SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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þ
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Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the fiscal year ended December 31, 2006
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o
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Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the transition period from
to
Commission File Number 0-368
OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter)
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MINNESOTA
(State or other jurisdiction of incorporation or organization)
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41-0462685
(I.R.S. Employer Identification No.)
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215 SOUTH CASCADE STREET, BOX 496,
FERGUS FALLS, MINNESOTA
(Address of principal executive offices)
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56538-0496
(Zip Code)
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Registrant’s telephone number, including area code:
866-410-8780
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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COMMON SHARES, par value $5.00 per share
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The NASDAQ Stock Market LLC
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Securities registered pursuant to Section 12(g) of the Act:
CUMULATIVE PREFERRED SHARES, without par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the
Securities Act. (Yes
þ
No
o
)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. (Yes
o
No
þ
)
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
þ
No
o
)
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.
þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or
a
non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule
12b-2 of
the Exchange Act. (Check one):
Large Accelerated Filer
þ
Accelerated Filer
o
Non-Accelerated Filer
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). (Yes
o
No
þ
)
The aggregate market value of the voting stock held by non-affiliates, computed by reference to the
last sales price, on June 30, 2006 was
$784,855,944.
Indicate the number of shares outstanding of each of the registrant’s classes of Common Stock, as
of
the latest practicable date:
29,551,401 Common Shares ($5 par value) as of February 15, 2007.
Documents Incorporated by Reference:
2006 Annual Report to Shareholders-Portions incorporated by reference into Parts I and II
Proxy Statement for the 2007 Annual Meeting-Portions incorporated by reference into Part III
TABLE OF CONTENTS
PART I
Item 1.
BUSINESS
(a)
General Development of Business
Otter Tail Corporation (the Company) was incorporated in 1907 under the laws of the State of
Minnesota. The Company’s executive offices are located at 215 South Cascade Street, P.O. Box 496,
Fergus Falls, Minnesota 56538-0496 and 4334 18
th
Avenue SW, Suite 200, P.O. Box 9156,
Fargo, North Dakota 58106-9156. Its telephone number is (866) 410-8780.
The Company makes available free of charge at its internet website (www.ottertail.com) its
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3,
4 and 5 filed on behalf of directors and executive officers and any amendments to these reports
filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as
soon as reasonably practicable after such material is electronically filed with or furnished to the
Securities and Exchange Commission. Information on the Company’s website is not deemed to be
incorporated by reference into this Annual Report on Form 10-K.
In the late 1980s, the Company determined that its core electric business was located in a
region of the country where there was little growth in the demand for electricity. In order to
maintain growth for shareholders, Otter Tail Power Company (as the Company was then known) began to
explore opportunities for the acquisition and long-term ownership of nonelectric businesses. This
strategy has resulted in steady revenue growth over the years. In 2001, the name of the Company was
changed to “Otter Tail Corporation” to more accurately represent the broader scope of electric and
nonelectric operations and the name “Otter Tail Power Company” was retained for use by the electric
utility. In 2006, approximately 28% of the Company’s consolidated operating revenues and
approximately 48% of the Company’s consolidated income from continuing operations came from
electric operations.
The Company’s strategy is straightforward: Reliable utility performance combined with growth
opportunities at all our businesses provides long-term value. This includes growing the core
electric utility business which provides a strong base of revenues, earnings and cash flows. In
addition, the Company looks to its nonelectric operating companies to provide growth both
organically and through acquisitions. Organic, internal growth comes from new products and
services, market expansion and increased efficiencies. The Company adheres to strict guidelines
when reviewing acquisition candidates. The Company’s aim is to add companies that will produce an
immediate positive impact on earnings and provide long-term growth potential. The Company believes
owning well-run, profitable companies across different industries will bring more growth
opportunities and more balance to results. In doing this, the Company also avoids concentrating
business risk within a single industry. All of the operating companies operate under a
decentralized business model with disciplined corporate oversight.
The Company assesses the performance of its operating companies over time, using the following
criteria:
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ability to provide returns on invested capital that exceed the Company’s weighted
average cost of capital over the long term; and
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assessment of an operating company’s business and potential for future earnings
growth.
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The Company is a committed long-term owner of its operating companies and does not acquire
companies in pursuit of short-term gains. However, the Company will divest operating companies if
they do not meet these criteria over the long term.
1
Otter Tail Corporation and its subsidiaries conduct business in all 50 states and in
international markets. The Company had approximately 3,705 full-time employees at December 31,
2006. The businesses of the Company have been classified into six segments: Electric, Plastics,
Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations.
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Electric
(the Utility) includes the production, transmission, distribution
and sale of electric energy in Minnesota, North Dakota and South Dakota under the name
Otter Tail Power Company. In addition the Utility is an active wholesale participant in
the Midwest Independent Transmission System Operator (MISO) markets. Electric utility
operations have been the Company’s primary business since incorporation.
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Plastics
consists of businesses producing polyvinyl chloride and
polyethylene pipe in the Upper Midwest and Southwest regions of the United States.
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Manufacturing
consists of businesses in the following manufacturing
activities: production of waterfront equipment, wind towers, material and handling
trays and horticultural containers, contract machining, and metal parts stamping and
fabrication. These businesses have manufacturing facilities in Minnesota, North Dakota,
South Carolina, Missouri, California, Florida and Ontario, Canada and sell products
primarily in the United States.
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Health Services
consists of businesses involved in the sale of diagnostic
medical equipment, patient monitoring equipment and related supplies and accessories.
These businesses also provide equipment maintenance, diagnostic imaging services and
rental of diagnostic medical imaging equipment to various medical institutions located
throughout the United States.
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Food Ingredient Processing
consists of Idaho Pacific Holdings, Inc. (IPH),
which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and
Souris, Prince Edward Island, Canada. IPH produces dehydrated potato products that are
sold in the United States, Canada, Europe, the Middle East, the Pacific Rim and Central
America. Approximately 32% of IPH’s sales are to customers outside of the United
States.
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Other Business Operations
consists of businesses in residential, commercial
and industrial electric contracting industries, fiber optic and electric distribution
systems, wastewater and HVAC systems construction, transportation and energy services,
as well as the portion of corporate general and administrative expenses that are not
allocated to other segments. These businesses operate primarily in the Central United
States, except for the transportation company which operates in 48 states and 6
Canadian provinces.
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The Company’s electric operations, including wholesale power sales, are operated as a division
of Otter Tail Corporation, and the Company’s energy services operation is operated as a subsidiary
of Otter Tail Corporation. Substantially all of the other businesses are owned by the Company’s
wholly-owned subsidiary, Varistar Corporation (Varistar).
The Company considers the following guidelines when reviewing potential acquisition
candidates:
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Emerging or middle market company;
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Proven entrepreneurial management team that will remain after the acquisition;
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Preference for 100% ownership of the acquired company;
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Products and services intended for commercial rather than retail consumer use; and
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The potential to provide immediate earnings and future growth.
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2
The
Company continues to look for strategic acquisitions of additional
businesses with emphasis on adding to existing operating companies and expects continued
growth in this area. No new acquisitions occurred during 2006. At
present, the most ambitious growth initiatives are major capital
projects within existing operating companies.
As part of an ongoing evaluation of the prospects and growth opportunities of the Company’s
business operations, the Company completed the sale of its natural gas marketing operations during
2006. As required in accordance with Statement of Financial Accounting Standard No. 144,
Accounting
for the Impairment of Disposal of Long-Lived Assets
, the natural gas marketing operations were
accounted for as discontinued operations in the Company’s consolidated financial statements which
are incorporated by reference and filed as an Exhibit hereto. Prior to 2006, the natural gas
marketing operations were included in the Other Business Operations segment. For financial
information regarding this sale see note 16 of “Notes to Consolidated Financial Statements” on
pages 60 and 61 of the Company’s 2006 Annual Report to Shareholders, filed as an Exhibit hereto.
On June 30, 2005 the Utility and a coalition of six other electric providers entered into
agreements for the development of Big Stone II, a proposed 630-megawatt coal-fired electric
generating plant adjacent to the existing Big Stone Plant near Milbank, South Dakota. During 2006,
the Utility continued to move forward with the planning and permitting process for Big Stone II.
For a further description of this project, see “Narrative Description of the
Business—Electric—Big Stone II.”
For a discussion of the Company’s results of operations, see “Management’s Discussion and
Analysis of Financial Condition and Results of Operations,” which is incorporated by reference to
pages 18 through 33 of the Company’s 2006 Annual Report to Shareholders, filed as an Exhibit
hereto.
(b)
Financial Information About Industry Segments
The Company is engaged in businesses that have been classified into six segments: Electric,
Plastics, Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations.
Financial information about the Company’s segments and geographic areas is incorporated by
reference to note 2 of “Notes to Consolidated Financial Statements” on pages 45 and 46 of the
Company’s 2006 Annual Report to Shareholders, filed as an Exhibit hereto.
(c)
Narrative Description of Business
ELECTRIC
General
The Utility provides electricity to more than 129,000 customers in a 50,000 square mile area
of Minnesota, North Dakota and South Dakota. The Company derived 28%, 32% and 33% of its
consolidated operating revenues from the Electric segment for each of the three years ended
December 31, 2006, 2005 and 2004, respectively. The Company derived 48%, 69% and 78% of its
consolidated income from continuing operations from the Electric segment for each of the three
years ended December 31, 2006, 2005 and 2004, respectively. The breakdown of retail revenues by
state is as follows:
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State
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2006
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2005
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Minnesota
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51.5
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%
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50.3
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%
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North Dakota
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39.8
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40.9
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South Dakota
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8.7
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8.8
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Total
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100.0
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%
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100.0
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%
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The territory served by the Utility is predominantly agricultural. Although there are
relatively few large customers, sales to commercial and industrial customers are significant. The
following table provides a
3
breakdown of electric revenues by customer category. All other sources include gross wholesale
sales from Utility generation, net revenue from energy trading activity and sales to
municipalities.
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Customer category
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2006
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2005
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Commercial
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35.6
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%
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33.5
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%
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Residential
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30.5
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28.1
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Industrial
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23.0
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20.9
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All other sources
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10.9
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17.5
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Total
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100.0
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%
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100.0
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%
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Wholesale electric energy kWh sales were 41.0% of total kWh sales for 2006 and 41.6% for 2005.
Wholesale electric energy kWh sales were essentially flat between the years while revenue per kWh
decreased by 8.4%. Activity in the short-term energy market is subject to change based on a number
of factors and it is difficult to predict the quantity of wholesale power sales or prices for
wholesale power in the future.
With the inception of the MISO Day 2 markets in April 2005, MISO introduced two new types of
contracts, virtual transactions and Financial Transmission Rights (FTR). Virtual transactions are
of two types: Virtual Demand Bid, which is a bid to purchase energy in MISO’s Day-Ahead Market that
is not backed by physical load, and Virtual Supply Offer which is an offer submitted by a market
participant in the Day-Ahead Market to sell energy not supported by a physical injection or
reduction in withdrawals in commitment by a resource. An FTR is a financial contract that entitles
its holder to a stream of payments, or charges, based on transmission congestion charges calculated
in MISO’s Day-Ahead Market. A market participant can acquire an FTR from several sources: the
annual or monthly FTR allocation based on existing entitlements, the annual or monthly FTR auction,
the FTR secondary market, or a grant of an FTR in conjunction with a transmission service request.
