personally to the party to whom directed, or upon the earlier of
actual receipt, or
CONFIDENTIAL CONTRACT BNSF-C-12221
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three days after deposit in the United States Mail, Registered or Certified
Mail, return receipt requested with postage prepaid and property addressed
to the following:
The Burlington Northern
and Santa Fe Railway Company Otter Tail Power Company
---------------------------- ------------------------
2650 Lou Menk Drive 215 South Cascade
Fort Worth, TX 76161-0051 Fergus Falls, MN 56537
Attn: Coal Business Unit Attn: Hoot Lake Plant
These addresses may be changed by written notice to the other party.
SECTION 21. LIABILITY AND INDEMNIFICATION
21(A) BNSF Indemnity.
To the extent permitted by applicable law, BNSF shall protect,
indemnify and save harmless OTP, its officers, directors, employees,
agents and servants from and against all liabilities losses, claims,
demands, damages, penalties, causes of action, judgments, suits,
(including suits for personal injuries or death) including all
reasonable attorneys' fees, court costs and expenses incurred in
defense of any claim or suit, proximately caused by the negligent or
intentional conduct of BNSF or its employees, representatives or
agents and arising out of or in connection with its obligations
under this Agreement, and shall pay for any losses, claims, demands,
damages, penalties, judgments, suit of any nature rendered against
OTP or such person.
21(B) OTP Indemnity.
To the extent permitted by applicable law, OTP shall protect,
indemnify and save harmless BNSF, its officers, directors,
employees, agents and servants from and against all liabilities
losses, claims, demands, damages, penalties, causes of action,
judgments, suits, (including suits for personal injuries or death)
including all reasonable attorneys' fees, court costs and expenses
incurred in defense of any claim or suit, proximately caused by the
negligent or intentional conduct of OTP or its employees,
representatives or agents and arising out of or in connection with
its obligations under this Agreement, and shall pay for any losses,
claims, demands, damages, penalties, judgments, suit of any nature
rendered against BNSF or such person.
21(C) Joint Indemnity.
If any liability, loss, claim, damage, demand, penalty, cause of
action, judgment or suit arises from the joint negligence or
intentional conduct of BNSF and/or OTP and/or a third party, each
party's responsibility for its portion of the liability, loss,
claim, damage, penalty, cause of action, or suit shall be as
determined in accordance will applicable law.
SECTION 22. GOVERNING LAWS
For all purposes, this Agreement shall be deemed to be an Agreement made in
the state of Minnesota and governed by and construed according to the laws
of that state except that matters related to loss and damage to coal shall
be construed and interpreted consistent with relevant agency and court
decisions and U.S. statutes and regulations thereunder establishing or
determining rights and obligations of carriers providing interstate common
carriage by rail.
SECTION 23. CONFIDENTIALITY
Except when required by law, the parties shall not reveal the terms of this
Agreement to persons not employed by a party to this Agreement or its
affiliate and shall protect the confidentiality of the information developed
in connection with this Agreement; provided, however, that neither party
will be precluded from revealing such information in obtaining or attempting
to obtain financing or in filing reports and information
CONFIDENTIAL CONTRACT BNSF-C-12221
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with the Securities and Exchange Commission, or the appropriate governmental
or regulatory authorities, or making public information required thereby, or
when advised by legal counsel that such disclosure is required. When
required, the parties may also submit information to consultants and
contractors performing work related to this Agreement who agree in writing
to protect the confidentiality of such information.
SECTION 24. REPRESENTATIONS AND WARRANTIES
24(A) OTP represents and warrants to BNSF:
(1) It is a corporation duly organized, validly existing and in
good standing under the laws of the State of Minnesota.
(2) The execution and delivery by OTP of this Agreement and the
performance by OTP of its obligations are within its power and
authority and have been duly authorized.
(3) This Agreement is a legal, valid and binding obligation of OTP
enforceable against OTP in accordance with its terms.
24(B) BNSF represents and warrants to OTP:
(1) It is a corporation duly organized, validly existing and in
good standing under the laws of the State of Delaware.
(2) The execution and delivery of this Agreement by BNSF and the
performance by BNSF of its obligations thereunder are within
its corporate powers, have been duly authorized by all
necessary corporate action, and do not and will not
contravene or conflict with any provision of law or of its
charter or by-laws.
(3) This Agreement is legal, valid and binding obligation of
BNSF enforceable against BNSF in accordance with its terms.
SECTION 25. HEADINGS NOT TO AFFECT CONSTRUCTION
The headings to the Sections, Subsection and paragraphs of this Agreement
are inserted for the convenience of reference only, and are neither to be
taken to be any part of the provisions hereof nor to control or affect the
meaning, construction or effect of the same.
IN WITNESS WHEREOF, the parties have executed this Agreement effective as of
the date last written below.
THE BURLINGTON NORTHERN
OTTER TAIL POWER COMPANY AND SANTA FE RAILWAY COMPANY
BY:/s/Ward Uggerud BY: /s/David S. Quilici
- --------------------------------- -----------------------------
Chief Operating Officer,
TITLE: Energy Supply TITLE: VP Coal Marketing
- ---------------------------------- -----------------------------
DATE: July 16, 1999 DATE: 7-19-99
- ---------------------------------- -----------------------------
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(*) Confidential information has been omitted and filed separately with the
Commission pursuant to Rule 24b-2.
EXHIBIT 10-N-3
SEVERANCE AGREEMENT
This Agreement is made as of the ________ day of ____________________,
between Otter Tail Power Company, a Minnesota corporation, with its
principal offices at 215 South Cascade Street, P.O. Box 496, Fergus Falls,
Minnesota 56538-0496 (the "Company") and _____________________ ("Employee"),
residing at __________________________________.
W I T N E S S E T H T H A T:
WHEREAS, this Agreement is intended to specify the financial
arrangements that the Company will provide to Employee upon Employee's
separation from employment with the Company under any of the circumstances
described herein; and
WHEREAS, this Agreement is entered into by the Company in the belief
that it is in the best interests of the Company and its shareholders to
provide stable conditions of employment for Employee notwithstanding the
possibility, threat or occurrence of certain types of change in control,
thereby enhancing the Company's ability to attract and retain highly
qualified people.
NOW, THEREFORE, to assure the Company that it will have the continued
dedication of Employee notwithstanding the possibility, threat or occurrence
of a bid to take over control of the Company, and to induce Employee to
remain in the employ of the Company, and for other good and valuable
consideration, the Company and Employee agree as follows:
1. Term of Agreement. The term of this Agreement shall commence on
the date hereof as first written above and shall continue through April 1,
2001; provided that commencing on March 31, 2001 and each March 31
thereafter, the term of this Agreement shall automatically be extended for
one additional year unless not later than December 31 of the preceding year,
the Company shall have given notice that it does not wish to extend this
Agreement; and provided, further, that notwithstanding any such notice by
the Company not to extend, this Agreement shall continue in effect for a
period of 24 months beyond the term provided herein if a Change in Control
(as defined in Section 3(i) hereof) shall have occurred during such term.
2. Termination of Employment.
--------------------------
(i) Prior to a Change in Control. Employee's rights upon
termination of employment prior to a Change in Control (as defined in
Section 3(i) hereof) shall be governed by the Company's standard employment
termination policy applicable to Employee in effect at the time of
termination.
(ii) After a Change in Control.
(a) From and after the date of a Change in Control (as
defined in Section 3(i) hereof) during the term of this Agreement, the
Company shall not terminate Employee from employment with the Company except
as provided in this Section 2(ii) or as a result of Employee's Disability
(as defined in Section 3(iv) hereof) or death.
(b) From and after the date of a Change in Control (as
defined in Section 3(i) hereof) during the term of this Agreement, the
Company shall have the right to terminate Employee from employment with the
Company at any time during the term of this Agreement for Cause (as defined
in Section 3(iii) hereof), by written notice to Employee, specifying the
particulars of the conduct of Employee forming the basis for such
termination.
(c) From and after the date of a Change in Control (as
defined in Section 3(i) hereof) during the term of this Agreement: (x) the
Company shall have the right to terminate Employee's employment without
Cause (as defined in Section 3(iii) hereof), at any time; and (y) Employee
shall, upon the occurrence of such a termination by the Company without
Cause, or upon the voluntary termination of Employee's employment by
Employee for Good Reason (as defined in Section 3(ii) hereof), be entitled
to receive the benefits provided in Section 4 hereof. Employee shall
evidence a voluntary termination for Good Reason by written notice to the
Company given within 60 days after the date of the occurrence of any event
that Employee knows or should reasonably have known constitutes Good Reason
for voluntary termination. Such notice need only identify Employee and set
forth in reasonable detail the facts and circumstances claimed by Employee
to constitute Good Reason.
Any notice given by Employee pursuant to this Section 2 shall be
effective five business days after the date it is given by Employee.
3. Definitions
-----------
(i) A "Change in Control" shall mean:
(a) a change in control of a nature that would be required to
be reported in response to Item 6(e) of Schedule 14A of Regulation 14A
promulgated under the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), or successor provision thereto, whether or not the Company
is then subject to such reporting requirement;
(b) any "person" (as such term is used in Sections 13(d) and
14(d) of the Exchange Act) is or becomes the "beneficial owner" (as defined
in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly,
of securities of the Company representing 35% or more of the combined voting
power of the Company's then outstanding securities;
(c) the Continuing Directors (as defined in Section 3(v)
hereof) cease to constitute a majority of the Company's Board of Directors;
provided that such change is the direct or indirect result of a proxy fight
and contested election or elections for positions on the Board of Directors;
or
(d) the majority of the Continuing Directors (as defined in
Section 3(v) hereof) determine in their sole and absolute discretion that
there has been a change in control of the Company.
(ii) "Good Reason" shall mean the occurrence of any of the following
events, except for the occurrence of such an event in connection with the
termination or reassignment of Employee's employment by the Company for
Cause (as defined in Section 3(iii) hereof), for Disability (as defined in
Section 3(iv) hereof) or for death:
(a) the assignment to Employee of employment responsibilities
which are not of comparable responsibility and status as the employment
responsibilities held by Employee immediately prior to a Change in Control;
(b) a reduction by the Company in Employee's base salary as
in effect immediately prior to a Change in Control;
(c) an amendment or modification of the Company's incentive
compensation program (except as may be required by applicable law) which
affects the terms or administration of the program in a manner adverse to
the interest of Employee as compared to the terms and administration of such
program immediately prior to a Change in Control;
(d) the Company's requiring Employee to be based anywhere
other than within 50 miles of Employee's office location immediately prior
to a Change in Control, except for requirements of temporary travel on the
Company's business to an extent substantially consistent with Employee's
business travel obligations immediately prior to a Change in Control;
(e) except to the extent otherwise required by applicable
law, the failure by the Company to continue in effect any benefit or
compensation plan, stock ownership plan, stock purchase plan, stock
incentive plan, bonus plan, life insurance plan, health-and-accident plan,
or disability plan in which Employee is participating immediately prior to a
Change in Control (or plans providing Employee with substantially similar
benefits), the taking of any action by the Company which would adversely
affect Employee's participation in, or materially reduce Employee's benefits
under, any of such plans or deprive Employee of any material fringe benefit
enjoyed by Employee immediately prior to such Change in Control, or the
failure by the Company to provide Employee with the number of paid vacation
days to which Employee is entitled immediately prior to such Change in
Control in accordance with the Company's vacation policy as then in effect;
or
(f) the failure by the Company to obtain, as specified in
Section 6(i) hereof, an assumption of the obligations of the Company to
perform this Agreement by any successor to the Company.
(iii) "Cause" shall mean termination by the Company of Employee's
employment based upon (a) the willful and continued failure by Employee
substantially to perform Employee's duties and obligations (other than any
such failure resulting from Employee's incapacity due to physical or mental
illness or any such actual or anticipated failure resulting from Employee's
termination for Good Reason) or (b) the willful engaging by Employee in
misconduct which is materially injurious to the Company, monetarily or
otherwise. For purposes of this Section 3(iii), no action or failure to act
on Employee's part shall be considered "willful" unless done, or omitted to
be done, by Employee in bad faith and without reasonable belief that such
action or omission was in the best interests of the Company.
(iv) "Disability" shall mean any physical or mental condition which
would qualify Employee for a disability benefit under the Company's long-
term disability plan.
(v) "Continuing Director" shall mean any person who is a member of
the Board of Directors of the Company, while such person is a member of the
Board of Directors, who is not an Acquiring Person (as hereinafter defined)
or an Affiliate or Associate (as hereinafter defined) of an Acquiring
Person, or a representative of an Acquiring Person or of any such Affiliate
or Associate, and who (a) was a member of the Board of Directors on the date
of this Agreement as first written above or (b) subsequently becomes a
member of the Board of Directors, if such person's nomination for election
or initial election to the Board of Directors is recommended or approved by
a majority of the Continuing Directors. For purposes of this Section 3(v):
"Acquiring Person" shall mean any "person" (as such term is used in Sections
13(d) and 14(d) of the Exchange Act) who or which, together with all
Affiliates and Associates of such person, is the "beneficial owner" (as
defined in Rule 13d-3 promulgated under the Exchange Act) of 20% or more of
the shares of Common Stock of the Company then outstanding, but shall not
include the Company, any subsidiary of the Company or any employee benefit
plan of the Company or of any subsidiary of the Company or any entity
holding shares of Common Stock organized, appointed or established for, or
pursuant to the terms of, any such plan; and "Affiliate" and "Associate"
shall have the respective meanings ascribed to such terms in Rule 12b-2
promulgated under the Exchange Act.
4. Benefits upon Termination under Section 2(ii)(c)
------------------------------------------------
(i) Upon the termination (voluntary or involuntary) of the
employment of Employee pursuant to Section 2(ii)(c) hereof, Employee shall
be entitled to receive the benefits specified in this Section 4. The
amounts due to Employee under subparagraph (a) of this Section 4(i) shall be
paid to Employee, at Employee's election as specified in a written notice
delivered by Employee to the Company on the date of this Agreement and which
is attached hereto as Exhibit A and made a part hereof, either (a) in a lump
sum not later than one business day prior to the date that the termination
of Employee's employment becomes effective or (b) in 36 equal installments
payable monthly, on the last business day of the month, for 36 consecutive
months following the date that the termination of Employee's employment
becomes effective. The amounts due to Employee under subparagraphs (b), (c)
and (d) of this Section 4(i) shall be paid to Employee not later than one
business day prior to the date that the termination of Employee's employment
becomes effective. Subject to the provisions of Section 4(ii) hereof, all
benefits to Employee pursuant to this Section 4(i) shall be subject to any
applicable payroll or other taxes required by law to be withheld.
(a) The Company shall pay as severance pay to Employee an
amount equal to three times the sum of (1) Employee's highest annual rate of
salary from the Company in effect at any time during the 36 months preceding
the date that the termination of Employee's employment became effective and
(2) the average of the annual bonus paid or to be paid to Employee in
respect of each of the three fiscal years preceding the fiscal year when the
termination of Employee's employment became effective.
(b) For a period of 36 months following the date that the
termination of Employee's employment became effective or until Employee
reaches age 65 or dies, whichever is the shorter period, the Company shall
continue for Employee, at the Company's expense, the health, disability and
life insurance coverage in effect for Employee immediately prior to the date
that the termination of Employee's employment became effective under the
plans provided by the Company for its executive personnel generally or, if
such coverage cannot by the terms of such plans be provided thereunder, then
the Company shall provide equivalent insurance coverage for Employee for
such period under specially obtained policies of insurance.
(c) The Company shall pay to Employee (1) any amount earned
by Employee as a bonus with respect to the fiscal year of the Company
preceding the termination of Employee's employment if such bonus has not
theretofore been paid to Employee, and (2) an amount representing credit for
any vacation earned or accrued by him but not taken.