An FTR is structured to hedge a market participant’s exposure to uncertain cash flows resulting
from congestion of the transmission system. In 2006, net revenues from virtual and FTR transactions
represented 1.4% of total electric energy revenues compared with 4.9% in 2005. As the MISO markets
have evolved and become more efficient, profits from virtual transactions have declined.
The aggregate population of the Utility’s retail electric service area is approximately
230,000. In this service area of 423 communities and adjacent rural areas and farms, approximately
130,900 people live in communities having a population of more than 1,000, according to the 2000
census. The only communities served which have a population in excess of 10,000 are Jamestown,
North Dakota (15,527); Fergus Falls, Minnesota (13,471); and Bemidji, Minnesota (11,917). As of
December 31, 2006 the Utility served 129,070 customers. This is an increase of 604 customers over
December 31, 2005.
Capability and Demand
As of December 31, 2006 and 2005 the Utility had base load net plant capability as follows:
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Base load net plant capability
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2006
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2005
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Big Stone Plant
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256,025
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kW
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256,025
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kW
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Coyote Station
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149,450
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149,450
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Hoot Lake Plant
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143,875
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153,700
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Co-generation plant — Bemidji, MN (contract)
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—
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5,862
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Co-generation plant — Perham, MN (contract)
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1,281
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1,242
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Total
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550,631
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kW
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566,279
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kW
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The base load net plant capability for Big Stone Plant and Coyote Station constitutes the Utility’s
ownership percentages of 53.9% and 35%, respectively. The Utility owns 100% of the Hoot Lake Plant.
Base load net plant capability decreased at the Hoot Lake Plant due to the retirement of the unit 1
turbine generator on December 31, 2005. The contract under which the Utility obtained energy from a co-generation plant near
4
Bemidji,
MN was terminated in 2006, due to the closure of the adjacent mill that produced wood-waste used to
fuel the generator.
In addition to its base load capability, the Utility has combustion turbine and small diesel
units owned or under contract, used chiefly for peaking and standby purposes, with a total
capability of 145,098 kW, and hydroelectric capability of 4,294 kW. During 2006, the Utility
generated about 76% of its retail kWh sales and purchased the balance.
The Utility has arrangements to help meet its future base load requirements and continues to
investigate other means for meeting such requirements. The Utility has an agreement to purchase
50,000 kW of year-round capacity through April 30, 2010. The Utility has agreements to purchase the
output from approximately 23,000 kW (nameplate rating) of wind generating facilities. The December
2006 capacity rating of the wind generating facilities was 6,451 kW. Surplus energy is received
from another 2,300 kW (nameplate rating) of wind generation that customers use to supply some of
their own load. The Utility has a direct control load management system which provides some
flexibility to the Utility to effect reductions of peak load. The Utility, in addition, offers
rates to customers which encourage off-peak usage.
The Utility traditionally experiences its peak system demand during the winter season. For the
year ended December 31, 2006 the Utility experienced a system peak demand of 680,331 kW on December
7, 2006. The highest all-time system peak demand was 686,044 kW on January 5, 2004. Taking into
account additional capacity available to it on December 7, 2006 under purchase power contracts
(including short-term arrangements), as well as its own generating capacity, the Utility’s
capability of then meeting system demand, excluding reserve requirements computed in accordance
with accepted industry practice, amounted to 845,470 kW (776,060 kW if reserve requirements are
included). The Utility’s additional capacity available under power purchase contracts (as described
above), combined with generating capability and load management control capabilities, is expected
to meet 2007 system demand, including industry reserve requirements.
Big Stone II
On June 30, 2005 the Utility and a coalition of six other electric providers entered into
several agreements for the development of a second electric generating unit, named Big Stone II, at
the site of the existing Big Stone Plant near Milbank, South Dakota. The three primary agreements
are the Participation Agreement, the Operation and Maintenance Agreement and the Joint Facilities
Agreement. Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power
District, Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc., Southern Minnesota
Municipal Power Agency and Western Minnesota Municipal Power Agency are parties to all three
agreements. NorthWestern Corporation, one of the co-owners of the existing Big Stone Plant, is an
additional party to the Joint Facilities Agreement.
The Participation Agreement is an agreement to jointly develop, finance, construct, own (as
tenants in common) and manage the Big Stone II Plant. The Participation Agreement includes
provisions which obligate the parties to the agreement to obtain financing and pay their share of
development, construction, operating and maintenance costs for the Big Stone II Plant. It also
provides for the sharing of the plant output. Estimated construction costs for the plant including
transmission are expected to be approximately $1.8 billion. The Participation Agreement provides
that the Utility shall pay for and own 19.33% of the Big Stone II Plant and be entitled to a
corresponding interest in the plant’s electrical output. The project participants included in the
Participation Agreement a section covering withdrawal rights due to higher than anticipated project
costs. Higher than anticipated project costs give each participant certain withdrawal rights
exercisable at an agreed upon time. Under amendments to the Participation Agreement entered into in
2006, that time has been extended to June 2007. The Participation Agreement establishes a
Coordinating Committee and an Engineering and Operating Committee to manage the development,
design, construction, operation and maintenance of the Big Stone II Plant.
5
The Operation and Maintenance Agreement designates the Utility as the operator of the Big
Stone II Plant. As operator, the Utility is required to provide staff and resources for the
development, design, financing, construction and operation of the Big Stone II Plant. The other
project participants are each required to reimburse the Utility for their respective share of the
costs relating to those activities. The Coordinating Committee and the Engineering and Operating
Committee, which are made up of representatives of all project participants, are authorized to
supervise the Utility in its role as operator.
The Joint Facilities Agreement provides for the transfer of certain real property and
easements from the Big Stone I Plant owners to the Big Stone II Plant participants and for the
shared use of certain equipment and facilities between the two plants. The Joint Facilities
Agreement also allocates between the two plants the costs of operation and maintenance of the
shared equipment and facilities.
The proposed project is intended to serve the participants’ native customer loads, will be
nominally rated 630 megawatts and will be rate-based and coal fired or coal-and-biomass fired. The
proposed project is expected to meet air emission requirements as prescribed by the Environmental
Protection Agency and the South Dakota Department of Environment and Natural Resources. Black &
Veatch Corporation, a Kansas City based engineering firm, has been selected to do the plant design
work and provide construction management services.
The participants are in the process of securing the permits required for construction and
operation of the project, including the generation permit, air emission permits and certificate of
need and route permits for transmission. In addition, a federal environmental impact statement
(EIS) is expected to yield a Record of Decision in third quarter 2007. All major permits have
been filed and are scheduled to be finalized in 2007. For more information regarding the status of
the permitting process, see “General Regulation” and “Environmental Regulation.” Financial close,
which requires the participants to provide binding financial commitments to support their share of
costs, is to occur 90 days after the EIS Record of Decision. The financial close is not currently
expected until first quarter of 2008. No one can predict the exact outcome of any of these
proceedings and there have been interveners in the permitting process. If the necessary approvals
are received and plans progress, groundbreaking is expected to take place in 2008 with the plant in
service by 2012.
Fuel Supply
Coal is the principal fuel burned at the Big Stone, Coyote and Hoot Lake generating plants.
Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake and Big Stone
plants burn western subbituminous coal.
The following table shows the sources of energy used to generate the Utility’s net output of
electricity for 2006 and 2005:
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2006
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2005
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Net Kilowatt Hours
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Net Kilowatt Hours
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Generated
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% of Total Kilowatt
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Generated
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% of Total Kilowatt
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Sources
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(Thousands)
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Hours Generated
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(Thousands)
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Hours Generated
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Subbituminous Coal
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2,539,723
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71.1
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%
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2,410,719
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68.6
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%
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Lignite Coal
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981,478
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27.5
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1,043,020
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29.7
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Hydro
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18,363
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.5
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23,446
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.7
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Natural Gas and Oil
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31,846
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.9
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36,520
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1.0
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Total
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3,571,410
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100.0
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%
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3,513,705
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100.0
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%
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6
The Utility has the following primary coal supply agreements:
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Plant
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Coal Supplier
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Type of Coal
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Expiration Date
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Big Stone Plant
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Arch Coal Sales Company, Inc.
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Wyoming subbituminous
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December 31, 2007
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Big Stone Plant
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Kennecott Coal Sales Company
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Wyoming subbituminous
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December 31, 2007
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Hoot Lake Plant
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Kennecott Coal Sales Company
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Wyoming subbituminous
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December 31, 2007
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Coyote Station
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Dakota Westmoreland Corporation
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North Dakota lignite
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2016
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The contract with Dakota Westmoreland Corporation has a 15-year renewal option subject to
certain contingencies. It is the Utility’s practice to maintain a minimum 30-day inventory (at full
output) of coal at the Big Stone Plant and a 20-day inventory at the Coyote Station and Hoot Lake
Plant. Delivery disruptions in early 2006 to both Big Stone Plant and Hoot Lake Plant forced load
restrictions at those plants to prevent depletion of the stockpiles. Through these and other
efforts, the delivery slowdown was successfully managed without diminishing reliability.
Both plants have leased additional railcars to maintain sufficient deliveries of coal
needed to run at full-load capacity.
Railroad transportation services to the Big Stone Plant are being provided under a common
carrier rate by the Burlington Northern and Santa Fe Railroad. The Company filed a complaint in
regard to this rate with the Surface Transportation Board requesting the Board set a competitive
rate. On January 27, 2006 the Surface Transportation Board issued a final decision dismissing the
case. The co-owners of the Big Stone Plant appealed the Surface Transportation Board’s decision to
the U.S. Court of Appeals for the Eighth Circuit. Oral arguments were heard on the case on January
8, 2007, and a decision on the appeal is expected during the third quarter of 2007. During the
appeal process, the railroad transportation services to the Big Stone Plant continue to be provided
under the common carrier rate. Railroad transportation services to the Hoot Lake Plant are being
provided under a common carrier rate by the Burlington Northern and Santa Fe Railroad. On January
1, 2006, the Burlington Northern and Santa Fe Railroad implemented a new mileage-based methodology
to assess fuel surcharges that replaced the previous revenue-based fuel surcharge. The basis for
the fuel surcharge is still the U.S. average price of retail on-highway diesel fuel. The fuel
surcharge applies to both Hoot Lake and Big Stone plants. 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 2006, 2005 and 2004 was $1.419, $1.339 and $1.229, respectively.
The Utility is permitted by the State of South Dakota to burn some alternative fuels,
including tire-derived fuel and biomass, at the Big Stone Plant.
7
General Regulation
The Utility is subject to regulation of rates and other matters in each of the three states in
which it operates and by the federal government for certain interstate operations.