(d) The Company shall also pay to Employee all legal fees
and expenses incurred by Employee as a result of such termination of
employment (including all fees and expenses, if any, incurred by Employee in
seeking to obtain or enforce any right or benefit provided to Employee by
this Agreement whether by arbitration or otherwise); and
(e) Any and all contracts, agreements or arrangements
between the Company and Employee prohibiting or restricting Employee from
owning, operating, participating in, or providing employment or consulting
services to, any business or company competitive with the Company at any
time or during any period after the date the termination of Employee's
employment becomes effective, shall be deemed terminated and of no further
force or effect as of the date the termination of Employee's employment
becomes effective, to the extent, but only to the extent, such contracts,
agreements or arrangements so prohibit or restrict Employee; provided that
the foregoing provision shall not constitute a license or right to use any
proprietary information of the Company and shall in no way affect any such
contracts, agreements or arrangements insofar as they relate to
nondisclosure and nonuse of proprietary information of the Company
notwithstanding the fact that such nondisclosure and nonuse may prohibit or
restrict Employee in certain competitive activities.
(ii) In the event that any payment or benefit received or to be
received by Employee in connection with a Change in Control of the Company
or termination of Employee's employment (whether payable pursuant to the
terms of this Agreement or any other plan, contract, agreement or
arrangement with the Company, with any person whose actions result in a
Change in Control of the Company or with any person constituting a member of
an "affiliated group" as defined in Section 280G(d)(5) of the Internal
Revenue Code of 1986, as amended (the "Code"), with the Company or with any
person whose actions result in a Change in Control of the Company
(collectively, the "Total Payments")) would be subject to the excise tax
imposed by Section 4999 of the Code or any interest, penalties or additions
to tax with respect to such excise tax (such excise tax, together with any
such interest, penalties or additions to tax, are collectively referred to
as the "Excise Tax"), then Employee shall be entitled to receive from the
Company an additional cash payment (a "Gross-Up Payment") within thirty
business days of such determination in an amount such that after payment by
Employee of all taxes (including any interest, penalties or additions to tax
imposed with respect to such taxes), including any Excise Tax, imposed upon
the Gross-Up Payment, Employee retains an amount of the Gross-Up Payment
equal to the Excise Tax imposed upon the Total Payments. All determinations
required to be made under this Section 4(ii), including whether a Gross-Up
Payment is required and the amount of such Gross-Up Payment, shall be made
by the independent accounting firm retained by the Company on the date of
the Change in Control (the "Accounting Firm"), which shall provide detailed
supporting calculations both to the Company and Employee within 15 business
days of the date that the termination of Employee's employment becomes
effective, or such earlier time as is requested by the Company. If the
Accounting Firm determines that no Excise Tax is payable by Employee, it
shall furnish Employee with an opinion that Employee has substantial
authority not to report any Excise Tax on Employee's federal income tax
return.
Any uncertainty in the application of Section 4999 of the Code at the
time of the initial determination by the Accounting Firm hereunder shall be
resolved in favor of Employee. As a result of the uncertainty in the
application of Section 4999 of the Code at the time of the initial
determination by the Accounting Firm hereunder, it is possible that at a
later time there will be a determination that the Gross-Up Payments made by
the Company were less than the Gross-Up Payments that should have been made
by the Company ("Underpayment"), consistent with the calculations required
to be made hereunder. In the event that Employee is required to make a
payment of any Excise Tax, the Accounting Firm shall determine the amount of
the Underpayment, if any, that has occurred and any such Underpayment shall
be promptly paid by the Company to or for the benefit of Employee. As a
result of the uncertainty in the application of Section 4999 of the Code at
the time of the initial determination by the Accounting Firm hereunder, it
is possible that at a later time there will be a determination that the
Gross-Up Payments made by the Company were more than the Gross-Up Payments
that should have been made by the Company ("Overpayment"), consistent with
the calculations required to be made hereunder. Employee agrees to refund
to the Company the amount of any Overpayment that the Accounting Firm shall
determine has occurred hereunder. Any determination by the Accounting firm
as to the amount of any Gross-Up Payment, including the amount of any
Underpayment or Overpayment, shall be binding upon the Company and Employee.
(iii) Any payment not made to Employee when due hereunder shall
thereafter, until paid in full, bear interest at the rate of interest equal
to the reference rate announced from time to time by U.S. Bank National
Association, plus two percent, with such interest to be paid to Employee
upon demand or monthly in the absence of a demand.
(iv) Employee shall not be required to mitigate the amount of any
payment provided for in this Section 4 by seeking other employment or
otherwise. The amount of any payment or benefit provided in this Section 4
shall not be reduced by any compensation earned by Employee as a result of
any employment by another employer.
5. Employee's Agreements.
----------------------
Employee agrees that:
(i) Without the consent of the Company, Employee will not terminate
employment with the Company without giving 60 days prior notice to the
Company, and during such 60-day period Employee will assist the Company, as
and to the extent reasonably requested by the Company, in training the
successor to Employee's position with the Company. The provisions of this
Section 5(i) shall not apply to any termination (voluntary or involuntary)
of the employment of Employee pursuant to Section 2(ii)(c) hereof.
(ii) Without the consent of the Company or except as may be required
by law, Employee will not at any time after termination of his employment
with the Company disclose to any person, corporation, firm, or other entity,
confidential information concerning the Company of which Employee has gained
knowledge during employment with the Company.
(iii) In the event that Employee has received any benefits from the
Company under Section 4 of this Agreement, then, during the period of 36
months following the date that the termination of Employee's employment
became effective, Employee, upon request by the Company:
(a) Will consult with one or more of the executive officers
concerning the business and affairs of the Company for not to exceed four
hours in any month at times and places selected by Employee as being
convenient to him, all without compensation other than what is provided for
in Section 4 of this Agreement; and
(b) Will testify as a witness on behalf of the Company in any
legal proceedings involving the Company which arise out of events or
circumstances that occurred or existed prior to the date that the
termination of Employee's employment became effective (except for any such
proceedings relating to this Agreement), without compensation other than
what is provided for in Section 4 of this Agreement, provided that all out-
of-pocket expenses incurred by Employee in connection with serving as a
witness shall be paid by the Company.
Employee shall not required to perform Employee's obligations under
this Section 5(iii) if and so long as the Company is in default with respect
to performance of any of its obligations under this Agreement.
6. Successors and Binding Agreement.
---------------------------------
(i) The Company will require any successor (whether direct or
indirect, by purchase, merger, consolidation or otherwise to all or
substantially all of the business and/or assets of the Company), by
agreement in form and substance satisfactory to Employee, to expressly
assume and agree to perform this Agreement in the same manner and to the
same extent that the Company would be required to perform it if no such
succession had taken place. Failure of the Company to obtain such agreement
prior to the effectiveness of any such succession shall be a breach of this
Agreement and shall entitle Employee to compensation from the Company in the
same amount and on the same terms as Employee would be entitled hereunder if
employee terminated employment after a Change in Control for Good Reason,
except that for purposes of implementing the foregoing, the date on which
any such succession becomes effective shall be deemed the date that the
termination of Employee's employment becomes effective. As used in this
Agreement, "Company" shall mean the Company and any successor to its
business and/or assets which executes and delivers the agreement provided
for in this Section 6(i) or which otherwise becomes bound by all the terms
and provisions of this Agreement by operation of law.
(ii) This Agreement is personal to Employee, and Employee may not
assign or transfer any part of Employee's rights or duties hereunder, or any
compensation due to him hereunder, to any other person. Notwithstanding the
foregoing, this Agreement shall inure to the benefit of and be enforceable
by Employee's personal or legal representatives, executors, administrators,
heirs, distributees, devisees, and legatees.
7. Arbitration. Any dispute or controversy arising under or in
connection with this Agreement shall be settled exclusively by arbitration
in the Fergus Falls area, in accordance with the applicable rules of the
American Arbitration Association then in effect. Judgment may be entered on
the arbitrator's award in any court having jurisdiction.
8. Modification; Waiver. No provisions of this Agreement may be
modified, waived, or discharged unless such waiver, modification, or
discharge is agreed to in a writing signed by Employee and such officer as
may be specifically designated by the Board of Directors of the Company. No
waiver by either party hereto at any time of any breach by the other party
hereto of, or compliance with, any condition or provision of this Agreement
to be performed by such other party shall be deemed a waiver of similar or
dissimilar provisions or conditions at the same or at any prior or
subsequent time.
9. Notice. All notices, requests, demands, and all other
communications required or permitted by either party to the other party by
this Agreement (including, without limitation, any notice of termination of
employment and any notice of an intention to arbitrate) shall be in writing
and shall be deemed to have been duly given when delivered personally or
received by certified or registered mail, return receipt requested, postage
prepaid, at the address of the other party, as first written above (directed
to the attention of the Board of Directors and Corporate Secretary in the
case of the Company). Either party hereto may change its address for
purposes of this Section 9 by giving 15 days' prior notice to the other
party hereto.
10. Severability. If any term or provision of this Agreement or the
application hereof to any person or circumstances shall to any extent be
invalid or unenforceable, the remainder of this Agreement or the application
of such term or provision to persons or circumstances other than those as to
which it is held invalid or unenforceable shall not be affected thereby, and
each term and provision of this Agreement shall be valid and enforceable to
the fullest extent permitted by law.
11. Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
12. Governing Law. This Agreement has been executed and delivered in
the State of Minnesota and shall, in all respects, be governed by, and
construed and enforced in accordance with, the laws of the State of
Minnesota, including all matters of construction, validity and performance.
13. Effect of Agreement; Entire Agreement. The Company and Employee
understand and agree that this Agreement is intended to reflect their
agreement only with respect to payments and benefits upon termination in
certain cases and is not intended to create any obligation on the part of
either party to continue employment. This Agreement supersedes any and all
other oral or written agreements or policies made relating to the subject
matter hereof and constitutes the entire agreement of the parties relating
to the subject matter hereof; provided that this Agreement shall not
supersede or limit in any way Employee's rights under any benefit plan,
program or arrangements in accordance with their terms.
14. ERISA. For purposes of the Employee Retirement Income Security
Act of 1974, this Agreement is intended to be a severance pay employee
welfare benefit plan, and not an employee pension benefit plan, and shall be
construed and administered with that intention.
IN WITNESS WHEREOF, the Company has caused this Agreement to be
executed in its name by a duly authorized director and officer, and Employee
has hereunto set his or her hand, all as of the date first written above.
OTTER TAIL POWER COMPANY
By
------------------------
Its
---------------------
EMPLOYEE
---------------------------
EXHIBIT A
NOTICE
The undersigned ("Employee") does hereby notify Otter Tail Power Company
(the "Company") pursuant to Section 4(i) of that certain Severance Agreement
dated as of the date hereof between the Company and Employee (the
"Agreement") that Employee has elected to be paid any amounts which become
payable under Section 4(i)(a) of the Agreement as follows:
(check one)
______ in a lump sum not later than one business day prior to the
date that the termination of Employee's employment becomes effective.
______ in 36 equal installments payable monthly, on the last
business day of the month, for 36 consecutive months following the date that
the termination of Employee's employment becomes effective.
Dated:
-------------------------
--------------------------------
Employee
<TABLE>
<CAPTION>
EXHIBIT 13-A
Selected consolidated financial data
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 (3) 1997 1996 1995 1994 1989
-------- ---------- -------- -------- -------- -------- --------
(thousands except per-share data)
Revenues
- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Electric $ 233,527 $ 227,477 $ 205,121 $ 199,345 $ 203,925 $ 198,812 $172,607
Manufacturing 93,411 87,434 83,174 64,568 38,690 13,083 -
Health services 69,312 69,412 66,859 61,697 50,896 45,555 -
Other business operations 68,327 48,829 44,173 45,323 32,818 29,276 1,756
--------- --------- --------- --------- --------- --------- --------
Total operating revenues $ 464,577 $ 433,152 $ 399,327 $ 370,933 $ 326,329 $ 286,726 $174,363
Special charges $ - $ 9,522 $ - $ - $ - $ - $ -
Cumulative change in accounting principle $ - $ 3,819 $ - $ - $ - $ - $ -
Net income (1) $ 44,977 $ 34,520 $ 32,346 $ 30,624 $ 28,945 $ 28,475 $ 25,266
Cash flow from operations $ 78,325 $ 63,959 $ 69,398 $ 68,611 $ 58,077 $ 51,832 $ 46,902
Total assets $ 680,788 $ 655,612 $ 655,441 $ 669,704 $ 609,196 $ 578,972 $462,596
Long-term debt $ 176,437 $ 181,046 $ 189,973 $ 163,176 $ 168,261 $ 162,196 $119,711
Redeemable preferred $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 14,815
Common shares outstanding
(2) (4) (thousands) 23,850 23,759 23,462 23,072 22,360 22,360 23,589
Number of common
shareholders (5) 13,438 13,699 13,753 13,829 13,933 14,115 14,277
Basic and diluted earnings per share (2) (6) $ 1.79 $ 1.36 $ 1.29 $ 1.23 $ 1.19 $ 1.17 $ 0.97
Dividends per common share (2) $ 0.99 $ 0.96 $ 0.93 $ 0.90 $ 0.88 $ 0.86 $ 0.76
- ------------------------------------------------------------------------------------------------------------------------------
Notes:
(1) Includes net gain from sale of radio station assets of $8.1 million in 1999.
(2) Common shares outstanding and per-share data reflect the effect of the two-for-one stock split effective March 15, 2000.
(3) In the first quarter of 1998 the Company changed its method of electric revenue recognition in the states of Minnesota
and South Dakota from meter-reading dates to energy-delivery dates. Basic and diluted earnings per share includes
16 cents per share related to the cumulative effect of the change in accounting principle.
(4) Number of shares outstanding at year-end.
(5) Holders of record at year-end.
(6) Based on average number of shares outstanding.
</TABLE>
Management's discussion and analysis of
financial condition and results of operations
(Per-share data reflects the effect of the stock split described in note 15
to the consolidated financial statements.)
Management's major financial objective is to increase shareholder value by
earning returns for shareholders that exceed returns available from comparable
risk investments. Management can meet this objective by earning the returns
regulators allow in electric operations combined with successfully growing
diversified operations. Meeting this objective enables the Company to
preserve and enhance its financial capability by maintaining optimal
capitalization ratios and a strong interest coverage position, providing
excellent returns to the common shareholder in the form of long-term capital
appreciation and dividends, and preserving strong credit ratings on
outstanding securities, which in the form of lower interest rates benefits
both the Company's customers and shareholders.
Liquidity:
Liquidity is the ability to generate adequate amounts of cash to
meet the Company's needs, both short-term and long-term. Historically, the
Company's liquidity has been a function of its capital expenditures and debt
service requirements, its net internal funds generation, and its access to
long-term securities markets and credit facilities for external capital.
Over the years the Company has achieved a high degree of long-term liquidity
by maintaining desired capitalization ratios through timely stock and debt
issuances or repurchases, maintaining strong bond ratings, implementing cost-
containment programs, evaluating operations and projects on a cost-benefit
approach, investing in projects that enhance shareholder value, and
implementing sound tax-reduction strategies.
Cash provided by operating activities of $78.3 million, as shown on the
Consolidated Statement of Cash Flows for the year ended December 31, 1999,
combined with cash provided by issuing $1.8 million in common stock and funds
on hand of $3.9 million at December 31, 1998, allowed the Company to pay
dividends, meet sinking fund payment requirements, acquire an additional
company, redeem one series of preferred stock and finance its consolidated
capital expenditures in 1999. The increase of $21 million in cash and cash
equivalents primarily relates to the sale of the radio station assets that
occurred during the fourth quarter. A significant amount of the cash on
hand at December 31, 1999, was used to fund an acquisition in January 2000.
In 1999 the Company issued 89,238 common shares under its Automatic Dividend
Reinvestment and Share Purchase Plan, generating proceeds of $1.7 million.
In June 1999 the Company began purchasing the common shares needed for this
plan from the open market instead of issuing new shares.
The Company estimates that funds internally generated net of forecasted
dividend payments, combined with funds on hand, will be sufficient to meet
sinking fund payments on First Mortgage Bonds and preferred stock redemption
requirements in the next five years and to provide for its estimated 2000
through 2004 consolidated capital expenditures. Additional short-term or
long-term financing will be required in the period 2000 through 2004 for the
maturity of long-term debt, in the event the Company decides to refund or
retire early any of its presently outstanding debt or cumulative preferred
shares, or for other corporate purposes.
Capital requirements:
The Company's consolidated capital requirements include
periodic and timely replacement of technically obsolete or worn-out equipment,
new equipment purchases, and plant upgrades to accommodate anticipated growth.
The electric segment has a construction and capital investment program to
provide facilities necessary to meet forecasted customer demands and to
provide reliable service. The construction program is subject to continuing
review and is revised annually in light of changes in demands for energy,
availability of energy within the power pool, cost of capacity charges
relative to cost of new generation, environmental laws, regulatory changes,
technology, the costs of labor, materials and equipment, and the Company's
financial condition (including cash flow and earnings).
Consolidated capital expenditures for the years 1999, 1998, and 1997 were $33
million, $29 million, and $42 million, respectively. The estimated capital
expenditures for 2000 are $35 million, and the total capital expenditures for
the five-year period 2000 through 2004 are expected to be approximately $210
million. The breakdown of 1999 actual and 2000 through 2004 estimated
capital expenditures by segment is as follows:
1999 2000 2000-2004
---- ---- ---------
(in millions)
Electric utility $ 20 $ 24 $125
Manufacturing 7 4 26
Health services 1 4 42
Other business operations 5 3 17
---- ---- ---------
Total $ 33 $ 35 $210
In addition to these capital requirements, funds totaling approximately $50
million will be needed during the five-year period 2000 through 2004 to
retire First Mortgage Bonds and other long-term obligations at maturity
(including sinking fund payments for First Mortgage Bonds and preferred
stock redemption requirements).
Capital resources:
Financial flexibility is provided by unused lines of
credit, strong financial coverages and credit ratings, and alternative
financing arrangements such as leasing.
As of December 31, 1999, the Company had $24.8 million in cash and cash
equivalents and $32.7 million in lines of credit available. Bank lines of
credit are a key source of operating capital and can provide interim
financing of working capital and other capital requirements, if needed.
The subsidiaries' notes and credit lines are secured by a pledge of all of
the common stock of the subsidiaries. (See note 11 to consolidated financial
statements.)
The Company's coverage ratios improved in 1999 compared to 1998 due to the
gain from the sale of radio station assets. The fixed charge coverage ratio
after taxes was 6.1 for 1999 as compared to 4.0 for 1998, and the long-term
debt interest coverage ratio before taxes was 6.1 for 1999, as compared to
4.3 for 1998. During 2000 the Company expects these coverages to return to
ratios similar to 1998.
The Company's credit ratings affect its access to the capital market. The
current credit ratings for the Company's First Mortgage Bonds at December 31,
1999, which remain unchanged from 1998, are as follows:
Moody's Investors Service Aa3
Duff and Phelps AA
Standard and Poor's AA-
The Company's disclosure of these security ratings is not a recommendation
to buy, sell, or hold its securities.
Results of operations:
Electric operations
Otter Tail Power Company provides electrical service to more than 126,000
customers in a service territory exceeding 50,000 square miles.
1999 1998 1997
-------- -------- --------
(in thousands)
Operating revenues $233,527 $227,477 $205,121
Production fuel 36,839 34,234 31,362
Purchased power 44,190 40,609 24,420
Other operation and maintenance expenses 73,308 70,584 72,112
Special charges -- 7,022 --
Depreciation and amortization 21,782 22,128 21,442
Property taxes 10,174 10,684 10,819
-------- -------- --------
Operating income $ 47,234 $ 42,216 $ 44,966
(bar graph of information in following table)
Electric operating income
(millions)
--------------------------------
1997 $45.0
1998 $42.2
1999 $47.2
(end of graph)
Electric operating revenues increased 2.7 percent in 1999, as compared to
1998, due to a $16.1 million increase in power pool revenues offset by a
$5.5 million decrease in retail revenue and a $4.6 million decrease in other
electric revenue. Hot summer weather in the Midwest and North Central regions
of the United States, combined with increased emphasis on power marketing
efforts and increased generation at the Company's plants contributed to the
increase in power pool revenues. Reductions in kilowatt-hour (kwh) sales to
industrial customers, particularly pipeline customers, combined with lower
revenue per retail kwh for 1999 as compared to 1998 contributed to the
decrease in retail revenues. The reduction in revenue per retail kwh
primarily was due to a reduction in cost of energy revenues. Other electric
revenue decreased $4.6 million primarily as a result of a reduction in
electrical contract work done for other utilities combined with the Company's
decision not to record 1999 Minnesota Conservation Improvement Program (CIP)
financial incentives until approved by the Minnesota Public Utilities
Commission (MPUC). See note 5 to consolidated financial statements.
The 10.9 percent increase in electric operating revenues in 1998, as compared
to 1997, is due to a $17.9 million increase in power pool revenues, combined
with increases of $2.7 million in other electric revenue and $1.7 million in
retail revenue. Power pool kwh sales increased 96 percent and revenue per
power pool kwh sold increased 33 percent. An increase in energy available
for sale enabled the Company to respond to unusually high wholesale market
demands, resulting in the increase in power pool sales in 1998. The evolution
of a competitive wholesale electricity market is reflected in market-based
increases in revenue per power pool kwh sold and the cost per kwh of
purchased power. Other electric revenue increased as a result of more
electrical contract work done for other utilities and an increase in payments
from other utilities for the use of shared transmission facilities. Retail
revenue increased 0.9 percent despite a 0.3 percent decline in retail kwh
sales. Revenue per retail kwh increased 1.2 percent in 1998, as compared to
1997, as a result of increases in the CIP surcharge rate and an increase in
cost-of-energy revenues. Significantly milder weather during the first
quarter of 1998 was the main contributing factor to the decline in retail
kwh sales as heating degree days were down 18.7 percent for 1998 as compared
to 1997.
Increases or decreases in fuel and purchased power costs arising from changing
prices results in adjustments to the Company's rate schedules through the cost
of energy adjustment clause. During the last five years this has resulted in
savings of more than $45 million to the Company's customers.
Production fuel expense increased 7.6 percent in 1999 due to a 10.8 percent
increase in kwh generated offset by a 2.5 percent decrease in the fuel cost
per kwh generated at the Company's steam generating plants. The reduction
in fuel cost per kwh generated is a result of a settlement with Knife River
Coal Mining Company, which reduced the price of coal at Coyote Station. The
8.8 percent increase in purchased power expense in 1999 is directly related
to a 43.6 percent increase in power pool kwh sales. The increase in power
pool sales also drove the increase in kwhs generated at the Company's steam
generating units.
Greater plant availability in 1998, which allowed the Company to sell more
wholesale power, resulted in a 9.1 percent increase in kwh generated and a
9.2 percent increase in production fuel expense in 1998 as compared to 1997.
The 66.3 percent increase in purchased power costs in 1998 as compared to
1997 is due to a 161 percent increase in cost of power purchased for resale
combined with a 6.8 percent increase in cost of power purchased for system
use. The cost of power purchased for system use increased despite a 5.1
percent decrease in the volume of energy purchased for system use as a result
of generally higher market prices for purchased power during 1998. Power
purchased for resale increased due to a 96 percent increase in power pool
sales combined with a 40 percent increase in cost per kwh purchased for
resale.
The 3.9 percent increase in other electric operation and maintenance expenses
for 1999 as compared to 1998 primarily is due to the recording of expenses
related to employee incentive programs and increased expenditures for
transmission and distribution system line maintenance to enhance service
reliability. These increases were offset by a reduction in material and
supplies expenses due to less contracted work for other utilities during 1999
and no major overhaul work performed at the Company's generating plants in
1999.
Other electric operation and maintenance expenses for 1998 as compared to
1997, decreased 2.1 percent. This decrease, in part, reflects the effect of
the Company's early retirement program, which resulted in a workforce
reduction of 55 employees by June 1, 1998. Maintenance expenses were higher
in 1997 than in 1998 due to Coyote Station's ten-week overhaul in 1997.
Special charges incurred in 1998 of $7 million represent two items related to
electric operations: (1) a noncash charge of $6.3 million associated with the
Company's voluntary early retirement program and (2) the write-off of
$717,000 in accumulated costs related to a rail spur project at Big Stone
Plant. (See note 3 to consolidated financial statements.) The Company
incurred insignificant additional costs related to the early retirement offer
after the first quarter of 1998.
The 1.6 percent decrease in depreciation and amortization expense for 1999 as
compared to 1998 is due to a decrease in depreciation rates offset by an
increase in plant in service. Depreciation and amortization expense for 1998
as compared to 1997 increased 3.2 percent due to a slight increase in
electric plant in service.
Property taxes decreased 4.8 percent in 1999 as compared to 1998 due to
reductions in Minnesota property taxes as a result of legislative action
affecting commercial and industrial property class rates for 1999 and changes
in the formula funding for schools.
Manufacturing operations
Manufacturing operations is made up of businesses involved in the production
of polyvinyl chloride (PVC) pipe, agricultural equipment, frame-straightening
equipment and accessories for the auto body shop industry, contract
machining, and metal parts stamping and fabricating.
1999 1998 1997
-------- -------- --------
(in thousands)
Operating revenues $93,411 $87,434 $83,174
Cost of goods sold 71,489 64,390 61,361
Operating expenses 14,698 13,435 12,668
-------- -------- --------
Operating income $ 7,224 $ 9,609 $ 9,145
(bar graph of information in following table)
Manufacturing operating income
(millions)
-------------------------------
1997 $9.1
1998 $9.6
1999 $7.2
(end of graph)
The 6.8 percent increase in manufacturing operating revenue during 1999 as
compared to 1998 was the result of increased sales of PVC pipe, stamped metal
parts, and frame-straightening equipment offset by decreased revenues from
manufacturing agricultural-related equipment. Manufacturing operating
revenue increased 5.1 percent in 1998 as a result of increased sales volumes
of 15 percent within the companies that produce agricultural equipment and
stamp metal parts. These increases were offset by a reduction in sales of
frame-straightening equipment and accessories for the auto body shop industry
and a decrease in revenues from sales of PVC pipe.
Cost of goods sold for the manufacturing operations increased 11.0 percent
during 1999 due to the increase in sales volumes of PVC pipe and stamped
metal parts combined with an increase in prices for resins used to
manufacture PVC pipe. During 1998 manufacturing cost of goods sold increased
4.9 percent as a result of the increased sales volumes, offset by a decrease
in prices for resins used to manufacture PVC pipe. Operating expenses
increased 9.4 percent during 1999 as compared to 1998 primarily due to
increases in sales expenses. The increase in operating expenses for 1998 of
6.1 percent was due primarily to increased labor costs and the use of outside
professional services.
Effective January 1, 2000, the Company acquired the assets and operations of
Vinyltech Corporation, a manufacturer of PVC pipe located in Phoenix, Arizona.
(See note 15 to consolidated financial statements.)
Health services operations
Health services operations include businesses involved in the sale, service,
rental, refurbishing, and operation of medical imaging equipment and the sale
of related supplies and accessories to various medical institutions.
1999 1998 1997
-------- -------- --------
(in thousands)
Operating revenues $69,312 $69,412 $66,859
Cost of goods sold 55,464 53,473 53,191
Operating expenses 8,526 8,744 8,700
------- ------- -------
Operating income $ 5,322 $ 7,195 $ 4,968
(bar graph of information in following table)
Health services operating income
(millions)
--------------------------------
1997 $5.0
1998 $7.2
1999 $5.3
(end of graph)
Operating revenues for health services decreased slightly for 1999 as
compared to 1998. Decreases in revenues from imaging scans performed were
offset by increases in the sales of medical imaging equipment. The 3.8
percent increase in health services operating revenue in 1998, as compared to
1997, is due to an increase in sales volumes of diagnostic medical equipment
combined with an increase in the number of medical imaging scans performed
offset by a decrease in the average fee per scan. The decrease in operating
revenues and the 3.7 percent increase in cost of goods sold during 1999
reflect the tightening of gross margins in this industry due to intense price
competition. Operating expenses decreased 2.5 percent in 1999 due to an
increased focus on reducing costs within the health services companies.
Other business operations
The Company's other business operations include businesses involved in
electrical and telephone construction contracting, transportation, tele-
communications, entertainment, energy services, and natural gas marketing.
On September 1, 1999, the Company acquired the flatbed trucking operations
of E. W. Wylie Corporation. (See note 4 to consolidated financial statements.)
In October 1999 the Company completed the sale of certain assets of the radio
stations and video production company owned by KFGO, Inc., and the radio
stations owned by Western Minnesota Broadcasting Company for $24.1 million.
Operating income includes results of operations for the radio stations
through September 1999. The gain from this sale was not included in operating
income for segment purposes. For additional information regarding the sale
see note 4 to consolidated financial statements.
During 1999 the Company agreed, as part of a settlement with the Minnesota
Pollution Control Agency, to donate all of its assets in its Quadrant Co.
waste incineration plant to the City of Perham, Minnesota. The plant had
ceased operations during the third quarter of 1998, and a related impairment
loss (shown as special charges in the table below) of $2.5 million was
recorded in 1998. (See note 3 to consolidated financial statements.)
Pro forma operating income for other business operations without Quadrant and
the radio stations would have been $6,303,000, $1,543,000, and $3,953,000 in
1999, 1998, and 1997, respectively.
Results of operations for the other business operations segment are as
follows:
1999 1998 1997
-------- -------- --------
(in thousands)
Operating revenues $68,327 $48,829 $44,173
Cost of goods sold 45,126 29,133 23,393
Special charges -- 2,500 --
Operating expenses 15,615 17,680 16,645
------- ------- -------
Operating income (loss) $ 7,586 $ (484) $ 4,135
(bar graph of information in following table)
Other business operations operating income
(millions)
------------------------------------------
1997 $ 4.1
1998 $(0.5)
1999 $ 7.6
(end of graph)
The 39.9 percent increase in other business operations operating revenues in
1999 reflects an $8.5 million increase at the construction subsidiaries due
to favorable construction markets and conditions, a $5.2 million increase at
the natural gas marketing subsidiary reflecting a full year of operations,
and inclusion of four months of operating revenues as a result of the Wylie
acquisition. The 1999 operating revenues also increased as a result of the
$1.5 million gain from the sale of an investment by the telecommunication
subsidiary. Cost of goods sold increased 54.9 percent in 1999, as compared
to 1998, due to a $6.5 million increase at the construction subsidiaries, a
$4.7 million increase due to the full year of operations at the natural gas
subsidiary, and inclusion of four months of expense as a result of the Wylie
acquisition. Operating expenses decreased 11.7 percent as a result of the
sale of the radio stations and the donation of the Quadrant plant.
Other business operations operating revenues, cost of goods sold, and
operating expenses increased 10.5 percent, 24.5 percent, and 6.2 percent,
respectively, in 1998, as compared to 1997, primarily as a result of
acquiring the natural gas marketing subsidiary.
Gain from sale of radio station assets
The Company recorded a $14.5 million pre-tax gain from the sale of certain
assets of the six radio stations and the video production company owned by
KFGO, Inc., and the two radio stations owned by Western Minnesota
Broadcasting Company on October 1, 1999. The after-tax gain from this sale
contributed $0.34 to earnings per share.
Consolidated other income and deductions--net
(bar graph of information in following table)
Other income and deductions
(millions)
---------------------------
1997 $2.0
1998 $2.9
1999 $1.8
(end of graph)
Consolidated other income and deductions decreased 36.3 percent in 1999 due
to decreases in financial incentives from demand-side management programs and
dividend revenues offset by increased interest income. The 46.6 percent
increase in other income and deductions for 1998, as compared to 1997
reflects an increase in dividend income combined with an increase in revenue
recognition relating to Minnesota CIP financial incentives.
Consolidated interest charges
(bar graph of information in following table)
Interest charges
(millions)
----------------
1997 $18.5
1998 $15.6
1999 $14.8
(end of graph)
Interest charges for 1999 decreased 5.1 percent due to a reduction in average
outstanding debt for the year and lower average interest rates. The 15.9
percent decrease in interest charges in 1998 as compared to 1997 is a result
of a lower average interest rate on line of credit borrowings and of
refinancing various diversified companies' fixed and variable interest rate
debt with lower fixed rate debt in November 1997. In addition, the decrease
can be attributed to the implementation of a consolidated cash management
function within the subsidiaries that allowed excess cash to be used to
reduce outstanding borrowings.