A breakdown of electric rate regulation by each jurisdiction is as follows:
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2006
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2005
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% of
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% of
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% of
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% of
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Electric
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kWh
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Electric
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kWh
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Rates
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Regulation
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Revenues
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Sales
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Revenues
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Sales
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MN retail sales
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MN Public Utilities
Commission
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33.6
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%
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30.8
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%
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31.2
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%
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30.2
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%
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ND retail sales
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ND Public Service
Commission
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25.9
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22.7
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25.3
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22.9
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SD retail sales
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SD Public Utilities
Commission
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5.7
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5.4
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5.5
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5.2
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Transmission & wholesale
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Federal Energy Regulatory Commission
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34.8
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41.1
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38.0
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41.7
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100.0
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%
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100.0
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%
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100.0
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%
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100.0
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%
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The Utility operates under approved retail electric tariffs in all three states it serves. The
Utility has an obligation to serve any customer requesting service within its assigned service
territory. Accordingly, the Utility has designed its electric system to provide continuous service
at time of peak usage. The pattern of electric usage can vary dramatically during a 24-hour period
and from season to season. The Utility’s tariffs provide for continuous electric service and are
designed to cover the costs of service during peak times. To the extent that peak usage can be
reduced or shifted to periods of lower usage, the cost to serve all customers is reduced. In order
to shift usage from peak times, the Utility has approved tariffs in all three states for lower
rates for residential demand control and controlled service, in Minnesota and North Dakota for
real-time pricing, and in North Dakota and South Dakota for bulk interruptible rates. Each of these
specialized rates is designed to improve efficient use of the Utility facilities, while encouraging
use of cost-effective electricity instead of other fuels and giving customers more control over the size of their electric bill. In
all three states, the Utility has approved tariffs which allow qualifying customers to release and
sell energy back to the Utility when wholesale energy prices make such transactions desirable.
The majority of the Utility’s electric retail rate schedules now in effect provide for
adjustments in rates based on the cost of fuel delivered to the Utility’s generating plants, as
well as for adjustments based on the cost of electric energy purchased by the Utility. Such
adjustments are presently based on a two-month moving average in Minnesota and under the Federal
Energy Regulatory Commission (FERC), a three-month moving average in South Dakota and a four-month
moving average in North Dakota. These adjustments are applied to the next billing period after
becoming applicable.
The following summarizes the material regulations of each jurisdiction applicable to the
Utility’s electric operations, as well as any specific electric rate proceedings during the last
three years with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service
Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and FERC. The Company’s
nonelectric businesses are not subject to direct regulation by any of these agencies.
Minnesota
: Under the Minnesota Public Utilities Act, the Utility is subject to the
jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public
utility services, construction of major utility facilities, establishment of exclusive assigned
service areas, contracts and arrangements with
subsidiaries and other affiliated interests, and other matters. The MPUC has the authority to
assess the need
8
for large energy facilities and to issue or deny certificates of need, after public
hearings, within one year of an application to construct such a facility. The Utility has not had a
significant rate proceeding before the MPUC since July 1987. The Utility has agreed to file a
general rate case on or before October 1, 2007.
The Department of Commerce (DOC) is responsible for investigating all matters subject to the
jurisdiction of the DOC or the MPUC, and for the enforcement of MPUC orders. Among other things,
the DOC is authorized to collect and analyze data on energy and the consumption of energy, develop
recommendations as to energy policies for the governor and the legislature of Minnesota and
evaluate policies governing the establishment of rates and prices for energy as related to energy
conservation. The DOC acts as a state advocate in matters heard before the MPUC. The DOC also has
the power, in the event of energy shortage or for a long-term basis, to prepare and adopt
regulations to conserve and allocate energy.
Under Minnesota law, every regulated public utility that furnishes electric service must make
annual investments and expenditures in energy conservation improvements, or make a contribution to
the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross
operating revenues from service provided in Minnesota. The DOC may require the utility to make
investments and expenditures in energy conservation improvements whenever it finds that the
improvement will result in energy savings at a total cost to the utility less than the cost to the
utility to produce or purchase an equivalent amount of a new supply of energy. Such DOC orders are
appealable to the MPUC. Investments made pursuant to such orders generally are recoverable costs in
rate cases, even though ownership of the improvement may belong to the property owner rather than
the utility. Since 1995, the Utility has recovered conservation related costs not included in base
rates under Minnesota’s Conservation Improvement Programs through the use of an annual recovery
mechanism approved by the MPUC.
The MPUC requires the submission of a 15-year advance integrated resource plan by utilities
serving at least 10,000 customers, either directly or indirectly, and having at least 100 megawatts
of load. The MPUC’s findings and orders with respect to these submissions are binding for
jurisdictional utilities. Typically, the filings are submitted every two years. The Utility
submitted its most recent integrated resource plan on July 1, 2005. MPUC action on that plan is
pending.
The MPUC requires the annual filing of a capital structure petition. In this filing the MPUC
reviews and approves the capital structure for the Company. Once the petition is approved, the
Company may issue securities without further petition or approval, provided the issuance is
consistent with the purposes and amounts set forth in the approved capital structure petition. The
Company’s current capital structure petition is in effect until the Commission issues a new capital
structure order for 2007. The Company expects to file its 2007 capital structure petition in March
and expects to receive approval from the MPUC prior to May 31, 2007.
The Minnesota legislature has enacted a statute that favors conservation over the addition of
new resources. In addition, it has mandated the use of renewable resources where new supplies are
needed, unless the utility proves that a renewable energy facility is not in the public interest.
It has effectively prohibited the building of new nuclear facilities. An existing environmental
externality law requires the MPUC, to the extent practicable, to quantify the environmental costs
associated with each method of electricity 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.
In February 2007, the Minnesota legislature passed a renewable energy standard requiring that
the Utility generate or procure sufficient renewable generation such that the following percentages
of total retail electric sales to retail customers in Minnesota are generated by qualifying
renewables: 12% by 2012; 17%
9
by 2016; 20% by 2020 and 25% by 2025. Under certain circumstances and after consideration of
costs and reliability issues, the MPUC may modify or delay implementation of the standards.
Pursuant to the Minnesota Power Plant Siting Act, the MPUC 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
MPUC is empowered, after an environmental impact study is conducted by the DOC and the Office of
Administrative Law conducts contested case hearings, to select or designate sites in Minnesota for
new electric power generating plants (50,000 kW or more) and routes for transmission lines (100 kV
or more) and to certify such sites and routes as to environmental compatibility. The Utility and
the coalition of six other electric providers filed an application for a Certificate of Need for
the Minnesota portion of the Big Stone II transmission line project on October 3, 2005 and filed an
application for a Route Permit for the Minnesota portion of the Big Stone II transmission line
project with the MPUC on December 9, 2005. Evidentiary hearings were conducted in December 2006
and all parties have submitted legal briefs. The recommendation of the Administrative Law Judge is
expected in March 2007 and final action by the MPUC is possible in May 2007.
The Minnesota Legislature enacted the Minnesota Energy Security and Reliability Act in 2001.
Its primary focus was to streamline the siting and routing processes for the construction of new
electric generation and transmission projects. The bill also added to utility requirements for
renewable energy and energy conservation. This legislation also changed the environmental review
authority from the Environmental Quality Board to the DOC.
In September 2004, a letter was provided to the MPUC summarizing issues and conclusions of an
internal investigation completed by the Company related to claims of allegedly improper regulatory
filings brought to the attention of the Company by certain individuals. On November 30, 2004 the
Utility filed a report with the MPUC responding to these claims. In 2005, the Energy Division of
the DOC, the Residential Utilities Division of the Office of Attorney General and the claimants
filed comments in response to the report, to which the Company filed reply comments. A hearing
before the MPUC was held on February 28, 2006. As a result of the hearing, the Utility agreed that
within 90 days it would file a revised Regulatory Compliance Plan, an updated Corporate Cost
Allocation Manual and documentation of the definitions of its chart of accounts. The Utility filed
these documents with the MPUC in the second quarter of 2006. The Company received comments on its
filings from the DOC and the claimants and filed reply comments in August 2006.
The DOC recommended accepting the revised Regulatory Compliance Plan and the chart of accounts
definition. The Utility filed supplemental comments related to its Corporate Allocation Manual in
November 2006. The Utility also agreed to file a general rate case in Minnesota on or before
October 1, 2007. At a MPUC hearing on January 25, 2007 all remaining open issues were resolved. The
MPUC accepted the Company’s compliance filing with minor changes, agreed to allow the Utility to
calculate corporate cost allocations as proposed, determined not to conduct any further review at
this time and required the Company to include all of its short-term debt in its calculations of
allowance for funds used during construction. The Company agreed to provide the MPUC the results of
the current FERC Operational Audit when available, compare the corporate allocation method to a
commonly accepted methodology in the next rate case, and provide the results of the Company’s
investigation relating to a 2007 hotline complaint. The Company recorded a noncash charge to other
income and deductions of $3.3 million in 2006 related to uncertainty with respect to the
capitalized cost of construction funds included in the Utility’s rate base.
In December 2005 the MPUC issued an order denying the Utility’s request to allow recovery of
certain MISO-related costs through the fuel clause adjustment (FCA) in Minnesota retail rates and
requiring a refund of amounts previously collected pursuant to an interim order issued in April
2005. A $1.9 million reduction in revenue and a refund payable was recorded in December 2005 by the
Utility to reflect the refund obligation. On February 9, 2006 the MPUC decided to reconsider its
December 2005 order. The MPUC issued a subsequent order on February 24, 2006, requiring
investor-owned utilities in the state to
10
participate with the DOC and other parties in a proceeding
that would evaluate suitability of recovery of certain MISO Day 2 energy market costs
through the FCA. The February 24, 2006 order eliminated the refund provision from the December 2005
order and allowed that any MISO-related costs not recovered through the FCA may be deferred for a
period of 36 months, with possible recovery through base rates in the Utility’s next general rate
case. As a result, the Utility recognized $1.9 million in revenue and reversed the refund payable
in February 2006. The Utility, together with the other Minnesota utilities and other parties
submitted a final Joint Report to the MPUC in July 2006. On October 31, 2006 the MPUC convened a
technical conference at which the parties provided a summary of the Joint Report. On November 6,
2006 the utilities filed supplemental comments. This matter returned to the MPUC on November 7,
2006.
In an order issued on December 20, 2006, the MPUC stated that except for schedules 16 and 17
administrative costs, discussed below, each petitioning utility may recover the charges imposed by
the MISO for Day 2 operations (offset by revenues from Day 2 operations via net accounting) through
the calculation of the utility’s FCA from the period April 1, 2005 through a period of at least
three years after the date of the order. The MPUC ordered the utilities to refund schedule 16 and
17 costs collected through the FCA since the inception of MISO Day 2 Markets in April 2005 and
stated that each petitioning utility may use deferred accounting for MISO schedule 16 and 17 costs
incurred since April 1, 2005. Each utility may continue deferring schedule 16 and 17 costs without
interest until the earlier of March 1, 2009 or the utility’s next electric rate case. By March 1,
2009, each utility shall begin amortizing the balance of the deferred Day 2 costs through March 1,
2012 unless and until the utility has a rate case addressing the utility’s proposal for recovering
the balance. In its next rate case a utility may seek to recover schedule 16 and 17 costs at an
appropriate level of base rate recovery. The utility may not increase rates to recover MISO
administrative costs unless the costs were prudently incurred, reasonable, resulted in benefits
justifying recovery and not already recovered through other rates. However, a utility may seek to
recover schedule 16 and 17 costs and associated amortizations through interim rates pending the
resolution of a rate case, subject to final MPUC approval. As a result of the December 20, 2006
order, the Utility will refund $446,000 to Minnesota retail customers through the FCA over a
twelve-month period beginning in February 2007 and will defer that amount and additional amounts
related to MISO schedule 16 and 17 costs incurred subsequent to December 31, 2006 until it seeks
recovery of those costs in its next electric rate case to be filed on or before October 1, 2007.