Consolidated income taxes
(bar graph of information in following table)
Income taxes
(millions)
------------
1997 $14.3
1998 $15.1
1999 $23.9
(end of graph)
The 58.0 percent increase in income taxes in 1999 as compared to 1998 reflects
income tax expense of $6.4 million related to the sale of the radio station
assets combined with an increase in income before tax. The 5.8 percent
increase in income taxes in 1998 as compared to 1997 reflects the use of a
capital loss carryforward in 1997 combined with an increase in income before
tax for 1998.
Cumulative effect of change in accounting principle
In the first quarter of 1998 the Company changed its method of revenue
recognition in Minnesota and South Dakota from meter-reading dates to energy-
delivery dates resulting in the recognition of $6,364,000 ($3,819,000 net-of-
tax or $0.16 per share) in unbilled revenues. (See note 2 to consolidated
financial statements.)
Impact of inflation
The Company operates under regulatory provisions that allow price changes in
the cost of fuel and purchased power to be passed to customers through
automatic adjustments to its rate schedules under the cost of energy
adjustment clause. Other increases in the cost of electric service must be
recovered through timely filings for rate relief with the appropriate
regulatory agency.
The Company's health services, manufacturing, and other business operations
consist almost entirely of unregulated businesses. Increased operating costs
are reflected in product or services pricing with any limitations on price
increases determined by the marketplace. The impact of inflation on these
segments has been less significant during the past few years because of the
relatively low rates of inflation experienced in the United States. Raw
material costs, labor costs, and interest rates are important components of
costs for companies in these segments. Any or all of these components could
be impacted by inflation, with a possible adverse effect on the Company's
profitability.
Factors affecting future earnings
The results of operations discussed above are not necessarily indicative of
future earnings. Factors that might affect future earnings 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, changes in the economy of the Upper Midwest, governmental and
regulatory action, fuel and purchase power costs and environmental issues.
Anticipated higher operating costs and carrying charges on increased capital
investment in plant, if not offset by proportionate increases in operating
revenues and other income (either by appropriate rate increases, increases
in unit sales, or increases in nonelectric operations), will affect future
earnings.
Diversification
- ---------------
In 1999 approximately 30 percent of the Company's net earnings were
contributed by diversified operations, excluding the gain from the sale of
the radio station assets. The Company plans to make additional acquisitions
through its wholly owned subsidiary, Varistar Corporation. It is possible
that by 2004, more than 45 percent of the Company's net earnings will be
contributed from diversified operations. The following guidelines are used
when considering acquisitions: emerging or middle market company; proven
entrepreneurial management team that will remain after the acquisition;
products and services that are intended for commercial rather than retail
consumer use; the ability to provide immediate earnings and future growth
potential; and 100 percent ownership. The Company intents to grow earnings
as a long-term owner of these investments. However, such as in the case with
the sale of the radio station assets during 1999, the Company will compare
the returns of continued ownership of a business against its market value.
Continuing revenue growth from diversified operations could result in
earnings and stock price volatility.
While we cannot predict the success of our current diversified businesses, we
believe opportunities exist for growth in the business segments. Factors
that could affect the results of the diversified businesses include, but are
not limited to the following: fluctuations in the cost and availability of
raw materials and the ability to maintain favorable supplier arrangements and
relationships; competitive products and pricing pressures and the ability to
gain or maintain market share in trade areas; effectiveness of advertising,
marketing, and promotional programs; adverse weather conditions; and the
highly competitive nature of the health services industry.
Growth of electric revenue
- --------------------------
Growth in electric sales will be subject to a number of factors, including
the volume of power pool sales to other utilities, the effectiveness of
demand-side management programs, weather, competition, and the rate of
economic growth or decline in the Company's service area. The Company's
electric business is primarily dependent upon the use of electricity by
customers in our service area. The Company's electric kwh sales to retail
customers decreased 2.6 percent and 0.3 percent in 1999 and 1998,
respectively, and increased 1.4 percent in 1997.
Factors beyond the Company's control, such as mergers and acquisitions,
geographical location, transmission costs, unplanned interruptions at the
Company's generating plants, and the effects of deregulation, could lead to
greater volatility in the volume and price of power pool sales.
Regulation
- ----------
Rates of return earned on utility operations are subject to review by the
various state commissions that have jurisdiction over the electric rates
charged by the Company. These reviews may result in future revenue
reductions when actual rates of return are deemed by regulators to be in
excess of allowed rates of return.
During 1999 the North Dakota Public Service Commission (NDPSC) approved a
settlement agreement following an audit of the Company's electric operations
in North Dakota. The effects of this settlement decreased 1999 earnings by
approximately $441,000 after taxes or $0.02 per share. As part of the
settlement the Company is required to refund to North Dakota customers any
1999 regulated electric operations earnings from North Dakota over a 12.5
percent return on equity and file with the NDPSC a proposal for performance-
based ratemaking early in 2000. While the final decision on any potential
refund relating to 1999 results lies with the NDPSC, the Company expects
that any refund will not be significant.
Load Management and Minnesota Conservation Improvement Programs
- ---------------------------------------------------------------
Load management efforts will continue in all jurisdictions served by the
Company. The goal of load management is to control demand for electricity by
customers at times of peak use in order to alleviate or delay the need for
building or acquiring new generating capacity or to avoid having to purchase
high-priced energy at times of peak demand. In addition to our load
management efforts, we also invest in conservation improvement programs in
Minnesota as mandated by state law. Conservation improvement programs are
designed to encourage and reward the wise and efficient use of electricity
by customers.
In 1999, as a result of the Company's conservation improvement efforts, the
MPUC approved the Company's 1998 financial incentive filing, including lost
margins recovery, along with a 1.5 percent surcharge on all Minnesota
customers' bills (approximately 0.75 percent of total retail revenue) from
July 1, 1999 through June 30, 2000. The surcharge provides for the recovery
of conservation-related costs and financial incentives in excess of those
being recovered in current rates. The previous 12-month period surcharge was
2.75 percent. It is likely that any financial incentives approved by the MPUC
in the future will result in a significantly lower surcharge because recent
actions by the MPUC have indicated a movement toward the discontinuance of
allowing recovery of lost margins.
Fuel Costs
- ----------
The Company has reached an agreement for Big Stone Plant's coal supply
through December 31, 2001. In November 1995 the Company and two other Coyote
Station owners initiated a lawsuit against Knife River Coal Mining Company
and its parent, MDU Resources Group Inc., in an attempt to resolve disputes
over pricing in the Coyote coal agreement. The case was remanded to
arbitration in 1997. During 1999 settlement of the arbitration resulted in:
(1) a reduction of fuel prices for Coyote Station, beginning March 26, 1999,
(2) modification of the price adjustment provision of the contract for the
future, and (3) a requirement that Knife River refund excess amounts paid
for coal from September 13, 1996, through March 26, 1999. The Company
received a refund of $2.7 million, representing its share as a co-owner
of Coyote Station. This refund and accumulated interest has been recorded as
a liability pending regulatory filing in each state to determine procedures
for refunds to electric retail customers. The regulatory filings included a
request to recover costs related to the arbitration incurred by the Company.
The Mid-Continent Area Power Pool (MAPP) region has experienced a reduction
in availability of excess generation and transmission capacity, particularly
in the summer season in the past two years. While the availability of the
Company's plants has been excellent, the loss of a major plant could expose
the Company to higher purchased power costs. Two factors significantly
mitigate this financial risk. First, wholesale sales contracts include
provisions to release the Company from its obligations in case of a plant
outage, and second, the Company has cost of energy adjustment clauses that
allow pass through of energy costs to retail customers.
Environmental
- -------------
Current regulations under the Federal Clean Air Act (the Act) are not
expected to have a significant impact on future capital requirements or
operating costs. However, proposed or future regulations under the Act,
changes in the future coal supply market, and/or other laws and regulations
could impact such requirements or costs. It is anticipated that, under
current regulatory principles, any such costs could be recovered through
rates.
The Company's electric generating plants were not subject to the Act's phase
one requirements. Phase two standards of the Act must be met by the year
2000. The Company intends that Big Stone Plant will maintain current levels
of operation and meet phase two requirements for sulfur dioxide emissions by
burning subbituminous coal. The Company has a new coal contract that provides
a lower sulfur subbituminous coal for Big Stone Plant. Under EPA regulations,
modifications were required at Big Stone Plant by 2000 to satisfy nitrogen
oxide emission standards. During 1997 the Company conducted tests at Big
Stone Plant to determine if nitrogen oxide emissions could be reduced through
modifications to existing equipment. The results of the tests were positive
and modifications have been completed.
The Company's Coyote Station is equipped with sulfur dioxide removal
equipment. Compliance with the phase two requirements is not expected to
significantly impact operations at that plant. Hoot Lake Plant already uses
low-sulfur subbituminous coal, and minor modifications were completed to meet
the phase two nitrogen oxide emission requirements.
Deregulation and legislation
- ----------------------------
In December 1999 the Federal Energy Regulatory Commission (FERC) issued Order
No. 2000. This order requires public utilities that own, operate or control
interstate transmission to file by October 15, 2000 a proposal for a regional
transmission organization (RTO) or a description of any efforts made to
participate in an RTO, the reasons for not participating, and any plans for
further work towards participation. The goal is to consolidate control of
the transmission industry into a new structure of independent, regional grid
operators.
In 1996 the Federal Energy Regulatory Commission (FERC) issued two final
rules, Order Nos. 888 and 889, which give competing wholesale suppliers the
ability to transmit electricity through a utility's transmission system.
Order No. 888 requires electric utilities and other transmission providers to
abide by, and to offer to other transmission users, terms, conditions and
pricing comparable to those they use for themselves in transmitting power.
Order No. 889, which became effective January 3, 1997, requires public
utilities to implement Standards of Conduct and an Open Access Same-Time
Information System (OASIS). These rules require transmission personnel to
provide information about their transmission systems to all customers,
including their marketing associates within their respective companies,
through the OASIS. After rehearing, the FERC issued Orders 888A and B,
further clarifying its intent to prevent any discriminatory abuse of market
power by utilities controlling both transmission and generation assets. The
Company filed its initial transmission tariff on July 9, 1996, as required
by Order No. 888. A revised rate schedule became effective in the first
quarter of 1997.
The U.S. Congress ended its 1999 legislative session without taking action on
proposed electric industry restructuring legislation. We expect that during
2000 Congress will continue to debate proposed legislation which, if enacted,
would promote customer choice and a more competitive electric market. While
the Company cannot predict the timing or what form the legislation might
take, we continue to monitor the debate on the issues.
The Minnesota Legislature did not take any significant legislative action on
electric utility restructuring in 1999. However, the Minnesota Department of
Commerce is drafting comprehensive retail access legislation that is planned
to be introduced in January 2001. The Minnesota State Chamber of Commerce
plans to introduce legislation in 2000 to separate costs for generation,
transmission and distribution on electric service statements by July 1, 2001.
Company personnel have participated in a number of working groups set up by
the Minnesota Department of Commerce. In 1997 the North Dakota Legislature
created a subcommittee to investigate the impact of electric utility industry
restructuring on North Dakota. The North Dakota Legislature plans to deal
first with tax issues surrounding restructuring pertaining to both investor-
owned electric utilities and electric cooperatives. The South Dakota
Legislature and Public Utility Commission continue to monitor the status of
the industry restructuring and retail competition. The Company cannot
predict the timing or impact of regulatory actions regarding restructuring.
Competition in the electric industry
- ------------------------------------
As the electric industry moves towards deregulation the Company expects the
industry to become more competitive. The Company is taking a number of steps
to position itself for success in a competitive marketplace. The Company has
functionally unbundled its energy supply, energy delivery, and energy
services operations. Necessary accounting systems have been developed to
capture costs and determine the profitability of each of these business units
and to identify areas for improvement and opportunities for increased
profitability. Separate business plans have been created for each business
unit. The Company has established an energy services business unit to promote
the energy-related products and services traditionally offered to the
Company's customers and to develop new products and services to be offered
to current and potential customers in order to distinguish the Company from
the competition. The Company offered a voluntary early retirement program in
1998 that reduced the electric utility staff by 55 employees.
As the electric industry evolves and becomes more competitive, the Company
believes it is well positioned to be successful. The Company's generation
capacity appears poised for competition due to unit heat rate improvements
and reductions in fuel and freight costs. A comparison of the Company's
electric retail rates to the rates of other investor-owned utilities,
cooperatives, and municipals in the states the Company serves indicates
that its rates are competitive. In addition, the Company would attempt more
flexible pricing strategies under an open, competitive environment.
Year 2000 readiness disclosure
- ------------------------------
During the last three years the Company worked on becoming year 2000 ready.
The Company's readiness plan involved three phases: inventory, assessment and
remediation/testing, all of which were completed prior to December 31, 1999.
The Company coordinated its year 2000 efforts with those of MAPP and the
North American Electric Reliability Council. Critical external parties were
contacted, and contingency plans were developed. As of the date of this
report the Company has not experienced or been notified of any significant
year 2000 related issues or problems. While it still is possible that some
issues have not surfaced yet, the Company believes that any such issues will
not have a material adverse effect on the Company's consolidated results of
operations.
The costs of the Company's year 2000 readiness efforts have been funded with
cash flows from operations. These costs were not substantially different
from the normal, ongoing costs that are incurred for systems development,
implementation, and maintenance due in part to the use of internal resources
and the deferral of other projects. Management estimates that the total
expenditures related to the Company's year 2000 readiness effort since 1997
were approximately $900,000.
Accounting pronouncements
In June 1999 the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) 137 - Accounting for Derivative
Instruments and Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133. This statement delays the effective date for SFAS 133
until periods beginning after June 15, 2000. SFAS 133 - Accounting for
Derivative Instruments and Hedging Activities was issued by the FASB in
June 1998. SFAS 133 establishes accounting and reporting standards for
derivative instruments and for hedging activities. The adoption of this
statement is not expected to have a material impact on the Company's
financial position as presently reported.
Cautionary Statements
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995, the Company makes the following statements.
The information in this annual report includes forward-looking statements.
Important risks and uncertainties that could cause actual results to differ
materially from those discussed in such forward-looking statements are set
forth above under "Factors affecting future earnings." Other risks and
uncertainties may be presented from time to time in the Company's future
Securities and Exchange Commission filings.
Independent Auditors' Report
To the Shareholders of Otter Tail Power Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Otter Tail Power Company and its subsidiaries (the
Company) as of December 31, 1999, and 1998, and the related consolidated
statements of income, changes in equity, and cash flows for each of the
three years in the period ended December 31, 1999. These consolidated
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1999, and 1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with generally accepted accounting principles.
As discussed in note 2 to the consolidated financial statements, the Company
changed its method of accounting for unbilled revenues in 1998.
DELOITTE & TOUCHE LLP
January 31, 2000
Minneapolis, Minnesota
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Balance Sheets, December 31 1999 1998
- ---------------------------------------------------------------------------------------------
(in thousands)
Assets
Plant
<S> <C> <C>
Electric plant in service $ 779,037 $ 770,887
Diversified operations 99,558 89,094
--------- ---------
Total 878,595 859,981
Less accumulated depreciation and amortization 386,618 370,290
--------- ---------
Plant - net of accumulated depreciation and amortization 491,977 489,691
Construction work in progress 10,979 10,495
--------- ---------
Net plant 502,956 500,186
--------- ---------
Investments 19,502 20,612
--------- ---------
Intangibles--net 23,311 21,176
--------- ---------
Other assets 6,141 3,968
--------- ---------
Current assets
Cash and cash equivalents 24,762 3,919
Accounts receivable:
Trade (less accumulated provision for uncollectible accounts:
1999, $832,000; 1998, $1,444,000) 40,685 41,249
Other 5,616 6,845
Materials and supplies:
Fuel 3,808 3,418
Inventory, materials, and operating supplies 26,329 23,138
Deferred income taxes 3,123 2,730
Accrued utility revenues 9,923 11,179
Other 5,690 6,310
--------- ---------
Total current assets 119,936 98,788
--------- ---------
Deferred debits
Unamortized debt expense and reacquisition premiums 3,251 3,737
Regulatory assets 4,111 3,774
Other 1,580 3,371
--------- ---------
Total deferred debits 8,942 10,882
--------- ---------
Total $ 680,788 $ 655,612
========= =========
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Balance Sheets, December 31 1999 1998
- -------------------------------------------------------------------------------------------------
(in thousands)
Liabilities and Equity
Capitalization (page 33)
<S> <C> <S><C> <S> <C> <S><C> <S> <C> <C> <C>
Common shares, par value $5 per share -- authorized, 50,000,000 shares;
outstanding, 1999 -- 23,849,974 shares; 1998 -- 11,879,504 shares * $ 119,250 $ 59,398
Premium on common shares * - 39,919
Unearned compensation (301) -
Retained earnings * 126,744 125,462
Accumulated other comprehensive income - 297
--------- --------
Total common equity 245,693 225,076
Cumulative preferred shares 33,500 38,831
Long-term debt:
Electric utility 152,507 153,389
Diversified operations 23,930 27,657
--------- --------
Total capitalization 455,630 444,953
--------- --------
Current liabilities
Short-term debt - 824
Sinking fund requirements and current maturities 5,948 5,794
Accounts payable 39,343 32,411
Accrued salaries and wages 6,197 3,946
Federal and state income taxes accrued 8,153 2,192
Other taxes accrued 10,818 11,119
Interest accrued 3,266 3,120
Other 3,589 3,826
--------- --------
Total current liabilities 77,314 63,232
--------- --------
Noncurrent liabilities 26,514 22,842
--------- --------
Commitments (note 8) - -
--------- --------
Deferred credits
Accumulated deferred income taxes 87,972 90,964
Accumulated deferred investment tax credit 16,295 17,481
Regulatory liabilities 11,359 11,692
Other 5,704 4,448
--------- --------
Total deferred credits 121,330 124,585
--------- --------
Total $ 680,788 $ 655,612
========= =========
* 1999 amounts reflect the effect of stock split described in note 15.
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Statements of Income
For the Years Ended December 31 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------
(in thousands, except per-share amounts)
<S> <C> <C> <C>
Operating revenues
Electric $ 233,527 $ 227,477 $ 205,121
Manufacturing 93,411 87,434 83,174
Health services 69,312 69,412 66,859
Other business operations 68,327 48,829 44,173
--------- --------- ---------
Total operating revenues 464,577 433,152 399,327
Operating expenses
Production fuel 36,839 34,234 31,362
Purchased power 44,190 40,609 24,420
Electric operation and maintenance expenses 73,308 70,584 72,112
Special charges - 9,522 -
Cost of goods sold 172,079 146,996 137,945
Other nonelectric expenses 35,197 36,134 33,873
Depreciation and amortization 25,420 25,813 25,536
Property taxes 10,178 10,724 10,865
--------- --------- ---------
Total operating expenses 397,211 374,616 336,113
Operating income
Electric 47,234 42,216 44,966
Manufacturing 7,224 9,609 9,145
Health services 5,322 7,195 4,968
Other business operations 7,586 (484) 4,135
--------- --------- ---------
67,366 58,536 63,214
Gain from sale of radio station assets 14,469 - -
Other income and deductions -- net 1,828 2,871 1,959
Interest charges 14,771 15,566 18,519
--------- --------- ---------
Income before income taxes 68,892 45,841 46,654
Income taxes 23,915 15,140 14,308
--------- --------- ---------
Income before cumulative effect of change in accounting principle 44,977 30,701 32,346
Cumulative effect of change in accounting principle (net-of-tax of $2,545) - 3,819 -
--------- --------- ---------
Net income 44,977 34,520 32,346
Preferred dividend requirements 2,228 2,358 2,358
--------- --------- ---------
Earnings available for common shares $ 42,749 $ 32,162 $ 29,988
========= ========= =========
Average number of common shares outstanding * 23,831 23,596 23,277
Basic and diluted earnings per share *
Income before cumulative effect of change in accounting principle $1.79 $1.20 $1.29
Cumulative effect of change in accounting principle - 0.16 -
--------- --------- ---------
Basic and diluted earnings per share $1.79 $1.36 $1.29
Dividends per common share * $0.99 $0.96 $0.93
* Common shares outstanding and per-share data reflect the effect of the stock split described in note 15.
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Statements of Changes in Common Shareholders' Equity
- -----------------------------------------------------------------------------------------------------------------------------------
Accumulated
Common Par value, Premium on other
shares common common Unearned Retained comprehensive Total
outstanding shares shares compensation earnings income equity
------------ -----------------------------------------------------------
(in thousands, except common shares outstanding)
<S> <C> <C> <C> <C> <C> <C> <C> <S> <C> <C> <C> <C>
Balance, December 31, 1996 11,536,056 $ 57,680 $ 29,885 $ - $107,864 $ 619 $196,048
Cash portion of Peoples pooling transaction, January 1, 1997 (209) (209)
Common stock issuances 195,022 975 5,520 6,495
Comprehensive income:
Net income 32,346 32,346
Unrealized gains on available-for-sale securities 103 103
Reversal of previously recorded unrealized gains
on available-for-sale securities sold (359) (359)
-------
Total comprehensive income 32,090
Cumulative preferred dividends at required annual rates (2,358) (2,358)
Common dividends (21,496) (21,496)
Distributions by pooled entities (414) (414)
------------ -----------------------------------------------------------
Balance, December 31, 1997 11,731,078 $ 58,655 $ 35,196 $ - $115,942 $ 363 $210,156
Common stock issuances 148,426 743 4,723 5,466
Comprehensive income:
Net income 34,520 34,520
Unrealized loss on available-for-sale securities (66) (66)
-------
Total comprehensive income 34,454
Cumulative preferred dividends at required annual rates (2,358) (2,358)
Common dividends (22,642) (22,642)
------------ -----------------------------------------------------------
Balance, December 31, 1998 11,879,504 $ 59,398 $39,919 $ - $125,462 $ 297 $225,076
Common stock issuances 45,768 228 1,541 1,769
Common stock retired (285) (1) (1) (10) (12)
Unearned compensation - stock options 301 (301) -
Comprehensive income:
Net income 44,977 44,977
Reversal of previously recorded unrealized gains
on available-for-sale securities sold (297) (297)
-------
Total comprehensive income 44,680
Cumulative preferred dividends at required annual rates (2,266) (2,266)
Common dividends (23,554) (23,554)
Two-for-one stock split - March 15, 2000 11,924,987 59,625 (41,760) (17,865) -
------------ -----------------------------------------------------------
Balance, December 31, 1999 23,849,974 $119,250 $ - $ (301) $126,744 $ - $245,693
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Statements of Cash Flows
For the Years Ended December 31 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Cash flows from operating activities
Net income $44,977 $34,520 $ 32,346
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 34,796 34,965 39,302
Deferred investment tax credit--net (1,186) (1,186) (1,186)
Deferred income taxes (3,816) (6,253) (3,155)
Change in deferred debits and other assets (484) 99 1,204
Change in noncurrent liabilities and deferred credits 4,902 2,129 1,960
Allowance for equity (other) funds used during construction (246) (103) -
Gain on sale of radio station assets (14,469) - -
Loss/(Gain) on investments in and disposal of noncurrent assets 14 607 (1,722)
Voluntary early retirement program charges - 6,305 -
Cumulative effect of change in accounting principle - (3,819) -
Asset impairment losses - 3,217 -
Cash provided by (used for) current assets and current liabilities:
Change in receivables, materials, and supplies (1,761) (5,765) (2,270)
Change in other current assets 1,956 (2,962) 1,752
Change in payables and other current liabilities 7,536 2,804 908
Change in interest and income taxes payable 6,106 (599) 259
------- ------- -------
Net cash provided by operating activities 78,325 63,959 69,398
------- ------- -------
Cash flows from investing activities
Gross capital expenditures (32,679) (29,289) (41,973)
Proceeds from sale of radio station assets 24,063 - -
Proceeds from disposal of noncurrent assets 1,930 3,359 20,802
Proceeds from the sales of marketable securities - - 785
Acquisitions--net of cash acquired (16,000) (1,372) -
Change in other investments (9) (1,585) (470)
------- ------- -------
Net cash used in investing activities (22,695) (28,887) (20,856)
------- ------- -------
Cash flows from financing activities
Change in short-term debt--net issuances (824) (1,276) (23,500)
Proceeds from issuance of long-term debt 13,049 1,559 178,272
Proceeds from issuance of common stock 1,769 5,466 6,286
Payments for debt and common stock issuance expense - (82) (244)
Payments for retirement of common stock (12) - -
Redemption of preferred stock (5,331) - -
Payments for retirement of long-term debt (17,618) (17,121) (181,917)
Dividends paid (25,820) (25,000) (24,268)
------- ------- -------
Net cash used in financing activities (34,787) (36,454) (45,371)
------- ------- -------
Net change in cash and cash equivalents 20,843 (1,382) 3,171
Cash and cash equivalents at beginning of year 3,919 5,301 2,130
------- ------- -------
Cash and cash equivalents at end of year $24,762 $ 3,919 $ 5,301
======= ======= ========
Supplemental disclosures of cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $14,004 $15,189 $ 18,203
Income taxes $23,077 $22,966 $ 18,057
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
Otter Tail Power Company
- ------------------------
Consolidated Statements of Capitalization, December 31 1999 1998
- -------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Total common shareholders' equity $ 245,693 $ 225,076
--------- ---------
Cumulative preferred shares -- without par value (stated and
liquidating value $100 a share) -- authorized 1,500,000 shares;
outstanding:
Series subject to mandatory redemption:
$6.35, 180,000 shares; 9,000 shares due 2002-06;
135,000 shares due 2007 18,000 18,000
--------- ---------
Other series:
$3.60, 60,000 shares 6,000 6,000
$4.40, 25,000 shares 2,500 2,500
$4.65, 30,000 shares 3,000 3,000
$6.75, 40,000 shares 4,000 4,000
$9.00, 1999 - 0 shares; 1998 - 53,311 shares - 5,331
--------- ---------
Total other preferred 15,500 20,831
--------- ---------
Cumulative preference shares -- without par value, authorized
1,000,000 shares; outstanding: none
Long-term debt
First mortgage bond series:
7.25%, due August 1, 2002 18,600 18,800
8.75%, due September 15, 2021 18,400 18,600
8.25%, due August 1, 2022 27,900 28,200
Pollution control series:
6.40-6.80%, due February 1, 2006, Big Stone project 5,247 5,307
6.40-6.90%, due February 1, 2019, Coyote project 21,029 21,264
--------- ---------
Total first mortgage bond series 91,176 92,171
Senior debentures 6.375%, due December 1, 2007 50,000 50,000
Industrial development refunding revenue bonds
5.00% due December 1, 2002 3,010 3,010
Pollution control refunding revenue bonds
variable 5.50% at December 31, 1999, due December 1, 2012 10,400 10,400
Obligations of Varistar Corporation:
7.80% ten-year term note, due October 31, 2007 14,271 18,169
Various at 1.9% to 7.5% at December 31, 1999 13,521 14,281
Obligations of Otter Tail Energy Services Company
8.75% ten-year term note, due April 11, 2008 1,085 -
Other 6 6
--------- ---------
Total 183,469 188,037
Less:
Current maturity 4,953 4,799
Sinking fund requirement 995 995
Unamortized debt discount and premium -- net 1,084 1,197
--------- ---------
Total long-term debt 176,437 181,046
--------- ---------
Total capitalization $ 455,630 $ 444,953
========= =========
See accompanying notes to consolidated financial statements.
</TABLE>
Otter Tail Power Company
Notes to consolidated financial statements
For the three years ended December 31, 1999
(All common share amounts and per-share data reflect the effect of the stock
split described in note 15.)
1. Summary of accounting policies
System of accounts--For regulatory reporting purposes, the electric
utility's internal system of accounts are translated into the accounts of
the Uniform System of Accounts prescribed by the Federal Energy
Regulatory Commission (FERC), the Public Service Commission of North
Dakota, and the Public Utilities Commissions of Minnesota and South
Dakota.
Principles of consolidation--The consolidated financial statements
include the accounts of the Company and all wholly owned subsidiaries.
Profits on sales between nonregulated affiliates and from the regulated
electric utility company to nonregulated affiliates are eliminated.
However, profits on sales to the regulated electric utility company
from nonregulated affiliates are not eliminated, in accordance with the
requirements of Statement of Financial Accounting Standards (SFAS) No.
71 - Accounting for the Effects of Certain Types of Regulation.
Plant, retirements, and depreciation--Utility plant is stated at original
cost. The cost of additions includes contracted work, direct labor and
materials, allocable overheads, and allowance for funds used during
construction. The cost of depreciable units of property retired plus
removal costs less salvage is charged to the accumulated provision for
depreciation. Maintenance, repairs, and replacement of minor items of
property are charged to operating expenses. The provisions for utility
depreciation for financial reporting purposes are made on the straight-
line method based on the estimated service lives of the properties.
Such provisions as a percent of the average balance of depreciable
electric utility property were 3.06 percent in 1999, 3.12 percent in
1998, and 3.08 percent in 1997.
Property and equipment of nonutility and diversified operations are
carried at historical cost, or at the current appraised value if acquired
in a business combination accounted for under the purchase method of
accounting, and are depreciated on a straight-line basis over the useful
lives (3 to 40 years) of the related assets. On sale or retirement of
property and equipment, the cost and related accumulated depreciation
are eliminated from the respective accounts and the resulting gain or
loss is included in the consolidated financial statements.
Jointly owned plants--The consolidated financial statements include the
Company's 53.9 percent and 35 percent ownership interests in the assets,
liabilities, revenue, and expenses of Big Stone Plant and Coyote Station,
respectively. Amounts at December 31, 1999 and 1998 included in electric
plant in service for Big Stone were $111,722,000 and $111,754,000,
respectively, and the accumulated provision for depreciation and
amortization was $66,734,000 and $63,635,000, respectively. Amounts at
December 31, 1999 and 1998 included in electric plant in service for
Coyote were $146,163,000 and $145,899,000, respectively, and the
accumulated provision for depreciation and amortization was $67,289,000
and $63,463,000, respectively. The Company's share of direct revenue
and expenses of the jointly owned plants in service is included in the
corresponding operating revenue and expenses in the statement of income.
Allowance for funds used during construction (AFC)--AFC, a noncash item,
is included in construction work in progress. The rate for AFC was 10.00
percent for 1999, 10.25 percent for 1998, and 5.67 percent for 1997.
Recoverability of long-lived assets--The Company reviews its long-lived
assets whenever events or changes in circumstances indicate the carrying
amount of the assets may not be recoverable. The Company determines
potential impairment by comparing the carrying value of the assets with
net cash flows expected to be provided by operating activities of the
business or related assets. Should the sum of the expected future net
cash flows be less than the carrying values, the Company would determine
whether an impairment loss should be recognized. An impairment loss
would be quantified by comparing the amount by which the carrying
value exceeds the fair value of the asset where fair value is based on
the discounted cash flows expected to be generated by the asset.
Income taxes--Comprehensive interperiod income tax allocation is used for
substantially all book and tax temporary differences. Deferred income
taxes arise for all temporary differences between the book and tax basis
of assets and liabilities. Deferred taxes are recorded using the tax
rates scheduled by tax law to be in effect when the temporary differences
reverse. The Company amortizes the investment tax credit over the
estimated lives of the related property.
Operating revenues--Electric customers' meters are read and bills are
rendered on a cycle basis. In the first quarter of 1998, the Company
changed its method of revenue recognition in the states of Minnesota
and South Dakota from meter-reading dates to energy-delivery dates,
resulting in the accrual of estimated unbilled revenue from sales of
electricity through the end of the accounting period. This change is
consistent with the way the Company has been recording electric revenue
from its North Dakota customers since 1993 under an order from the North
Dakota Public Service Commission. See note 2 for the cumulative effect
of recording Minnesota and South Dakota unbilled revenue as of
January 1, 1998.
The Company's rate schedules applicable to substantially all customers
include a cost of energy adjustment clause under which the rates are
adjusted to reflect changes in average cost of fuels and purchased power
and a surcharge for recovery of conservation-related expenses. (See
further discussion under note 5.)