North Dakota
: The Utility is subject to the jurisdiction of the NDPSC with respect to
rates, services, certain issuances of securities and other matters. The NDPSC periodically performs
audits of gas and electric utilities over which it has rate setting jurisdiction to determine the
reasonableness of overall rate levels. In the past, these audits have occasionally resulted in
settlement agreements adjusting rate levels for the Utility. The North Dakota Energy Conversion and
Transmission Facility Siting Act grants the NDPSC the authority to approve sites in North Dakota
for large electric generating facilities and high voltage transmission lines. This Act is similar
to the Minnesota Power Plant Siting Act described above and applies to proposed new electric power
generating plants of 100,000 kW or more and proposed new transmission lines of more than 115 kV.
The Utility is required to submit a ten-year plan to the NDPSC annually.
The NDPSC reserves the right to review the issuance of stocks, bonds, notes and other
evidence of indebtedness of a public utility. However, the issuance by a public utility of
securities registered with the Securities and Exchange Commission is expressly exempted from
review by the NDPSC under North Dakota state law.
In September 2004, a letter was provided to the NDPSC summarizing issues and conclusions of
an internal investigation completed by the Company as it related to claims of allegedly improper
regulatory filings brought to the attention of the Company by certain individuals. The NDPSC did
not open a formal docket, but its staff reviewed the issues. The Company responded to various data
requests and worked with staff and the NDPSC to resolve issues raised by the internal
investigation. In its hotline complaint investigation order issued in May 2006, the NDPSC stated
that, in the opinion of staff, the impact of the issues reviewed was not significant enough to
cause a change in the results of the Company’s performance-based ratemaking plan in place from
2001 through 2005.
11
In February 2005, the Utility filed with the NDPSC a petition to seek recovery of certain
MISO-related costs through the FCA. The NDPSC granted interim recovery through the FCA in April
2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the
merits of the case are determined. The NDPSC has taken no further action regarding this filing.
North Dakota law provides that a utility may ask the NDPSC to determine in advance that an
expected investment in a large generating or transmission facility is prudent. On November 14,
2006, the Utility filed an application asking the NDPSC to determine that the Big Stone II project
is prudent. Evidentiary hearings are scheduled for late spring 2007.
South Dakota
: Under the South Dakota Public Utilities Act, the Utility is subject to
the jurisdiction of the SDPUC with respect to rates, public utility services, establishment of
assigned service areas and other matters. The Utility is not currently subject to the jurisdiction
of the SDPUC with respect to the issuance of securities. Under the South Dakota Energy Facility
Permit Act, the SDPUC has the authority to approve sites in South Dakota for large energy
conversion facilities (100,000 kW or more) and transmission lines of 115 kV or more. There have
been no significant rate proceedings in South Dakota since November 1987. The Utility and the
coalition of six other electric providers filed an Energy Conversion Facility Siting Permit
Application with the SDPUC for the Big Stone II Plant on July 21, 2005. The permit was granted by
the SDPUC on July 14, 2006 and was appealed by the following interveners: Center for Environmental
Advocacy, Fresh Energy, Izaak Walton League, and Union of Concerned Scientists (joint interveners).
In February 2007, a South Dakota circuit judge affirmed the SDPUC’s issuance of the permit, however
it is possible the joint interveners may appeal the decision to the state’s Supreme Court. A
permit application for the South Dakota portion of the transmission line for the Big Stone II Plant
was filed with the SDPUC on January 16, 2006 and was approved by the SDPUC on January 2, 2007.
In September 2004, a letter was provided to the SDPUC summarizing issues and conclusions of
an internal investigation completed by the Company as it related to claims of allegedly improper
regulatory filings brought to the attention of the Company by certain individuals. The staff of
the SDPUC followed up with a few informal questions. There has been no additional correspondence
between the Company and the SDPUC related to these issues.
In March 2005, the Utility filed with the SDPUC a petition to seek recovery of certain
MISO-related costs through the FCA. The SDPUC approved the request in April 2005.
FERC
: Wholesale power sales and transmission rates are subject to the jurisdiction of
the FERC under the Federal Power Act of 1935, as amended (FPA). The FERC is an independent agency,
which has jurisdiction over rates for wholesale electricity sales, transmission and sale of
electric energy in interstate commerce, interconnection of facilities, and accounting policies and
practices. Filed rates are effective after a one-day suspension period, subject to ultimate
approval by the FERC.
On April 25, 2006 the FERC issued an order requiring MISO to refund to customers, with
interest, amounts related to real-time revenue sufficiency guarantee (RSG) charges that were not
allocated to day-ahead virtual supply offers in accordance with MISO’s Transmission and Energy
Markets Tariff (TEMT) going back to the commencement of MISO Day 2 markets in April 2005. On May
17, 2006 the FERC issued a Notice of Extension of Time, permitting MISO to delay compliance with
the directives contained in its April 2006 order, including the requirement to refund to customers
the amounts due, with interest, from April 1, 2005 and the requirement to submit a compliance
filing. The Notice stated that the order on rehearing would provide the appropriate guidance
regarding the timing of compliance filing. On October 26, 2006 the FERC issued an order on
rehearing, stating it would not require refunds related to real-time RSG charges that had not been
allocated to day-ahead virtual supply offers in accordance with MISO’s TEMT going back to the
commencement of the MISO Day 2 market in April 2005. However, the FERC ordered prospective
allocation of RSG charges to virtual transactions consistent with the TEMT to prevent future
inequity and directed MISO to propose a charge that assesses RSG costs to virtual supply offers
12
based on the RSG costs they cause within 60 days of the
October 26, 2006 order. On December 27, 2006 the FERC issued an order granting rehearing of
the October 26, 2006 order.
The Division of Operation Audits of the FERC Office of Market Oversight and Investigations
(OMOI) commenced an audit of the Utility’s transmission practices in 2005. The purpose of the audit
is to determine whether and how the Utility’s transmission practices are in compliance with the
FERC’s applicable rules and regulations and tariff requirements and whether and how the
implementation of the Utility’s waivers from the requirements of Order No. 889 and Order No. 2004
restricts access to transmission information that would benefit the Utility’s off-system sales. The
Division of Operation Audits of the OMOI has not issued an audit report. The Company cannot predict
if the results of the audit will have any impact on the Company’s consolidated financial
statements.
The Comprehensive Energy Policy Act of 2005 (the 2005 Energy Act) signed into law in August
2005, substantially affected the regulation of energy companies, including the Utility. The 2005
Energy Act amended federal energy laws and provided the FERC with new oversight responsibilities.
Among the important changes implemented as a result of this legislation were the following:
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The Public Utility Holding Company Act of 1935 (PUHCA) was repealed effective February
8, 2006. PUHCA significantly restricted mergers and acquisitions in the electric utility
sector.
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•
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FERC appointed the Electric Reliability Organization (ERO) formerly known as North
American Electric Reliability Council (NERC) as an electric reliability organization to
establish and enforce mandatory reliability rules regarding the interstate electric
transmission system. On January 1, 2007 the ERO began operating.
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•
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The FERC established incentives for transmission companies, such as performance based
rates, recovery of costs to comply with reliability rules and accelerated depreciation for
investments in transmission infrastructure.
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•
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Federal support was made available for certain clean coal power initiatives, nuclear
power projects and renewable energy technologies.
|
The Utility continues to follow the regulatory matters arising from the 2005 Energy Act and cannot
predict with certainty the impact on its electric operations.
MAPP
: The Utility participates in the Mid-Continent Area Power Pool (MAPP) generation
reserve sharing pool, which operates in parts of eight states in the Upper Midwest and in three
provinces in Canada.
MEMA
: The Utility is a member of the Mid-Continent Energy Marketers Association (MEMA)
which is an independent, non-profit trade association representing entities involved in the
marketing of energy or in providing services to the energy industry. MEMA operates in the MAPP,
MISO, Southwest Power Pool, PJM Interconnection, LLC and Southeast regions and was formed in 2003
as a successor organization of the Power and Energy Market of MAPP. Power pool sales are conducted
continuously through MEMA in accordance with schedules filed by MEMA with the FERC.
MRO
: The Utility is a member of the Midwest Reliability Organization (MRO). The MRO, a
non-profit organization that replaced the MAPP Regional Reliability Council, is one of 8 Regional
Reliability Councils that comprise the NERC. The MRO is a voluntary organization committed to
ensuring the reliability of the bulk power system in the Midwest part of North America. The MRO,
through its balanced stakeholder board with independent oversight, operates independently from any
member, market participant or operator, so that the standards developed and enforced by the MRO are
fair and administered without undue influence from market participants. The MRO is approximately
40% larger in terms of net end use load than MAPP. The MRO region includes more than 40 members
supplying approximately 280 million megawatt-hours to more than 20 million people. Its membership
is comprised of municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown Corporations and independent
power producers.
13
MISO
: The Utility is a member of the MISO. As expressed in FERC Order No. 2000, FERC’s
view is that independent regional transmission organizations will benefit the public interest by
enhancing the reliability of the electric grid and providing unbiased regional grid management,
nondiscriminatory operation of the bulk power transmission system and open access to the
transmission facilities under MISO’s functional supervision. The MISO covers a broad region
containing all or parts of 20 states and one Canadian province. The MISO began operational control
of the Utility’s transmission facilities above 100 kV on February 1, 2002 but the Utility continues
to own and maintain its transmission assets. As the transmission provider and security coordinator
for the region, the MISO seeks to optimize the efficiency of the interconnected system, provide
regional solutions to regional planning needs and minimize risk to reliability through its security
coordination, long-term regional planning, market monitoring, scheduling and tariff administration
functions.
The MISO Energy Markets commenced operation on April 1, 2005. Through its Energy Markets, MISO
seeks to develop options for energy supply, increase utilization of transmission assets, optimize
the use of energy resources across a wider region and provide greater visibility of data. MISO aims
to facilitate a more cost-effective and efficient use of the wholesale bulk electric system. The
MISO Energy Market is intended to improve efficiency and price transparency, which may reduce the
Utility’s opportunity for traditional marketing profits. The effects of the MISO Energy Market on
the Utility’s retail customers, including costs to those customers, and the Utility’s wholesale
margins are expected to vary through the transition.
Other:
The Utility is subject to various federal and state laws, including the
Federal Public Utility Regulatory Policies Act and the Energy Policy Act of 1992, which are
intended to promote the conservation of energy and the development and use of alternative energy
sources, and the 2005 Energy Act described above.