Health services' operating revenues on major equipment and installation
contracts are recorded using the percentage-of-completion method. Amounts
received in advance under customer service contracts are deferred and
recognized on a straight-line basis over the contract period. Revenues
generated in the mobile imaging operations are recorded on a fee for
scan basis.
Manufacturing operating revenues are recorded when products are shipped,
when services are rendered, and on a percentage-of-completion basis for
construction type contracts.
Other business operations' operating revenues are recorded when services
are rendered or products are shipped. In the case of construction
contracts, the percentage-of-completion method is used.
Employee incentive plan--The Company has incentive plans covering
employees that are based on certain performance measures. Total amounts
of accrued compensation for these incentive plans in 1999, 1998, and
1997 were $5,671,000, $3,083,000, and $3,826,000, respectively.
Stock-based compensation--As described in note 6, the Company has elected
to follow the accounting provisions of Accounting Principle Board Opinion
No. 25 (APB 25), Accounting for Stock Issued to Employees, for stock-
based compensation and to furnish the pro forma disclosures required
under SFAS No. 123, Accounting for Stock-Based Compensation.
Use of estimates--In recording transactions and balances resulting from
business operations, the Company uses estimates based on the best
information available. Estimates are used for such items as depreciable
lives, tax provisions, collectability of trade accounts receivable,
workers' compensation claims, self insurance programs, injuries and
damages reserve, environmental liabilities, unbilled revenues, service
contract maintenance costs and actuarially determined benefit costs.
As better information becomes available (or actual amounts are
determinable) the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting
estimates.
Reclassifications--Certain prior year amounts have been reclassified to
conform to 1999 presentation. Such reclassification had no impact on net
income and shareholders' equity. In addition, all financial information
pertaining to per-share amounts and number of common shares outstanding
has been adjusted to reflect a two-for-one stock split effective March
15, 2000, for shareholders of record on February 15, 2000.
Cash equivalents--The Company considers all highly liquid debt instruments
purchased with a maturity of 90 days or less to be cash equivalents.
Debt reacquisition premiums--In accordance with regulatory treatment, the
Company defers utility debt redemption premiums and amortizes such costs
over the original life of the reacquired bonds.
Investments--At December 31, 1999 and 1998, the Company had noncurrent
investments of $7,219,000 and $7,540,000, respectively, in limited
partnerships that invest in tax-credit qualifying affordable housing
projects. These investments, accounted for under the equity method,
provided the Company with tax credits of $1,393,000 and $1,330,000, in
1999 and 1998, respectively. At December 31, 1999 the Company did not
have any investments in marketable equity securities classified as
available-for-sale. At December 31, 1998, the Company had $590,000
invested in marketable equity securities classified as available-
for-sale and recorded at market value. The balance of investments at
December 31, 1999 consists of $2,013,000 in additional investments
accounted for under the equity method, and $10,270,000 in other
investments accounted for under the cost method, with $1,424,000 related
to participation in economic development loan pools. The balance of
investments at December 31, 1998 consists of $1,911,000 in additional
investments accounted for under the equity method, and $10,571,000 in
other investments accounted for under the cost method, with $1,515,000
related to participation in economic development loan pools. (See further
discussion under note 12.)
Inventories--The electric operation inventories are reported at average
cost. The health service, manufacturing, and other business operation
inventories are stated at the lower of cost (first-in, first-out) or
market.
Short-term debt--There was no short-term debt outstanding as of December
31, 1999. The composite interest rate on short-term debt outstanding as
of December 31, 1998, was 8.75 percent. The average interest rate paid
on short-term debt during 1999 and 1998 was 8.75 percent and 6.65
percent, respectively.
Intangible assets--The majority of the Company's intangible assets
consist of goodwill associated with the acquisition of subsidiaries.
Intangible assets are amortized on a straight-line basis over periods of
40 years for the telephone company and 15 years or less for all other
intangibles. The Company periodically evaluates the recovery of
intangible assets based on an analysis of undiscounted future cash flows.
Total intangibles as of December 31 are as follows:
1999 1998
-------- --------
(in thousands)
Goodwill on telephone company $ 7,749 $ 7,749
Other intangible assets 23,428 21,808
------- -------
Total 31,177 29,557
Less accumulated amortization 7,866 8,381
------- -------
Intangibles-net $23,311 $21,176
======= =======
Adoption of new accounting pronouncements--In 1998 the Company adopted
Statement of Financial Accounting Standards (SFAS) 131 - Disclosures
about Segments of an Enterprise and Related Information. SFAS 131
supersedes SFAS 14, Financial Reporting for Segments of a Business
Enterprise, replacing the "industry segment" approach with the
"management" approach. The management approach designates the internal
organization that is used by management for making operating decisions
and assessing performance as the source of the Company's reportable
segments. SFAS 131 also requires disclosures about products and
services, geographic areas, and major customers. The adoption of SFAS
131 did not change the Company's reportable segments or affect results
of operations or financial position.
In February 1998 the Financial Accounting Standards Board (FASB) issued
SFAS 132 - Employers' Disclosures about Pensions and Other Postretirement
Benefits, which was effective for the Company on January 1, 1998. SFAS
132 revises employers' disclosures about pension and other postretirement
benefit plans. The adoption of SFAS 132 did not affect the Company's 1998
results of operations or financial position. Note 10 reflects the
adoption of SFAS 132.
New accounting pronouncement--In June 1998 the FASB issued Statement of
Financial Accounting Standards (SFAS) 133 - Accounting for Derivative
Instruments and Hedging Activities, effective for financial statements
issued for periods beginning after June 15, 1999. In June 1999 the FASB
issued SFAS 137 which delayed the effective date for SFAS 133 to periods
beginning after June 15, 2000. SFAS 133 establishes accounting and
reporting standards for derivative instruments and for hedging
activities. It requires that all derivatives be recognized as either
assets or liabilities and that those financial instruments be measured at
fair value. The accounting for changes in the fair value of a derivative
depends on the intended use of the derivative. The adoption of this
statement is not expected to have a material impact on the Company's
financial position as presently reported.
2. Change in accounting principle
Effective January 1, 1998 the Company changed its method of revenue
recognition in the states of Minnesota and South Dakota from meter-
reading dates to energy-delivery dates, resulting in the accrual of
estimated unbilled revenue from sales of electricity through the end of
the accounting period. This change is consistent with the way the
Company has been recording electric revenue from its North Dakota
customers since 1993 under an order from the North Dakota Public
Service Commission. The cumulative effect of recording Minnesota and
South Dakota unbilled revenue as of January 1, 1998, increased 1998 net
income by $3,819,000 (net of income taxes of $2,545,000) or $0.16 per
share. The effect on 1998 income of this accounting change, not
including the cumulative effect, was an increase in net income of
approximately $193,000 or $0.01 per share.
If the Company had been recording Minnesota and South Dakota unbilled
revenue in previous accounting periods, its reported electric revenue for
1997 would have been $203,778,000 and its reported net income would have
been $31,540,000 or $1.25 per share for 1997.
3. Special charges
In January 1998 the Company offered a voluntary early retirement program
for all nonunion electric utility employees age 55 and over. Most of the
cash costs of the program will be funded through the Company's pension
plan. The Company recorded a noncash charge to operating expenses of
$6,305,000 ($3,783,000 net-of-tax or $0.16 per share) in 1998 for special
termination benefits and the recognition of previously unrecognized prior
service costs related to pension and postretirement benefits.
In March 1998 the Company recorded a noncash accounting charge related to
the impairment of its Quadrant Co. (Quadrant) waste incineration plant.
The impaired assets include buildings, machinery, and equipment used to
burn waste. The revised carrying value of this group of assets was
determined to be zero, which was calculated on the basis of discounted
estimated future cash flows. The pre-tax noncash charge of $2,500,000
($1,500,000 net-of-tax or $0.06 per share) pertaining to the write down
included $248,000 for selling or disposal costs all of which was used
toward the disposition of the plant. The recognition of this impairment
is in accordance with the provisions of Statement of Financial
Accounting Standards No. 121 - Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of. The $2,500,000
impairment loss was included in operating expenses under the caption of
special charges and in operating income from other business operations on
the Company's Statement of Income for the year ended December 31, 1998.
In August 1999 the assets of the Quadrant plant were donated to the City
of Perham, Minnesota.
In the first quarter of 1998, as a result of an unfavorable court decision
related to the construction of a rail spur intended to serve Big Stone
Plant, the Company wrote off $717,000 ($430,000 net-of-tax or $0.02 per
share) in capitalized project related costs.
4. Business combinations, dispositions and segment information
As discussed in note 3 above, during August 1999, the assets of the
Quadrant plant were donated to the City of Perham, Minnesota.
On September 1, 1999 the Company acquired the flatbed trucking operations
of E. W. Wylie Corporation (Wylie). Wylie's annual revenues range from
$18 to $19 million. The acquisition was accounted for using the purchase
method of accounting. The excess of the purchase price over net assets
acquired of approximately $8 million is being amortized over 15 years.
Wylie is located in Fargo, North Dakota and operates in 48 states and 6
Canadian provinces. The pro forma effect of the Wylie acquisition on
1999, 1998 and 1997 revenue, net income, or earnings per share was not
significant.
On October 1, 1999 the Company completed the sale of certain assets of
the radio stations and video production company owned by KFGO, Inc. and
the radio stations owned by Western Minnesota Broadcasting Company for
$24.1 million. The gain after income tax was $8.1 million or $0.34 cents
per share.
Pro forma operating income for other business operations without Quadrant
and the radio stations would have been $6,303,000 $1,543,000 and
$3,953,000 in 1999, 1998, and 1997 respectively.
On May 1, 1998 the Company acquired PAM Natural Gas, Inc. (PAM) for
approximately $1.8 million in stock purchased on the open market. PAM is
a Sioux Falls, South Dakota-based marketer of natural gas to commercial
and institutional customers in Iowa, South Dakota, North Dakota and
Minnesota. Upon acquisition PAM's name was changed to Otter Tail Energy
Management Company. The PAM acquisition was accounted for under the
purchase method. The pro forma effect of the PAM acquisition on 1998
and 1997 revenue, net income, or earnings per share was not significant.
Effective November 1998 Mid-States Development, Inc., a subsidiary of the
Company since 1989, changed its name to Varistar Corporation (Varistar).
On January 1, 1999 the Company's telecommunications subsidiary, North
Central Utilities, Inc. (NCU) merged with Varistar. Subsidiaries
previously owned by NCU became wholly owned subsidiaries of Varistar.
Segment information--The accounting policies of the segments are the same
as those described in the note 1 - Summary of accounting policies. The
Company's business operations are broken down into four segments based on
products and services. Electric operations includes the electric utility
only and is based in Minnesota, North Dakota, and South Dakota.
Manufacturing operations is made up of businesses involved in the
production of polyvinyl chloride pipe, agricultural equipment, frame-
straightening equipment and accessories for the auto body shop industry,
contract machining, and metal parts stamping and fabrication located
primarily in the Upper Midwest. Health services operations consists of
businesses involved in the sale, service, rental, refurbishing and
operations of medical imaging equipment and the sale of related supplies
and accessories to various medical institutions located in 23 states.
Other business operations consists of businesses diversified in such
areas as electrical and telephone construction contracting, transporta-
tion, telecommunications, entertainment, and energy services and natural
gas marketing. The electrical and telephone construction contracting
companies, and energy services and natural gas marketing business
operate primarily in the Upper Midwest. The telecommunications companies
operate in central and northeast Minnesota and the transportation company
operates in 48 states and 6 Canadian provinces. The Company evaluates
the performance of its business segments and allocates resources to them
based on earnings contribution and return on investment. Information for
the business segments for 1999, 1998 and 1997 is presented in the table
below.
1999 1998 1997
-------- -------- --------
(in thousands)
Operating revenue
Electric $233,527 $227,477 $205,121
Manufacturing 93,411 87,434 83,174
Health services 69,312 69,412 66,859
Other business operations 68,327 48,829 44,173
-------- -------- --------
Total $464,577 $433,152 $399,327
Operating income
Electric $ 47,234 $ 42,216 $ 44,966
Manufacturing 7,224 9,609 9,145
Health services 5,322 7,195 4,968
Other business operations 7,586 (484) 4,135
-------- -------- --------
Total $ 67,366 $ 58,536 $ 63,214
Depreciation and amortization
Electric $ 21,782 $ 22,128 $ 21,442
Manufacturing 562 510 542
Health services 499 541 638
Other business operations 2,577 2,634 2,914
-------- -------- --------
Total $ 25,420 $ 25,813 $ 25,536
Capital expenditures
Electric $ 20,136 $ 17,939 $ 26,603
Manufacturing 6,903 5,536 6,264
Health services 993 3,101 3,800
Other business operations 4,647 2,713 5,306
-------- -------- --------
Total $ 32,679 $ 29,289 $ 41,973
Identifiable assets
Electric $524,012 $525,226 $526,679
Manufacturing 46,832 41,579 40,814
Health services 29,542 36,241 35,738
Other business operations 80,402 52,566 52,210
-------- -------- --------
Total $680,788 $655,612 $655,441
No single external customer accounts for 10 percent or more of the
Company's revenues. Substantially all sales and long-lived assets of
the Company are within the United States.
5. Rate matters
On October 6, 1999, the NDPSC approved a settlement agreement following
an audit of the Company's electric operations in North Dakota. The
effect of this settlement decreased 1999 earnings by approximately
$441,000 after taxes or $0.02 per share. In addition as part of the
settlement agreement, the Company filed a proposal for a performance-
based ratemaking plan in 2000 and is required to refund to North Dakota
customers any 1999 regulated electric operations earnings from North
Dakota over a 12.5% return on equity. While the final decision on any
potential refund relating to 1999 results lies with the NDPSC, the
Company expects that any refund will not be significant.
On July 1, 1995, the Company began charging all Minnesota customers a
.5030 percent surcharge on their electric service statements for recovery
of conservation-related costs exceeding the amount already included in
base rates. On July 1, 1996, the rate was increased to 1.25 percent, on
July 1, 1997, the rate was increased to 1.75 percent, on July 1, 1998,
the rate was increased to 2.75 percent and on July 1, 1999, the rate was
decreased to 1.5 percent. The conservation-related costs being recovered
through the surcharge and in base rates include Conservation Improvement
Program (CIP) expenditures, carrying charges on costs incurred in excess
of costs currently being recovered, lost margins on avoided kilowatt-hour
sales, and bonus incentives related to energy savings. The MPUC approved
recovery of 1998, 1997, and 1996 lost margins and bonus incentives in
1999, 1998, and 1997, respectively. The Company recorded revenues related
to 1998, 1997, and 1996 lost margins and financial incentives of
$1,829,000, $1,931,000, and $1,266,000, respectively. As these costs are
recovered through the monthly billing process, the amounts billed are
offset by the amortization of deferred CIP charges. The Company did not
record any estimated financial incentives for 1999.
6. Common shares
Stock incentive plan--During 1999, the Company's shareholders approved
the 1999 Stock Incentive Plan (Incentive Plan). Under the Incentive Plan
a total of 2,600,000 common shares are available for granting of stock
awards. The Incentive Plan provides for the grant of options, performance
awards, restricted stock, stock appreciation rights and other types of
stock grants or stock-based awards. In 1999, the Company granted
approximately 450,700 stock options and 2,298 shares of restricted stock
under the Incentive Plan. The exercise price of the stock options is
equal to the fair market value per share at the date of the grant. The
options vest over a four-year period at the rate of 25 percent per year
and will expire ten years after the date of the grant. Presented below
is a summary of the stock options activity for 1999. No stock options
were granted prior to 1999.
Balance, December 31, 1998 --
Granted 450,700
Forfeited (7,800)
-------
Balance, December 31, 1999 442,900
The Company accounts for the Incentive Plan under APB 25. Unearned
compensation relating to the options granted in 1999 is $301,000 at
December 31, 1999, and is included as a reduction of common equity.
Since none of the options had vested as of December 31, 1999, no
compensation expense occurred under SFAS No. 123 and there was no
impact on the Company's net income and earnings per share.
The fair value of each option grant is estimated on the date of grant
using the Black Scholes option pricing model with the following
weighted-average assumptions used to the grant
Risk free interest rate 5.2%
Expected dividend yield 5.0%
Expected life 7 years
Expected volatility 19.29%
Weighted average fair value $2.79
The effect of the stock options on the computation of diluted earnings
per share was immaterial for 1999.
Employee stock purchase plan--During 1999, the shareholders approved the
Company's 1999 Employee Stock Purchase Plan (Purchase Plan). The
Purchase Plan allows eligible employees to purchase the Company's common
shares at 85 percent of the lower market price at either the beginning or
the end of each six-month purchase period. A total of 400,000 common
shares is available for purchase by employees under the Purchase Plan.
For 1999 there was only one purchase period that was in effect from May 1
through December 31, 1999. During January 2000, 24,080 shares were
purchased from the open market for the Purchase Plan. The purchase price
per share paid by the employees was $15.96. The average price paid by
the Company to purchase these shares was $19.36.
Dividend reinvestment and share purchase plan--On August 30, 1996, the
Company filed a shelf registration statement with the Securities and
Exchange Commission for the issuance of up to 2,000,000 common shares
pursuant to the Company's Automatic Dividend Reinvestment and Share
Purchase Plan (the Plan), which permits shares purchased by shareholders,
or customers who participate in the Plan to be either new issue common
shares or common shares purchased on the open market. In June 1999, the
Company began purchasing the common shares needed for this Plan from the
open market instead of issuing new shares. Prior to this the Company
had been issuing newly issued common shares: 89,238 shares were issued
in 1999, 296,852 shares were issued in 1998, and 323,662 shares were
issued in 1997.
Shareholder rights plan--On January 27, 1997, the Company's Board of
Directors declared a dividend of one preferred share purchase right
(Right) for each outstanding common share held of record as of February
10, 1997. One Right was also issued with respect to each common share
issued after February 10, 1997. Each Right entitles the holder to
purchase from the Company one one-hundredth of a share of newly created
Series A Junior Participating Preferred Stock at a price of $70, subject
to certain adjustment. The Rights are exercisable when, and are not
transferable apart from the Company's common shares until, a person or
group has acquired 15 percent or more, or commenced a tender or exchange
offer for 15 percent or more, of the Company's common shares. If the
specified percentage of the Company's common shares is acquired, each
Right will entitle the holder (other than the acquiring person or group)
to receive, upon exercise, common shares of either the Company or the
acquiring company having value equal to two times the exercise price of
the Right. The Rights are redeemable by the Company's Board of
Directors in certain circumstances and expire on January 27, 2007.
7. Retained earnings restriction
The Company's Indenture of Mortgage and Articles of Incorporation, as
amended, contain provisions that limit the amount of dividends that may
be paid to common shareholders. Under the most restrictive of these
provisions, retained earnings at December 31, 1999, were restricted by
$9,667,000.
8. Commitments
At December 31, 1999, the electric utility had commitments under
contracts in connection with construction programs aggregating
approximately $4,211,000. For capacity and energy requirements the
electric utility has agreements extending through 2004, at annual costs
of approximately $10,977,000 in 2000, $12,591,000 in 2001, $12,791,000
in 2002, $11,197,000 in 2003, and $11,411,000 in 2004.
The electric utility also has several long-term coal contracts in which
it is responsible for making payment only upon the delivery of the coal.
The risk of loss from nonperformance of the contracts is considered
nominal because of the availability of other suppliers and the expected
continued reliability of the current fuel suppliers. Furthermore, the
cost of energy adjustment provision in the rate-making process lessens
the risk of loss (in the form of increased costs) from market price
changes because it assures recovery of almost all fuel costs.
In 1999, the Company entered into a 5-year operating lease for 120
used hopper rail cars for transporting coal to the Hoot Lake Plant.
These cars began transporting coal to the Hoot Lake Plant in July 1999.
In November 1997 Varistar's medical imaging services subsidiary entered
into a sale/leaseback transaction whereby $16,000,000 of diagnostic
medical equipment was sold and leased back under two operating leases
with terms of three and four years. The amounts of future operating
lease payments are as follows:
Electric Diversified
utility companies Total
-------- ----------- -------
(in thousands)
2000 $1,362 $12,106 $13,468
2001 1,299 10,242 11,541
2002 1,299 6,333 7,632
2003 1,299 3,507 4,806
2004 1,072 175 1,247
Later years 2,885 -- 2,885
Rent expense was $14,233,000, $13,016,000, and $6,714,000 for 1999,
1998, and 1997, respectively.
9. Long-term obligations
Preferred shares--The $6.35 cumulative preferred shares are redeemable in
whole or in part at the option of the Company after December 1, 1999, at
$101.905, declining linearly to $100.00 at December 31, 2002. The
aggregate requirement of cumulative preferred shares subject to mandatory
redemption outstanding at December 31, 1999 for the next five years is
$900,000 each year for 2002-2004.
During 1999, the Company redeemed all of its outstanding $9.00
exchangeable cumulative preferred stock at par in an exchange for 227,952
shares of common stock, purchased on the open market, and $547,000 in
cash.
Long-term debt--All utility property, with certain minor exceptions, is
subject to the lien of the Indenture of Mortgage of the Company securing
its First Mortgage Bonds. The Company is required by the Indenture to
make annual payments (exclusive of redemption premiums) for sinking fund
purposes, except that the requirement with respect to certain series may
be satisfied by the delivery of bonds of such series of equal principal
amount. The Company issued First Mortgage Bonds of its pollution control
series to secure payment of a like principal amount of revenue bonds that
were issued by local governmental units to finance facilities leased or
purchased and that the Company has capitalized. Varistar's ten-year
term note and credit line borrowings are secured by a pledge of all of
the common stock of the companies owned by Varistar. The aggregate
amounts of maturities and sinking fund requirements on bonds outstanding
and other long-term obligations at December 31, 1999, for each of the
next five years are $5,947,000 for 2000, $5,611,000 for 2001, $26,231,000
for 2002, $4,700,000 for 2003, and $4,697,000 for 2004.
10. Pension plan and other postretirement benefits
The utility company's noncontributory funded pension plan covers
substantially all electric utility employees. The plan provides 100
percent vesting after 5 vesting years of service and for retirement
compensation at age 65, with reduced compensation in cases of retirement
prior to age 62. The utility company reserves the right to discontinue
the plan, but no change or discontinuance may affect the pensions
theretofore vested. The utility company's policy is to fund
pension costs accrued. All past service costs have been provided for.
The pension plan has a trustee who is responsible for pension payments to
retirees. Five investment managers are responsible for managing the
plan's assets. In addition, an independent actuary performs the
necessary actuarial valuations for the plan.
Net periodic pension cost for 1999, 1998, and 1997 includes the following
components:
1999 1998 1997
-------- -------- --------
(in thousands)
Service cost--benefit earned during the period $ 3,080 $ 2,319 $ 2,385
Interest cost on projected benefit obligation 8,150 7,823 7,131
Expected return on assets (12,159) (10,988) (9,036)
Amortization of transition asset (235) (235) (235)
Amortization of prior-service cost 1,287 1,069 980
Amortization of net gain (149) (344) (121)
------ ------ ------
Net periodic pension cost $ (26) $ (356) $1,104
1998 early retirement and curtailment -- 4,026 --
------ ------ ------
Total $ (26) $3,670 $1,104
====== ====== ======
The plan assets consist of common stock and bonds of public companies,
U.S. Government Securities, cash, and cash equivalents.
The following tables provide a reconciliation of the changes in the
plan's benefit obligations and fair value of assets over the two-year
period ending December 31, 1999 and a statement of the funded status
as of December 31 of both years:
1999 1998
-------- --------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $128,505 $107,357
Service cost 3,080 2,319
Interest cost 8,150 7,823
Actuarial (gain)/loss (18,025) 13,924
Benefit payments (7,265) (6,813)
1998 early retirement and curtailment -- 3,895
-------- --------
Obligation at December 31 $114,445 $128,505
======== ========
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 $150,026 $137,560
Actual return on plan assets 16,613 19,054
Pension purchase options rollovers 181 225
Benefit payments (7,265) (6,813)
-------- --------
Fair value of plan assets at December 31 $159,555 $150,026
======== ========
Funded status:
Funded status at December 31 $ 45,110 $ 21,521
Unrecognized transition asset (545) (780)
Unrecognized prior-service cost 11,461 9,393
Unrecognized net actuarial gain (57,040) (31,174)
-------- --------
Net amount recognized $ (1,014) $ (1,040)
======== ========
The following table provides the amounts recognized in the statement
of financial position as of December 31 of both years:
1999 1998
-------- --------
(in thousands)
Accrued benefit liability $ (1,014) $ (1,040)
The assumptions used for actuarial valuations were:
1999 1998
-------- --------
Discount rate 7.75% 6.50%
Rate of increase in future compensation level 4.25% 4.25%
Long-term rate of return on assets 9.50% 9.50%
In addition to providing pension benefits to all electric utility
employees, the Company has an unfunded, nonqualified benefit plan for
executive officers and certain key management employees. This plan
provides defined benefit payments to these employees on their retirements
or to their beneficiaries on their death for a 15-year period. Life
insurance carried on the plan participants is payable to the Company
upon the employee's death. There are no plan assets in this nonqualified
benefit plan due to the nature of the plan.
Net periodic pension cost for 1999, 1998, and 1997 includes the following
components:
1999 1998 1997
-------- -------- --------
(in thousands)
Service cost--benefit earned during the period $ (99) $ (88) $ (140)
Interest cost on projected benefit obligation 569 521 475
Amortization of transition obligation 17 18 20
Amortization of prior service cost 106 111 127
Recognized net actuarial loss 47 --- ---
------ ------ ------
Net periodic pension cost $ 640 $ 562 $ 482
1998 early retirement and curtailment -- 1,413 --
------ ------ ------
Total $ 640 $1,975 $ 482
====== ====== ======
The following tables provide a reconciliation of the changes in the
plan's benefit obligations over the two-year period ending December 31,
1999 and a statement of the funded status as of December 31 of both
years:
1999 1998
-------- --------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $ 9,071 $ 6,964
Service cost (99) (88)
Interest cost 569 521
Plan amendments 1,618 --
Actuarial (gain)/loss (318) 807
Benefit payments (429) (273)
1998 early retirement and curtailment -- 1,140
-------- --------
Obligation at December 31 $ 10,412 $ 9,071
======== ========
Funded status:
Funded status at December 31 $ (10,412) $ (9,071)
Unrecognized transition obligation 17 34
Unrecognized prior-service cost 2,785 1,273
Unrecognized net actuarial loss 1,057 1,422
-------- --------
Net amount recognized $ (6,553) $ (6,342)
======== ========
The following table provides the amounts recognized in the statement of
financial position as of December 31 of both years:
1999 1998
-------- --------
(in thousands)
Accrued benefit liability $ (8,486) $ (7,649)
Intangible asset 1,933 1,307
-------- --------
Net amount recognized $ (6,553) $ (6,342)
======== ========
The assumptions used for actuarial valuations were:
1999 1998
-------- --------
Discount rate 7.75% 6.50%
Rate of increase in future compensation level 4.00% 5.00%
In addition to providing pension benefits, the electric utility provides
a portion of health insurance benefits for retired electric utility
employees. Substantially all of the Company's electric utility employees
may become eligible for health insurance benefits if they reach age 55
and have 10 years of service. Upon adoption of SFAS 106 - Employers'
Accounting for Postretirement Benefits Other Than Pensions - in January
1993, the Company elected to recognize its transition obligation related
to postretirement benefits earned of approximately $14,964,000 over a
period of 20 years. There are no plan assets.
The net periodic postretirement benefit cost for 1999, 1998, and 1997
includes the following components:
1999 1998 1997
-------- -------- -------
(in thousands)
Service cost - benefit earned during the period $ 753 $ 563 $ 578
Interest cost on accumulated postretirement
benefit obligation 1,432 1,281 1,159
Amortization of transition obligation 748 748 748
Amortization of prior service cost 111 -- --
Amortization of net gain -- (209) (251)
------ ------ ------
Net periodic postretirement benefit cost $3,044 $2,383 $2,234
1998 early retirement and curtailment -- 954 --
------ ------ ------
Total $3,044 $3,337 $2,234
====== ====== ======
The following tables provide a reconciliation of the changes in the plan's
benefit obligations over the two-year period ending December 31, 1999 and
a statement of the funded status as of December 31 of both years:
1999 1998
-------- --------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $ 23,628 $ 17,707
Service cost 753 563
Interest cost 1,432 1,281
Actuarial (gain)/loss (4,444) 4,726
Benefit payments (1,555) (1,412)
Participant premium payments 437 492
1998 early retirement and curtailment -- 271
-------- --------
Obligation at December 31 $ 20,251 $ 23,628
======== ========
Funded status:
Funded status at December 31 $(20,251) $(23,628)
Unrecognized transition obligation 9,726 10,474
Unrecognized prior service cost 596 --
Unrecognized (gain) loss (4,348) 802
-------- --------
Net amount recognized $(14,277) $(12,352)
======== ========
The amounts recognized in the statement of financial position as of
December 31 of both years:
1999 1998
-------- --------
(in thousands)
Accrued benefit liability $(14,277) $(12,352)
The assumed health-care cost-trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 1999, was 7.0
percent for 2000, decreasing linearly each successive year until it
reaches 5.0 percent in 2003, after which it remains constant. The
assumed health-care cost-trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 1998, was 7.5
percent for 1999, decreasing linearly each successive year until it
reaches 5.0 percent in 2003, after which it remains constant. The
assumed discount rate used in determining the accumulated postretirement
benefit obligation as of December 31, 1999 and 1998, was 7.75 percent and
6.5 percent, respectively.
Assumed health-care cost-trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in
assumed health-care cost-trend rates for 1999 would have the following
effects:
1 percent 1 percent
increase decrease
--------- ---------
Effect on total of service and interest (in thousands)
cost components $ 399 $ (332)
Effect on the postretirement benefit obligation $ 1,637 $ (3,194)
The Company has a leveraged employee stock ownership plan (ESOP) for the
benefit of all its electric utility employees. Contributions made by the
Company were $1,110,000 for 1999, $1,078,000 for 1998, and $1,055,000 for
1997.
11. Compensating balances and short-term borrowings
The Company maintains formal bank lines of credit for its electric utility
operations separate from lines and letters of credit maintained by the
diversified companies. The lines of credit make available to the Company
bank loans for short-term financing and provide backup financing for
commercial paper notes. At December 31, 1999, the Company maintained no
compensating balances to support formal bank lines of credit. The
Company's bank lines of credit for electric utility operations totaled
$18,000,000, none of which was used at December 31, 1999. The diversified
companies' bank lines and letters of credit, which require no
compensating balances, totaled $14,725,000, none of which was used at
December 31, 1999.
12. Fair value of financial instruments
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:
Cash and short-term investments--The carrying amount approximates fair
value because of the short-term maturity of those instruments.
Other investments--The carrying amount approximates fair value. A
portion of other investments is in financial instruments that have
variable interest rates that reflect fair value. The remainder of
other investments is accounted for by the equity method which, in the
case of operating losses, results in a reduction of the carrying amount.
Redeemable preferred stock--The fair value is estimated based on the
current rates available to the Company for the issuance of redeemable
preferred stock.
Long-term debt--The fair value of the Company's long-term debt is
estimated based on the current rates available to the Company for the
issuance of debt. About $20 million of the Company's long-term debt,
which is subject to variable interest rates, approximates fair value.
<TABLE>
<CAPTION>
1999 1998
---------------------- ---------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
-------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Cash and short-term investments $ 24,762 $ 24,762 $ 3,919 $ 3,919
Other investments 19,502 19,502 20,612 20,612
Redeemable preferred stock (18,000) (17,650) (18,000) (19,252)
Long-term debt (176,437) (176,677) (181,046) (203,789)
</TABLE>
The Company's marketable securities are included in investments on the
balance sheet and are classified as available for sale. These securities
are recorded at fair value with any unrealized gain or loss included in
accumulated other comprehensive income in the equity section of the
balance sheet net of deferred income taxes of $210,000 at year-end 1998.
Realized gains and losses are computed on each specific investment sold.