Competition, Deregulation and Legislation
Electric sales are subject to competition in some areas from municipally owned systems, rural
electric cooperatives and, in certain respects, from on-site generators and cogenerators.
Electricity also competes with other forms of energy. The degree of competition may vary from time
to time depending on relative costs and supplies of other forms of energy. The Utility may also
face competition as the restructuring of the electric industry evolves.
The Company believes the Utility is well positioned to be successful in a more competitive
environment. A comparison of the Utility’s electric retail rates to the rates of other
investor-owned utilities, cooperatives and municipals in the states the Utility serves indicates
that the Utility’s rates are competitive. In addition, the Utility would attempt more flexible
pricing strategies under an open, competitive environment.
Legislative and regulatory activity could affect operations in the future. The Utility cannot
predict the timing or substance of any future legislation or regulation. There has been no
legislative action regarding electric retail choice in any of the states where the Utility
operates. The Minnesota legislature is considering legislation which would regulate holding
companies doing business within the state that include in the ownership chain a public utility. The
legislation would limit the non-utility assets of the holding company as a whole, to 25% of total
assets. This legislation, if passed in its present form, could limit the Company’s ability to
maintain and grow its nonelectric businesses. The Company does not expect retail competition to
come to the States of Minnesota, North Dakota or South Dakota in the foreseeable future.
The Utility is unable to predict the impact on its operations resulting from future regulatory
activities, from future legislation or from future taxes that may be imposed on the source or use
of energy.
14
Environmental Regulation
Impact of Environmental Laws
: The Utility’s existing generating plants are subject to
stringent federal and state standards and regulations regarding, among other things, air, water and
solid waste pollution. In the five years ended December 31, 2006 the Utility invested
approximately $10.8 million in environmental control facilities. The 2007 construction budget
includes approximately $12.4 million for environmental equipment for existing facilities. The
Utility’s share of environmental expenditures for the proposed Big Stone II Plant is estimated to
be $133 million, including the cost of a joint scrubber, which will be shared between the current
Big Stone Plant and the proposed Big Stone II Plant.
Air Quality
: Pursuant to the Federal Clean Air Act of 1970 as amended (the Act), the
United States Environmental Protection Agency (EPA) has promulgated national primary and secondary
standards for certain air pollutants.
The primary fuels burned by the Utility’s steam generating plants are North Dakota lignite
coal and western subbituminous coal. Electrostatic precipitators have been installed at the
principal units at the Hoot Lake Plant. Hoot Lake Plant unit 1 turbine generator, which is the
smallest of the three coal-fired units at Hoot Lake Plant, was retired as of December 31, 2005.
The Utility has retained the unit 1 boiler for use as a source of emergency heat. A fabric filter
collects particulates from stack gases on Hoot Lake Plant unit 1. As a result, the Utility believes
the units at the Hoot Lake Plant currently meet all presently applicable federal and state air
quality and emission standards.
A major portion of the Big Stone Plant’s electrostatic precipitator was replaced in 2002 with
an Advanced Hybrid™ technology that was installed as part of a demonstration project co-funded by
Department of Energy’s National Energy Technology Laboratory Power Plant Improvement Initiative.
The technology is designed to capture at least 99.99% of the fly ash particulates emitted from the
boiler. Initial test data demonstrates the emissions design parameters were met. The Department of
Energy’s National Energy Technology Laboratory, consultants, equipment vendors and the Utility have
assessed the operational performance of the unit and its balance-of-plant impacts as part of the
ongoing effort to refine the demonstration technology. Even though Big Stone Plant co-owners
replaced the remaining four precipitator fields with Advanced Hybrid™ technology in 2005, the
technology continues to impose limits on plant output. The Big Stone Plant co-owners have
evaluated particulate emissions control technology options and have decided to replace the
demonstration project Advanced Hybrid™ technology with a pulse jet baghouse in 2007. The Big Stone
Plant is currently operating within all presently applicable federal and state air quality and
emission standards.
The Coyote Station is equipped with sulfur dioxide removal equipment. The removal
equipment—referred to as a dry scrubber—consists of a spray dryer, followed by a fabric filter,
and is designed to desulfurize hot gases from the stack. The fabric filter collects spray dryer
residue along with the fly ash. The Coyote Station is currently operating within all presently
applicable federal and state air quality and emission standards.
The Act, in addressing acid deposition, imposed requirements on power plants in an effort to
reduce national emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx).
The national SO2 emission reduction goals are achieved through a market-based system under
which power plants are allocated “emissions allowances” that will require plants to either reduce
their emissions or acquire allowances from others to achieve compliance. Each allowance is an
authorization to emit one ton of sulfur dioxide. Sulfur dioxide emission requirements are currently
being met by all of the Utility’s generating facilities without the need to acquire other
allowances for compliance.
The national NOx emission reduction goals are achieved by imposing mandatory emissions
standards on individual sources. Hoot Lake Plant unit 2 is governed by the phase one early opt-in
provision until January 1, 2008. In order to meet the national NOx emission standards required at the
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Hoot Lake Plant unit 2 in 2008, the Utility plans to install low NOx burners and possibly
over-fire air in 2008. The remaining generating units meet the NOx emission regulations that were
adopted by the EPA in December 1996. All of the Utility’s generating facilities met the NOx
standards during 2006.
The EPA Administrator signed the final Interstate Air Quality Rule, also known as the Clean
Air Interstate Rule, on March 10, 2005. EPA has concluded that SO2 and NOx are the chief emissions
contributing to interstate transport of particulate matter less than 2.5 microns (PM2.5). EPA has
also concluded that NOx emissions are the chief emissions contributing to ozone non-attainment.
Twenty-three states and the District of Columbia were found to contribute to ambient air quality
PM2.5 non-attainment in downwind states. On that basis, EPA is proposing to cap SO2 and NOx
emissions in the designated states. Minnesota is included among the twenty-three states for
emissions caps. Twenty-five states were found to contribute to downwind 8-hour ozone
non-attainment. None of the states in the Utility’s service territory are slated for NOx reduction
for ambient air quality 8-hour ozone non-attainment purposes. Based on the Utility’s assessment of
the likely applicable requirements, Hoot Lake Plant units 2 and 3 must either reduce their NOx
emissions to approximately 0.13 pounds per million Btu or purchase NOx allowances for those
emissions in excess of that level beginning in 2009. NOx emissions control equipment was installed
on Hoot Lake Plant unit 3 in 2006 at a cost of approximately $1.9 million. As noted above,
additional NOx emission control equipment is slated for installation in 2008 on Hoot Lake Plant
unit 2 at a similar cost. The Utility expects that the installation of NOx emission control
equipment will allow Hoot Lake Plant units 2 and 3 to reduce the purchase of NOx allowances.
On June 15, 2005, EPA signed the Regional Haze Best Available Retrofit Technology (BART) rule.
The rule requires emissions reductions from designated sources that are deemed to contribute to
visibility impairment in Class I air quality areas. Hoot Lake Plant unit 3 and Big Stone Plant are
units that are potentially subject to emission reduction requirements. The Minnesota Pollution
Control Agency has determined that Hoot Lake Plant unit 3 is not subject to the BART rule. A
similar determination has not been made for Big Stone Plant and it remains potentially subject to
emission reduction requirements. The state rule revisions are due by January 2008. Given the
regulatory uncertainties at this time, it is not possible to assess to what extent this regulation
will impact the Company.
The Act calls for EPA studies of the effects of emissions of listed pollutants by
electric steam generating plants. The EPA has completed the studies and submitted reports to
Congress. The Act required the EPA to make a finding as to whether regulation of emissions of
hazardous air pollutants from fossil fuel-fired electric utility generating units is appropriate
and necessary. On December 14, 2000 the EPA announced that it affirmatively decided to regulate
mercury emissions from electric generating units. The EPA published the proposed mercury rule on
January 30, 2004. The proposal included two options for regulating mercury emission from coal-fired
electric generating units. One option would set technology-based maximum achievable control
technology standards under paragraph 111(d) of the Act. The other option embodies a market-based
cap and trade approach to emissions reduction. The EPA published final rules in May 2005 based on
the cap and trade approach
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On October 28, 2005 the EPA announced a reconsideration of portions of
the final rules. Final rules were published on June 9, 2006 that maintained the cap and trade
approach. The cap and trade approach is being followed by the three states where the Utility’s
coal-fired plants are located. There are, however, unresolved legal challenges to EPA’s mercury
rule. The Utility is currently evaluating its compliance strategy based on EPA’s rule.
In 1998, the EPA announced its New Source Review Enforcement Initiative targeting coal-fired
utilities, petroleum refineries, pulp and paper mills and other industries for alleged violations
of EPA’s New Source Review rules. These rules require owners or operators that construct new major
sources or make major modifications to existing sources to obtain permits and install air pollution
control equipment at affected facilities. The EPA is attempting to determine if emission sources
violated certain provisions of the Act by
making major modifications to their facilities without installing state-of-the-art pollution
controls. On January 2, 2001 the Utility received a request from the EPA, pursuant to Section
114(a) of the Act, to provide certain information relative to past operation and capital
construction projects at the
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Big Stone Plant. The Utility responded to that request. In March 2003
the EPA conducted a review of the plant’s outage records as a follow-up to their January 2001 data
request. A copy of the designated documents was provided to EPA on March 21, 2003. At this time the
Utility cannot determine what, if any, actions will be taken by the EPA. The EPA issued changes to
the existing New Source Review rules with respect to routine maintenance and repair and replacement
activities in its Equipment Replacement Provision Rule on October 27, 2003. However, the U.S. Court
of Appeals for the D.C. Circuit issued an order which stayed the effective date of the Equipment
Replacement Provision rule pending judicial review. In a March 2006 decision the U.S. Court of
Appeals for the D.C. Circuit struck down the EPA’s Equipment Replacement Provision. The EPA
petitioned the original three-judge panel to reconsider its ruling and, at the same time,
petitioned all of the court’s judges to rehear the panel’s decision. In June 2006, the judges
denied both requests. The Department of Justice, on behalf of EPA, and the Utility Air Regulatory
Group filed petitions with the U.S. Supreme Court in November 2006 asking the Court to overturn the
D.C. Circuit Court’s decision to vacate the Equipment Replacement Provision.
On November 20, 2006, the Sierra Club notified the Utility and the two other Big Stone Plant
co-owners of its intent to sue alleging violations of the “Prevention of Significant Deterioration”
(PSD) requirements of the Act at the Big Stone Plant with respect to three past plant activities.
The Sierra Club stated that unless the matter is otherwise fully resolved, it intends to file suit
in the applicable district courts any time 60 days after November 20, 2006. As of the date of this
report on Form 10-K the Sierra Club has not filed suit in the applicable district courts. The
Utility believes that they are in material compliance with all applicable requirements of the Act.
The Coyote Station is subject to certain emission limitations under the PSD program of the
Act. The EPA and the North Dakota Department of Health reached an agreement to identify a process
for resolving several issues relating to the modeling protocol for the state’s PSD program.
Modeling was completed and the results were submitted to the EPA for their review. On April 19,
2005 the North Dakota Department of Health held a Periodic Review Hearing relating to the PSD Air
Quality Modeling Report that was submitted to the EPA. One of the Hearing Officer’s Findings and
Conclusion was that the air quality relating to impacts of SO2 emissions is being adequately
protected and that at 2002-2003 SO2 emission levels the relevant Class I increments are not
violated.
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.
On February 16, 2004 the EPA Administrator signed the final Phase II rule implementing Section
316(b) of the Clean Water Act establishing standards for cooling water intake structures for
certain existing facilities. Hoot Lake Plant is the Utility’s only facility that could be impacted
by this rule. On January 25, 2007 the U.S. Court of Appeals for the Second Circuit remanded
portions of the rule to EPA. The Utility has completed an information collection program for the
Hoot Lake Plant cooling water intake structure, but given the recent Court decision the Utility is
uncertain of the impact on the facility at this time.
The Utility has all federal and state water permits presently necessary for the operation of
the Coyote Station, the Big Stone Plant and the Hoot Lake Plant. The Utility 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 (manufacturer’s expected output) of the
five dams is 3,450 kW.
Solid Waste
: Permits for disposal of ash and other solid wastes have either been
issued or are under renewal for the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.
At the request of the Minnesota Pollution Control Agency (MPCA), the Utility has an ongoing
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investigation at its former, closed Hoot Lake Plant ash disposal sites. The MPCA continues to
monitor site activities under their Voluntary Investigation and Cleanup Program. The Utility
provided a revised focus feasibility study for remediation alternatives to the MPCA in October
2004. The Utility and the MPCA have reached an agreement identifying the remediation technology and
the Utility completed the projects in 2006. The effectiveness of the remediation is currently under
evaluation.
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. To date, the Utility has incurred no
significant costs as a result of these laws. The future total impact on the Utility of the various
solid and hazardous waste statutes and regulations enacted by the federal government or the States
of Minnesota, North Dakota and South Dakota is not certain at this time.
In 1980, the United States enacted the Comprehensive Environmental Response, Compensation and
Liability Act, commonly known as the Federal Superfund law, which was reauthorized and amended in
1986. In 1983, Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly
known as the Minnesota Superfund law. In 1988, South Dakota enacted the Regulated Substance
Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the
Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts
establish environmental response funds to pay for remedial actions associated with the release or
threatened release of certain regulated substances into the environment. These federal and state
Superfund laws also establish liability for cleanup costs and damage to the environment resulting
from such release or threatened release of regulated substances. The Minnesota Superfund law also
creates liability for personal injury and economic loss under certain circumstances. The Utility is
unable to determine the total impact of the Superfund laws on its operations at this time but has
not incurred any significant costs to date related to these laws. The Utility is not presently
named as a potentially responsible party under the federal or state Superfund laws.
Capital Expenditures
The Utility is continually expanding, replacing and improving its electric facilities. During
2006, approximately $35 million was invested for additions and replacements to its electric utility
properties. During the five years ended December 31, 2006 gross electric property additions,
including construction work in progress, were approximately $174.5 million and gross retirements
were approximately $60.9 million.
The Utility estimates that during the five-year period 2007-2011 it will invest approximately
$776 million for electric construction, which includes $360 million for its share of expected
expenditures for construction of the planned Big Stone II electric generating plant and related
transmission assets if all necessary permits and approvals are granted on a timely basis. Other
significant portions of the 2007-2011 capital budget include wind generation projects and upgrades
and extensions to the Utility’s transmission system.
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Franchises
At December 31, 2006 the Utility had franchises to operate as an electric utility in all
incorporated municipalities that it serves. All franchises are nonexclusive and generally were
obtained for 20-year terms, with varying expiration dates. No franchises are required to serve
unincorporated communities in any of the three states that the Utility serves. The Utility believes
that its franchises will be renewed prior to expiration.
Employees
At December 31, 2006 the Utility had approximately 656 equivalent full-time employees. A total
of 473 employees are represented by local unions of the International Brotherhood of Electrical
Workers. These labor contracts were renewed in the fall of 2005 and have expiration dates in the
fall of 2008 and 2009. The Utility has not experienced any strike, work stoppage or strike vote,
and considers its present relations with employees to be good.
PLASTICS
General
Plastics consist of businesses producing polyvinyl chloride (PVC) and polyethylene (PE) pipe.
The Company derived 15%, 16% and 14% of its consolidated operating revenues from the Plastics
segment for each of the three years ended December 31, 2006, 2005 and 2004, respectively. The
Company derived 28%, 26% and 14% of its consolidated income from continuing operations from the
Plastics segment for each of the three years ended December 31, 2006, 2005 and 2004, respectively.
The following is a brief description of these businesses:
Northern Pipe Products, Inc.
, located in Fargo, North Dakota, manufactures and sells
PVC and PE pipe for municipal water, rural water, wastewater, storm drainage systems and
other uses in the Northern, Midwestern and Western regions of the United States as well as
Canada. Production facilities for PVC pipe are located in Fargo, North Dakota and Hampton,
Iowa. The production facility for PE pipe is located in Hampton, Iowa.
Vinyltech Corporation
, located in Phoenix, Arizona, manufactures and sells PVC pipe
for municipal water, wastewater, water reclamation systems and other uses in the Western,
Southwestern and South-central regions of the United States.
Together these companies have the capacity to produce approximately 220 million pounds of PVC
and PE pipe annually.
Customers
The PVC and PE pipe products are marketed through a combination of independent sales
representatives, company salespersons and customer service representatives. Customers for the PVC
and PE pipe products consist primarily of wholesalers and distributors throughout the Upper
Midwest, Southwest and Western United States.
Competition
The plastic pipe industry is highly fragmented and competitive, due to the large number of
producers, the small number of raw material suppliers and the fungible nature of the product. Due
to shipping costs, competition is usually regional, instead of national, in scope. The principal
areas of
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competition are a combination of price, service, warranty and product performance. Northern Pipe and Vinyltech
compete not only against other plastic pipe manufacturers, but also ductile iron, steel, concrete
and clay pipe producers. Pricing pressure will continue to affect operating margins in the future.
Northern Pipe and Vinyltech intend to continue to compete on the basis of their high quality
products, cost-effective production techniques and close customer relations and support.
Manufacturing and Resin Supply
PVC pipe is manufactured through a process known as extrusion. During the production process,
PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is
heated to a molten state and then forced through a sizing apparatus to produce the pipe. The newly
extruded pipe is then pulled through a series of water cooling tanks, marked to identify the type
of pipe and cut to finished lengths. Warehouse and outdoor storage facilities are used to store the
finished product. Inventory is shipped from storage to customers mainly by common carrier.
The PVC resins are acquired in bulk and shipped to point of use by rail car. Over the last
several years, there has been consolidation in PVC resin producers. There are a limited number of
third party vendors that supply the PVC resin used by Northern Pipe and Vinyltech. Two vendors
provided approximately 99% and 97% of total resin purchases in 2006 and 2005, respectively. The
supply of PVC resin may also be limited due to manufacturing capacity and the limited availability
of raw material components. A majority of U.S. resin production plants are located in the Gulf
Coast region, which is subject to risk of damage to the plants and potential shutdown of resin
production because of exposure to hurricanes that occur in that part of the United States. The loss
of a key vendor, or any interruption or delay in the supply of PVC resin, could disrupt the ability
of the Plastics segment to manufacture products, cause customers to cancel orders or require
incurrence of additional expenses to obtain PVC resin from alternative sources, if such sources
were available. Both Northern Pipe and Vinyltech believe they have good relationships with their
key raw material vendors.
Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand
factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical
with significant fluctuations in prices and gross margins.
Capital Expenditures
Capital expenditures in the Plastics segment typically include investments in extrusion
machines, land and buildings and management information systems. During 2006, capital expenditures
of approximately $5 million were made in the Plastics segment. Total capital expenditures for the five-year period
2007-2011 are estimated to be approximately $19 million. Estimated capital expenditures include
approximately $6 million for an expansion at Vinyltech to add a state-of-the-art blending system
and two additional extrusion lines which are expected to increase capacity at that plant by 40%
when operational in 2008.
Employees
At December 31, 2006 the Plastics segment had approximately 192 full-time employees.
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MANUFACTURING
General
Manufacturing consists of businesses engaged in the following activities: production of
waterfront equipment, wind towers, material and handling trays and horticultural containers,
contract machining and metal parts stamping and fabrication.
The Company derived 28%, 25% and 25% of its consolidated operating revenues from the
Manufacturing segment for each of the three years ended December 31, 2006, 2005 and 2004,
respectively. The Company derived 26%, 14% and 19% of its consolidated income from continuing
operations from the Manufacturing segment for each of the three years ended December 31, 2006, 2005
and 2004, respectively. The following is a brief description of each of these businesses:
BTD Manufacturing, Inc. (BTD)
, with headquarters located in Detroit Lakes,
Minnesota, is a metal stamping and tool and die manufacturer that provides its services
mainly to customers in the Midwest. BTD stamps, fabricates, welds and laser cuts metal
components according to manufacturers’ specifications primarily for the recreation vehicle,
gas fireplace, health and fitness and enclosure industries.
DMI Industries, Inc. (DMI)
, located in West Fargo, North Dakota, engineers and
manufactures wind towers and other heavy metal fabricated products. In May 2006 DMI began
producing wind towers at its new manufacturing facility in Fort Erie, Ontario, Canada. As a
result of this expansion, DMI established a wholly-owned subsidiary, DMI Canada, Inc., for
the new Canadian operations.
ShoreMaster, Inc. (ShoreMaster),
with headquarters in Fergus Falls, Minnesota,
produces and markets residential and commercial waterfront equipment, ranging from boatlifts
and docks to full marina systems that are marketed throughout the United States. ShoreMaster
has two wholly-owned subsidiaries, Galva Foam Marine Industries, Inc. and Shoreline
Industries, Inc. ShoreMaster has manufacturing facilities located in Fergus Falls and Pine
River, Minnesota; Adelanto, California; Camdenton, Missouri; and St. Augustine, Florida.
T. O. Plastics, Inc. (T.O. Plastics)
, located in Minneapolis and Clearwater,
Minnesota; and Hampton, South Carolina; manufactures and sells thermoformed products for the
horticulture industry throughout the United States. In addition, T. O. Plastics produces
products such as clamshell packing, blister packs, returnable pallets and handling trays for
shipping and storing odd-shaped or difficult-to-handle parts for other industries.
Competition
The various markets in which the Manufacturing segment entities compete are characterized by
intense competition from both foreign and domestic manufacturers. 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 high-performance products, innovative technologies,
cost-effective manufacturing techniques, close customer relations and support, and increasing
product offerings.
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Raw Materials Supply
The companies in the Manufacturing segment use a variety of raw materials in the products that
they manufacture, including steel, aluminum, resin and concrete. Both pricing increases and
availability of these raw materials are concerns of companies in the Manufacturing segment. The
companies in the Manufacturing segment attempt to pass the increases in the costs of these raw
materials on to their customers. Increases in the costs of raw materials that cannot be passed on
to customers could have a negative affect on profit margins in the Manufacturing segment.
Legislation
The demand for wind towers that are manufactured by DMI depends primarily on the existence of
either renewable portfolio standards or a federal production tax credit for wind energy. A federal
production tax credit is in place through December 31, 2008.