The amounts recognized on the balance sheet as of December 31, 1999 and
1998, and amounts sold for each year are as follows:
1999 1998
-------- --------
Available for sale - securities (in thousands)
Cost $ -- $ 83
Gross unrealized gain -- 507
-------- -------
Fair value $ -- $ 590
======== =======
Proceeds from sale $ 1,566 $ --
Gross realized gains 1,483 --
13. Property, plant, and equipment 1999 1998
-------- --------
(December 31, in thousands)
Electric plant:
Production $309,761 $309,109
Transmission 151,581 143,822
Distribution 242,130 234,671
General 75,565 83,285
------- -------
Electric plant 779,037 770,887
Less accumulated depreciation and amortization 342,915 332,315
------- -------
Electric plant net of accumulated depreciation 436,122 438,572
Construction work in progress 10,979 10,495
------- -------
Net electric plant $447,101 $449,067
------- -------
Diversified operations plant $ 99,558 $ 89,094
Less accumulated depreciation and amortization 43,703 37,975
------- -------
Net diversified operations plant $ 55,855 $ 51,119
------- -------
Net plant $502,956 $500,186
======= =======
<TABLE>
<CAPTION>
14. Income taxes
The total income tax expense differs from the amount computed by applying the
federal income tax rate (35 percent in 1999, 1998 and 1997) to net income before
total income tax expense for the following reasons:
1999 1998 1997
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Tax computed at federal statutory rate $24,112 $18,272 $16,329
Increases (decreases) in tax from:
State income taxes net of federal income tax
benefit 2,607 2,665 2,224
Investment tax credit amortization (1,186) (1,186) (1,186)
Depreciation differences--flow-through
method reversal 82 1,133 408
Differences reversing in excess of federal rates (466) (1,639) (994)
Dividend received/paid deduction (667) (643) (620)
Affordable housing tax credits (1,393) (1,330) (1,057)
Permanent and other differences 826 413 (796)
------- ------- -------
Total income tax expense $23,915 $17,685 $14,308
======= ======= =======
Overall effective federal and state income tax rate 34.7% 33.9% 30.7%
Income tax expense includes the following:
Charges (credits) related to operations:
Current federal income taxes $25,823 $20,198 $17,123
Current state income taxes 5,182 4,182 3,300
Deferred federal income taxes (3,336) (4,085) (3,410)
Deferred state income taxes (450) (206) (205)
Investment tax credit amortization (1,186) (1,186) (1,186)
------- ------- -------
Total $26,033 $18,903 $15,622
Charges (credits) related to other income
and deductions:
Current federal income taxes (459) (280) (645)
Affordable housing tax credits (1,393) (1,330) (1,057)
Current state income taxes (145) (9) 19
Deferred federal and state income taxes (121) 401 369
------- ------- -------
Total income tax expense $23,915 $17,685 $14,308
======= ======= =======
</TABLE>
The Company's deferred tax assets and liabilities were composed of the
following on December 31, 1999 and 1998:
1999 1998
-------- --------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 10,601 $ 11,497
Vacation accrual 1,286 1,202
Unearned revenue 1,563 1,844
Operating reserves 11,093 10,026
Differences related to property 2,392 2,209
Transfer to regulatory asset -- 124
Transfer to regulatory liability 496 --
Other 1,353 991
-------- --------
Total deferred tax assets $ 28,784 $ 27,893
-------- --------
Deferred tax liabilities
Differences related to property (106,976) (108,968)
Transfer to regulatory asset (4,110) (3,744)
Other (2,547) (3,415)
-------- --------
Total deferred tax liabilities $(113,633) $(116,127)
-------- --------
Deferred income taxes $ (84,849) $ (88,234)
======== ========
15. Subsequent Events
Effective January 1, 2000, the Company through Varistar acquired the
assets and operations of Vinyltech Corporation (Vinyltech) located in
Phoenix, Arizona. Vinyltech is a manufacturer of PVC pipe and produces
approximately 90 million pounds of pipe annually. Annual revenues for
1999 were approximately $41 million. The acquisition will be accounted
for using the purchase method of accounting. The excess of the purchase
price over the net assets acquired of approximately $22 million will be
amortized over 15 years. Vinyltech sells PVC pipe in Arizona,
California, Nevada and other southwestern states.
On January 31, 2000, the Company's board of directors declared a
two-for-one common stock split to be effected in the form of a 100
percent stock dividend payable on March 15, 2000 to holders of record
on February 15, 2000. Accordingly, 1999 balances reflect the stock split
with an increase in common shares of $59,625,000 and reductions in
premium on common shares and retained earnings of $41,760,000 and
$17,865,000, respectively. All stock options, share and per-share data
has been restated to reflect the stock split.
<TABLE>
<CAPTION>
16. Quarterly information (unaudited)
Three Months Ended
March 31 June 30 September 30 December 31
-------------------- -------------------- -------------------- -------------------
1999 1998 1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- -------- -------- --------
(in thousands except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $111,485 $97,143 $112,397 $107,470 $123,619 $112,831 $117,076 $115,708
Operating income $ 17,688 $ 5,736 $ 14,604 $ 14,948 $ 18,861 $ 18,227 $ 16,213 $ 19,625
Income before cumulative effect
of change in accounting principle $ 9,249 $ 1,939 -- -- -- -- -- --
Cumulative effect of change in
accounting principle -net-of-tax $ -- $ 3,819 -- -- -- -- -- --
-------- -------
Net income $ 9,249 $ 5,758 $ 7,146 $ 8,015 $ 10,380 $ 9,877 $ 18,202 $ 10,870
Earnings available for common shares $ 8,659 $ 5,168 $ 6,557 $ 7,426 $ 9,801 $ 9,287 $ 17,732 $ 10,281
Basic and diluted earnings per share
Before cumulative effect of change
in accounting principle $ .36 $ .06 -- -- -- -- -- --
Cumulative effect of change in
accounting principle $ -- $ .16 -- -- -- -- -- --
-------- -------
Basic and diluted earnings per share $ .36 $ .22 $ .28 $ .32 $ .41 $ .39 $ .74 $ .43
Dividends paid per common share $ .2475 $ .24 $ .2475 $ .24 $ .2475 $ .24 $ .2475 $ .24
Price range:
High $22 3/8 $19 3/8 $21 3/16 $18 7/8 $22 3/4 $20 3/8 $22 25/32 $21 3/8
Low $17 $18 $19 $15 1/16 $19 $17 1/2 $18 3/4 $18 1/2
Average number of common shares
outstanding 23,780 23,481 23,845 23,554 23,850 23,637 23,851 23,710
The fourth quarter of 1999 includes a $14.5 million ($8.1 million net-of-tax) gain from the sale of the radio station
assets.
In the first quarter of 1998 the Company changed its method of electric revenue recognition in the states of Minnesota
and South Dakota from meter-reading dates to energy-delivery dates resulting in the recognition of $6,364,000
($3,819,000 net-of-tax) in unbilled revenue. The first quarter of 1998 also reflects the recording of special charges
related to the voluntary early retirement program, Quadrant Co. asset impairment and the write-off of the Big Stone
plant rail spur project.
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Stock Listing
- --------------
Otter Tail common stock is traded on The Nasdaq Stock Market.
(Nasdaq: National Association of Securities Dealers Automated Quotation.)
Exhibit 21-A
OTTER TAIL POWER COMPANY
Subsidiaries of the Registrant
March 1, 2000
Company State of Organization
Minnesota-Dakota Generating Company Minnesota
Otter Tail Realty Company Minnesota
Otter Tail Management Corporation* Minnesota
ORD Corporation* Minnesota
Quadrant Co.* Minnesota
Midwest Information Systems, Inc. Minnesota
Midwest Telephone Co. Minnesota
Osakis Telephone Company Minnesota
The Peoples Telephone Company of Bigfork Minnesota
Data Video Systems, Inc. Minnesota
Otter Tail Communications SD, Inc. South Dakota
MIS Investments, Inc. Minnesota
Varistar Corporation Minnesota
Precision Machine, Inc. Minnesota
Dakota Machine, Inc. North Dakota
Dakota Engineering, Inc.* North Dakota
Aerial Contractors, Inc. North Dakota
Moorhead Electric, Inc. Minnesota
Diagnostic Medical Systems, Inc. North Dakota
DMS Imaging, Inc. North Dakota
DMS Leasing Corporation North Dakota
BTD Manufacturing, Inc. Minnesota
Northern Pipe Products, Inc. North Dakota
Northern Micro, Inc. North Dakota
Fargo Baseball, LLC Minnesota
Fargo Sports Concession LLC Minnesota
Chassis Liner Corporation Minnesota
Chassis Liner Credit Corp. * Minnesota
Otter Tail Energy Services Company, Inc. Minnesota
Mid-States Testing Company Minnesota
Otter Tail Energy Management Company Minnesota
E. W. Wylie Corporation North Dakota
Vinyltech Corporation Arizona
*Inactive
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
Nos. 333-11145 on Form S-3 and 333-25261, 333-73041, 333-73075 on Form S-8
of Otter Tail Power Company of our report dated January 31, 2000,
incorporated by reference in this Annual Report on Form 10-K of Otter Tail
Power Company for the year ended December 31, 1999.
Deloitte & Touche LLP
Minneapolis, Minnesota
March 28, 2000
EXHIBIT 24
POWER OF ATTORNEY
__________
I, JEFFREY J. LEGGE, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, and or any one of
them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as Controller and Principal Accounting Officer of Otter
Tail Power Company, the Annual Report of Otter Tail Power Company on
Form 10-K for its fiscal year ended December 31, 1999, and any and all
amendments to said Annual Report, and to deliver on my behalf said
Annual Report and any and all amendments thereto, as each thereof is
so signed, for filing with the Securities and Exchange Commission
pursuant to the Securities Exchange Act of 1934, as amended.
Date: January 6, 2000.
----------------
/s/ Jeff Legge
-------------------------
Jeff Legge
In Presence of:
Kathy Legge
- ------------------------
Anita Anderson
- ------------------------
POWER OF ATTORNEY
__________
I, JOHN C. MAC FARLANE, do hereby constitute and appoint
JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them, my
Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as President and Chief Executive Officer, Principal Executive
Officer and Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 5, 2000.
----------------
/s/ John MacFarlane
-------------------------
John MacFarlane
In Presence of:
Lori D. Dawkins
- ------------------------
Penny Mosher
- ------------------------
POWER OF ATTORNEY
__________
I, ROBERT N. SPOLUM, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 10, 2000.
-----------------
/s/ Robert N. Spolum
-------------------------
Robert N. Spolum
In Presence of:
Francine C. Johnson
- ------------------------
W. T. Todd
- ------------------------
POWER OF ATTORNEY
__________
I, NATHAN I. PARTAIN, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 18, 2000.
-----------------
/s/ Nathan I. Partain
-------------------------
Nathan I. Partain
In Presence of:
Eric Elvekrog
- ------------------------
Ellen Rembert
- ------------------------
POWER OF ATTORNEY
__________
I, DAYLE DIETZ, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 15, 2000.
-----------------
/s/ Dayle Dietz
-------------------------
Dayle Dietz
In Presence of:
Stan Stroh
- ------------------------
Penny Mosher
- ------------------------
POWER OF ATTORNEY
__________
I, ARVID R. LIEBE, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 7, 2000.
----------------
/s/ Arvid R. Liebe
-------------------------
Arvid R. Liebe
In Presence of:
Renee Thomas
- ------------------------
Beth M. Folk
- ------------------------
POWER OF ATTORNEY
__________
I, THOMAS M. BROWN, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 7, 2000.
----------------
/s/ Thomas M. Brown
-------------------------
Thomas M. Brown
In Presence of:
Donna M. Hull
- ------------------------
Marla Larson
- ------------------------
POWER OF ATTORNEY
__________
I, MAYNARD D. HELGAAS, do hereby constitute and appoint JOHN
C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of
them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as Director of Otter Tail Power Company, the Annual
Report of Otter Tail Power Company on Form 10-K for its fiscal year
ended December 31, 1999, and any and all amendments to said Annual
Report, and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 17, 2000.
-----------------
/s/ Maynard D. Helgaas
-------------------------
Maynard D. Helgaas
In Presence of:
Carrie Horsted
- ------------------------
Elaine Hazelton
- ------------------------
POWER OF ATTORNEY
__________
I, KENNETH L. NELSON, do hereby constitute and appoint JOHN
C. MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of
them, my Attorney-in-Fact for the purpose of signing, in my name and
on my behalf as Director of Otter Tail Power Company, the Annual
Report of Otter Tail Power Company on Form 10-K for its fiscal year
ended December 31, 1999, and any and all amendments to said Annual
Report, and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 17, 2000.
-----------------
/s/ Kenneth L. Nelson
-------------------------
Kenneth L. Nelson
In Presence of:
Mike Holper
- ------------------------
Wayne Cagheny
- ------------------------
POWER OF ATTORNEY
__________
I, DENNIS R. EMMEN, do hereby constitute and appoint JOHN C.
MAC FARLANE, JOHN D. ERICKSON, and C. E. BRUNKO, or any one of them,
my Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Director of Otter Tail Power Company, the Annual Report of
Otter Tail Power Company on Form 10-K for its fiscal year ended
December 31, 1999, and any and all amendments to said Annual Report,
and to deliver on my behalf said Annual Report and any and all
amendments thereto, as each thereof is so signed, for filing with the
Securities and Exchange Commission pursuant to the Securities Exchange
Act of 1934, as amended.
Date: January 17, 2000.
-----------------
/s/ Dennis R. Emmen
-------------------------
Dennis R. Emmen
In Presence of:
Dee Fletcher
- ------------------------
Deborah A. Kleven
- ------------------------
POWER OF ATTORNEY
__________
I, JOHN D. ERICKSON, do hereby constitute and appoint JOHN
C. MAC FARLANE, and C. E. BRUNKO, or any one of them, my
Attorney-in-Fact for the purpose of signing, in my name and on my
behalf as Vice President, Finance of Otter Tail Power Company, the
Annual Report of Otter Tail Power Company on Form 10-K for its fiscal
year ended December 31, 1999, and any and all amendments to said
Annual Report, and to deliver on my behalf said Annual Report and any
and all amendments thereto, as each thereof is so signed, for filing
with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended.
Date: January 19, 2000.
-----------------
/s/ John Erickson
-------------------------
John Erickson
In Presence of:
Penny Mosher
- ------------------------
Becky Luhning
- ------------------------
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27
<LEGEND>
This schedule contains summary financial information extracted from
the Consolidated Balance Sheet as of December 31, 1999, and the
Consolidated Statement of Income for the twelve months ended
December 31, 1999, and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 447,101
<OTHER-PROPERTY-AND-INVEST> 104,809
<TOTAL-CURRENT-ASSETS> 119,936
<TOTAL-DEFERRED-CHARGES> 8,942
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 680,788
<COMMON> 119,250
<CAPITAL-SURPLUS-PAID-IN> (301)
<RETAINED-EARNINGS> 126,744
<TOTAL-COMMON-STOCKHOLDERS-EQ> 245,693
18,000
15,500
<LONG-TERM-DEBT-NET> 176,437
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 5,948
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 219,210
<TOT-CAPITALIZATION-AND-LIAB> 680,788
<GROSS-OPERATING-REVENUE> 464,577
<INCOME-TAX-EXPENSE> 23,915
<OTHER-OPERATING-EXPENSES> 397,211
<TOTAL-OPERATING-EXPENSES> 421,126
<OPERATING-INCOME-LOSS> 43,451
<OTHER-INCOME-NET> 16,297
<INCOME-BEFORE-INTEREST-EXPEN> 59,748
<TOTAL-INTEREST-EXPENSE> 14,771
<NET-INCOME> 44,977
2,228
<EARNINGS-AVAILABLE-FOR-COMM> 42,749
<COMMON-STOCK-DIVIDENDS> 23,554
<TOTAL-INTEREST-ON-BONDS> 14,232
<CASH-FLOW-OPERATIONS> 78,325
<EPS-BASIC> 1.79<F1>
<EPS-DILUTED> 1.79<F1>
<FN>
<F1>Per-share data reflects the effects of the two-for-one
stock split effective March 15, 2000. Prior Financial
Data Schedules have not been restated to reflect the
stock split.
</FN>
</TABLE>