Capital Expenditures
Capital expenditures in the Manufacturing segment typically include additional investments in
new manufacturing equipment or expenditures to replace worn-out manufacturing equipment. Capital
expenditures may also be made for the purchase of land and buildings for plant expansion and for
investments in management information systems. During 2006, capital expenditures of approximately
$20 million were made in the Manufacturing segment. Total capital expenditures for the
Manufacturing segment during the five-year period 2007-2011 are estimated to be approximately $59
million including approximately $7 million for a planned
expansion at DMI’s manufacturing
facility in Ontario, Canada in 2008 that will increase production capacity by 30%.
Employees
At December 31, 2006 the Manufacturing segment had approximately 1,420 full-time employees.
HEALTH SERVICES
General
Health Services consists of the DMS Health Group, which includes businesses involved in the
sale of diagnostic medical equipment, patient monitoring equipment and related supplies and
accessories. These businesses also provide equipment maintenance, diagnostic imaging services, and
rental of diagnostic medical imaging equipment.
The Company derived 12%, 13% and 14% of its consolidated operating revenues from the Health
Services segment for each of the three years ended December 31, 2006, 2005 and 2004, respectively.
The Company derived 4%, 7% and 7% of its consolidated income from continuing operations from the
Health Services segment for each of the three years ended December 31, 2006, 2005 and 2004,
respectively. The companies comprising the DMS Health Group that deliver diagnostic imaging and
healthcare solutions across the United States include:
DMS Health Technologies, Inc. (DMSHT)
, located in Fargo, North Dakota, sells and
services diagnostic medical imaging equipment, cardiac and other patient monitoring
equipment, defibrillators, EKGs and related medical supplies and accessories and provides
ongoing service maintenance. DMSHT sells radiology equipment primarily manufactured by
Philips Medical Systems (Philips), a large multi-national company based in the Netherlands.
Philips manufactures fluoroscopic, radiographic and vascular equipment, along with
ultrasound, computerized tomography (CT), magnetic resonance imaging (MR), positron emission
tomography (PET), PET/CT and cardiac cath labs. The
dealership agreement with Philips can be terminated on 180
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days written notice by either
party for any reason and can be terminated by Philips if certain compliance requirements are
not met. DMSHT is also a supplier of medical film and related accessories. DMSHT markets
mainly to hospitals, clinics and mobile imaging service companies.
DMS Imaging, Inc.
, a subsidiary of DMSHT located in Fargo, North Dakota, operates
diagnostic medical imaging equipment, including CT, MRI, PET and PET/CT and provides nuclear
medicine and other similar radiology services to hospitals, clinics, long-term care
facilities and other medical providers. Regional offices are located in Houston, Texas;
Minneapolis, Minnesota; and Sioux Falls, South Dakota. DMS Imaging, Inc. provides services
through four different business units:
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DMS Imaging — provides shared diagnostic medical imaging services
(primarily mobile) for MR, CT, nuclear medicine, PET, PET/CT, ultrasound,
mammography and bone density analysis.
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DMS Interim Solutions — offers interim and rental options for
diagnostic imaging services.
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DMS MedSource Partners — develops long-term relationships with
healthcare providers to offer dedicated in-house diagnostic imaging
services.
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DMS Portable X-Ray — delivers portable x-ray, ultrasound and
electrocardiography services to nursing homes and other facilities.
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Combined, the DMS Health Group covers the three basics of the medical imaging industry:
(1) ownership and operation of the imaging equipment for healthcare providers; (2) sale, lease
and/or maintenance of medical imaging equipment and related supplies; and (3) scheduling, billing
and administrative support of medical imaging services.
Regulation
The healthcare industry is subject to federal and state regulations relating to licensure,
conduct of operation, ownership of facilities, payment of services and expansion or addition of
facilities and services.
The federal Anti-Kickback Statute prohibits persons from knowingly and willfully soliciting,
receiving, offering or providing remuneration, directly or indirectly, to induce the referral of an
individual or the furnishing or arranging for a good or service for which payment may be made under
a federal healthcare program such as Medicare or Medicaid. Several states have similar statutes.
The term “remuneration” has been broadly interpreted to include anything of value, including, for
example, gifts, discounts, credit arrangements, payments of cash, waiver of payments and ownership
interests. Penalties for violating the Anti-Kickback Statute can include both criminal and civil
sanctions as well as possible exclusion from participating in Medicare and other federal healthcare
programs. By regulation, the U.S. Department of Health and Human Services has created certain “safe
harbors” under the Statute. These safe harbors set forth certain provisions, which, if met, assure
that healthcare providers will not be subject to liability under the Statute.
The Ethics and Patient Referral Act of 1989 (Stark Law) prohibits a physician from making
referrals for certain designated health services payable under Medicare, including services
provided by the Health Services companies, to an entity with which the physician has a financial
relationship, unless certain exceptions apply. The Stark Law also prohibits an entity from billing
for designated health services pursuant to a prohibited referral. A person who engages in a scheme
to violate the Stark Law or a person who presents a claim to Medicare in violation of the Stark Law
may be subject to civil fines and possible exclusion from participation in federal healthcare
programs.
Some federal courts have held that a violation of the Anti-Kickback Statute or the Stark Law
can serve as the basis for a claim under the Federal False Claims
Act. A suit under the Federal
False Claims
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Act can be brought directly by the United States Department of Justice, or can be
brought by a “whistleblower.” A whistleblower brings suit on behalf of themselves and the United
States, and the whistleblower is awarded a percentage of any recovery.
Enforcement actions regarding relationships among physicians and providers of imaging services
have highlighted the importance of compliance with the Anti-Kickback Statute and the Stark Law. The
Health Services companies believe their operations comply with the Anti-Kickback Statute and the
Stark Law. However, if the Health Services companies were to engage in conduct in violation of
these statutes, the sanction imposed could adversely affect the Company’s consolidated financial
results.
The Health Insurance Portability and Accountability Act of 1996 (HIPAA) created federal crimes
related to healthcare fraud and to making false statements related to healthcare matters. HIPAA
prohibits knowingly and willfully executing a scheme to defraud any healthcare benefit program
including a program involving private payors. Further, HIPAA prohibits knowingly and willfully
falsifying, concealing or covering up a material fact or making any materially false statement in
connection with the delivery of or payment for healthcare benefits or services. A violation of
HIPAA is a felony and may result in fines, imprisonment or exclusion from government-sponsored
programs such as Medicare and Medicaid. Finally, HIPAA creates federal privacy standards for
individually identifiable health information and computer security standards for all health
information. The Health Services companies believe that they are in compliance with the
requirements of HIPAA. However, if the Health Services companies were to engage in conduct in
violation of these statutes, the sanction imposed could adversely affect the Company’s financial
results.
In some states a certificate of need or similar regulatory approval is required prior to the
acquisition of high-cost capital items or services, including diagnostic imaging systems or the
provision of diagnostic imaging services by companies or its customers. Certificate of need laws
were enacted to contain rising healthcare costs by preventing unnecessary duplication of health
resources. Certificate of need regulations may limit or preclude the Health Services companies from
providing diagnostic imaging services or systems. Conversely, a repeal of existing certificate of
need regulations in states where the Health Services companies have obtained certificates of need
could adversely affect their financial performance.
DMS Imaging, Inc. maintains Independent Diagnostic Testing Facilities (IDTFs) that enroll in
the Medicare program as participating Medicare suppliers, so that they may receive reimbursement
directly from the Medicare program for services provided to Medicare beneficiaries. In 2006 the
Centers for Medicare and Medicaid Services (CMS) adopted new federal regulations to increase
oversight of IDTFs and ensure quality care for Medicare beneficiaries. These new regulations
impose additional requirements and restrictions on DMS Imaging, Inc. Some of the new requirements
include new physical facility standards for adequate patient privacy accommodations, storage of
medical records and hand washing facilities. Other new requirements include a mandated
comprehensive liability insurance policy of at least $300,000 per IDTF site, a requirement that all
diagnostic testing equipment be available for inspection by CMS within two business days, a
requirement that all changes in equipment, technicians, supervising physicians or other enrollment
information be provided to CMS on an updated enrollment application within 30 days of the change,
and a requirement that all technical staff on duty must have appropriate credentials to perform
tests. In addition, IDTFs are prohibited from directly soliciting patients. Some of these new
requirements may make it more difficult for the IDTFs to find supervising physicians to oversee the
clinical operations of the IDTFs. If IDTFs maintained by DMS Imaging, Inc. are unable to comply
with one or more of these requirements, CMS may revoke Medicare billing privileges for those IDTFs,
which may impact the financial performance of the Health Services companies.
In 2007 CMS issued a Medicare transmittal that would impose further requirements on IDTFs,
such as prohibitions on sharing space or equipment with any other Medicare supplier. CMS has
rescinded this transmittal, so IDTFs need not comply with those new proposed requirements.
However, CMS may
24
seek to impose the same or different requirements and limitations on IDTFs through future rulemakings
or Medicare transmittals. An inability to comply with any new IDTF standards may impact the
revenue of the Health Services companies.
Additional federal and state regulations that the Health Services companies are subject to
include state laws that prohibit the practice of medicine by non-physicians and prohibit
fee-splitting arrangements involving physicians; federal Food and Drug Administration requirements;
state licensing and certification requirements and federal and state laws governing diagnostic
imaging and therapeutic equipment. Courts and regulatory authorities have not fully interpreted a
significant number of the current laws and regulations.
The Health Services companies continue to monitor developments in healthcare law and modify
their operations from time to time as the business and regulatory environment changes. However,
there can be no assurances that the Health Services companies will always be able to modify their
operations to address changes in the regulatory environment without any adverse effect to their
financial performance.
Reimbursement
The companies in the Health Services segment derive significant revenue from direct billings
to customers and third-party payors such as Medicare, Medicaid, managed care and private health
insurance companies for their diagnostic imaging services. The Health Services’ customers are
primarily healthcare providers who receive the majority of their payments from third-party payors.
Payments by third-party payors to such healthcare providers depend, in part, upon their patients’
health insurance policies.
New Medicare regulations reduced 2006 Medicare reimbursement for certain imaging services
performed on contiguous body parts during the same day. In addition, the Deficit Reduction Act of
2006 (the DRA) limits reimbursement for imaging services provided in physician offices and in
free-standing imaging centers to the reimbursement amount for that same service when provided in a
hospital outpatient department. This DRA provision impacts a small number of imaging services
provided by the Health Services segment. Federal and state legislatures may seek additional cuts in
Medicare and Medicaid programs that could impact the value of the services provided by the Health
Services segment.
Competition
The market for selling, servicing and operating diagnostic imaging services, patient
monitoring equipment and imaging systems is highly competitive. In addition to direct competition
from other providers of items and services similar to those offered by the Health Services
companies, the companies within Health Services compete with free-standing imaging centers and
health care providers that have their own diagnostic imaging systems, as well as with equipment
manufacturers that sell imaging equipment directly to healthcare providers for permanent
installation. Some of the direct competitors, which provide contract MR and PET/CT services, have
access to greater financial resources than the Health Services companies. In addition, some of
Health Services’ customers are capable of providing the same services to their patients directly,
subject only to their decision to acquire a high-cost diagnostic imaging system, assume the
financial and technology risk, and employ the necessary technologists, rather than obtain the
services from the Health Services company. The Health Services companies may also experience
greater competition in states that currently have certificate of need laws if such laws were
repealed, thereby reducing barriers to entry and competition in that state. The Health Services
companies compete against other similar providers on the basis of quality of services, quality and
magnetic field strength of imaging systems, relationships with health care providers, knowledge and
service quality of technologists, price, availability and reliability.
25
Environmental, Health or Safety Laws
PET, PET/CT and nuclear medicine services require the use of radioactive material. While this
material has a short life and quickly breaks down into inert, or non-radioactive substances, using
such materials presents the risk of accidental environmental contamination and physical injury.
Federal, state and local regulations govern the storage, use and disposal of radioactive material
and waste products. The Company believes that its safety procedures for storing, handling and
disposing of these hazardous materials comply with the standards prescribed by law and regulation;
however the risk of accidental contamination or injury from those hazardous materials cannot be
completely eliminated. The companies in the Health Services segment have not had any material
expenses related to environmental, health or safety laws or regulations.
Capital Expenditures
Capital expenditures in this segment principally relate to the acquisition of diagnostic
imaging equipment used in the imaging business. During 2005, capital expenditures of approximately
$5 million were made in the Health Services segment. Total capital expenditures during the
five-year period 2007-2011 are estimated to be approximately $12 million. Operating leases are also
used to finance the acquisition of medical equipment used by Health Services companies. Current
operating lease commitments during the five-year period 2007-2011 are estimated to be $123 million.
Employees
At December 31, 2006 the Health Services segment had approximately 408 full-time employees.
FOOD INGREDIENT PROCESSING
General
Food ingredient processing consists of IPH, which was acquired by the Company on August 18,
2004. IPH headquartered in Ririe, Idaho, manufactures and supplies dehydrated potato products to
food manufacturers in the snack food, foodservice and bakery industries. IPH has three processing
facilities located in Ririe, Idaho; Center, Colorado; and Souris, Prince Edward Island, Canada.
Together these three facilities have the capacity to process approximately 113 million pounds of
potatoes annually.
The Company derived 4%, 4% and 2% of its consolidated operating revenues from the Food
Ingredient Processing segment for each of the years ended December 31, 2006, 2005 and 2004,
respectively. This segment’s contribution to consolidated income from continuing operations for
each of three years ended December 31, 2006, 2005 and 2004 was (8%), 1% and 1%, respectively.
Customers
IPH sells to customers in the United States, Mexico and Canada and exports products to Europe,
the Middle East, the Pacific Rim and Central America. Products are sold through company sales
persons and broker sales representatives. Customers include end users in the food ingredient
industries and distributors to the food ingredient industries and foodservice industries, both
domestically and internationally.
Competition
The market for processed, dehydrated potato flakes, flour and granules is highly competitive.
The ability to compete depends on superior product quality, competitive product pricing and strong
customer relationships. IPH competes with numerous manufacturers and dehydrators of varying sizes
in the United
26
States, including companies with greater financial resources.
Potato Supply
The principal raw material used by IPH is washed process-grade potatoes from fresh packing
operations and growers. These potatoes are unsuitable for use in other markets due to
imperfections. They do not meet United States Department of Agriculture’s general requirements and
expectations for size, shape or color. While IPH has processing capabilities in three
geographically distinct growing regions, there can be no assurance it will be able to obtain raw
materials due to poor growing conditions, a loss of key growers and other factors. A loss of raw
materials or the necessity of paying much higher prices for raw materials could adversely affect
the financial performance of IPH.
Regulations
IPH is regulated by the United States Department of Agriculture and the Federal Food and Drug
Administration and other federal, state, local and foreign governmental agencies relating to the
quality of products, sanitation, safety and environmental control. IPH adheres to strict
manufacturing practices that dictate sanitary conditions conducive to a high quality food product.
All facilities use wastewater systems that are regulated by government environmental agencies in
their respective locations and are subject to permitting by these agencies. IPH believes that it
complies with applicable laws and regulations in all material respects, and that continued
compliance with such laws and regulations will not have a material effect on its capital
expenditures, earnings or competitive position.
Capital Expenditures
Capital expenditures in the Food Ingredient Processing segment typically include additional
investments in new dehydration equipment or expenditures to replace worn-out equipment. Capital
expenditures may also be made for the purchase of land and buildings for plant expansion and for
investments in management information systems. During 2006, capital expenditures of approximately
$2 million were made in the Food Ingredient Processing segment. Total capital expenditures for the
Food Ingredient Processing segment during the five-year period 2007-2011 are estimated to be
approximately $17 million.
Employees
At December 31, 2006 the Food Ingredient Processing segment had approximately 370 full-time
employees.
OTHER BUSINESS OPERATIONS
General
Other Business Operations consists of businesses in residential, commercial and
industrial electric contracting industries; fiber optic and electric distribution systems;
wastewater,
and HVAC systems construction; transportation and energy services as well as the portion of
corporate general and administrative expenses that are not allocated to the other segments.
The Company derived 13%, 10% and 12% of its consolidated operating revenues from the Other
Business Operations segment for each of the years ended December 31, 2006, 2005 and 2004,
respectively. Due primarily to the inclusion of the unallocated corporate general and
administrative expenses, this segment’s contribution to consolidated income from continuing
operations for each of three years ended December 31, 2006, 2005 and 2004 was 2%, (17%) and (19%),
respectively. Excluding unallocated corporate general and administrative expenses, this segment’s
contribution to consolidated income from continuing operations for each of the three years ended
December 31, 2006, 2005 and 2004
27
was 10%, (1%) and (2%), respectively. Following is a brief description of the businesses included in this
segment.
Foley Company
, headquartered in Kansas City, Missouri, provides mechanical and prime
contracting services for water and wastewater treatment plants, power generation plants,
hospital and pharmaceutical facilities, and other industrial and manufacturing projects
across a multi-state service area in the Central United States.
Midwest Construction Services, Inc. (MCS)
, located in Moorhead, Minnesota, is a
holding company for five subsidiaries that provide security products, electrical design and
construction services for the industrial, commercial and municipal business markets,
including government, institutional, communications, utility and renewable energy projects
primarily in the Upper Midwest.
Otter Tail Energy Services Company
, headquartered in Fergus Falls, Minnesota,
provides technical and engineering services and energy efficient lighting primarily in North
Dakota and Minnesota.
E. W. Wylie Corporation (Wylie)
, located in Fargo, North Dakota, is a contract and
common carrier operating a fleet of tractors and trailers in 48 states and 6 Canadian
provinces. Wylie has trucking terminals in Fargo, North Dakota; Des Moines, Iowa; Fort
Worth, Texas and Chicago, Illinois.
Competition
Each of the businesses in Other Business Operations is subject to competition, as well as the
effects of general economic conditions in their respective industries. The construction companies
in this segment must compete with other construction companies in the Upper Midwest and the Central
regions of the United States, including companies with greater financial resources, when bidding on
new projects. The Company believes the principal competitive factors in the construction segment
are price, quality of work and customer services.
The trucking industry, in which Wylie competes, is highly competitive. Wylie competes
primarily with other short- to medium-haul, flatbed truckload carriers, internal shipping conducted
by existing and potential customers and, to a lesser extent, railroads. Competition for the freight
transported by Wylie is based primarily on service and efficiency and to a lesser degree, on
freight rates. There are other trucking companies that have greater financial resources, operate
more equipment or carry a larger volume of freight than Wylie and these companies compete with
Wylie for qualified drivers.
Capital Expenditures
Capital expenditures in this segment typically include investments in additional trucks,
flatbed trailers and construction equipment. During 2006, capital expenditures of approximately $2
million were made in Other Business Operations. Capital expenditures during the five-year period
2007-2011 are estimated to be approximately $6 million for Other Business Operations. Operating
leases are also used to finance the acquisition of trucks used by Wylie. Current operating lease
commitments during the five-year period 2007-2011 are estimated to be $5 million.
28
Employees
At
December 31, 2006 there were approximately 659 full-time employees in Other Business
Operations. Moorhead Electric, Inc., a subsidiary of MCS, has 82 employees represented by local
unions of the International Brotherhood of Electrical Workers and covered by a labor contract that
expires on May 31, 2007. Foley Company has 192 employees represented by various unions, including
Boilermakers, Carpenters and Millwrights, Cement Masons, Operating Engineers, Pipe Fitters and
Plumbers and Teamsters. Foley has several labor contracts with various expiration dates in 2007 and
2008. Moorhead Electric, Inc. and Foley Company have not experienced any strike, work stoppage or
strike vote, and consider their present relations with employees to be good.
Forward-Looking Information — Safe Harbor Statement Under the
Private Securities Litigation Reform Act of 1995
This Annual Report on Form 10-K contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995 (the Act). 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. Such statements are based on current expectations and
assumptions, and entail various risks and uncertainties that could cause actual results to differ
materially from those expressed in such forward- looking statements.
The following factors, among others, could cause actual results for the Company to differ
materially from those discussed in the forward-looking statements:
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•
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The Company is subject to federal and state legislation, government regulations and
regulatory actions that may have a negative impact on its business and results of
operations.
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•
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The Company may not be able to respond effectively to deregulation initiatives in the
electric industry, which could result in reduced revenues and earnings.
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•
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Future operating results of the Electric segment will be impacted by the outcome of a
rate case to be filed in Minnesota in late 2007.
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Certain MISO-related costs currently included in the FCA in Minnesota retail rates may
be excluded from recovery through the FCA and subject to future recovery through rates
established in a general rate case.
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Weather conditions can adversely affect the Company’s operations and revenues.
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Electric wholesale margins could be further reduced as the MISO market becomes more
efficient.
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•
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Electric wholesale trading margins could be reduced or eliminated by losses due to
trading activities.
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•
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The Company’s electric generating facilities are subject to operational risks that
could result in unscheduled plant outages, unanticipated operation and maintenance
expenses and increased power purchase costs.
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•
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Wholesale sales of electricity from excess generation could be reduced by reductions in
coal shipments to the Big Stone and Hoot Lake plants due to supply constraints or rail
transportation problems beyond the Company’s control
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•
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The Utility has capitalized $6.1 million in costs related to the planned construction
of a second electric generating unit at its Big Stone Plant site as of December 31, 2006.
Should approvals of permits not be received on a timely basis, the project could be at
risk. If the project is abandoned for permitting or other reasons these capitalized costs
and others incurred in future periods may be subject to expense and may not be
recoverable.
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29
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•
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DMI Industries operates in a market that has been dependent on the federal production
tax credit. This tax credit is currently in place through December 31, 2008. Should this
tax credit not be extended or renewed, the revenues and earnings of this business and the
Company’s electrical contractor could be adversely effected.
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Federal and state environmental regulation could cause the Company to incur substantial
capital expenditures which could result in increased operating costs.
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•
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The Company’s plans to grow and diversify through acquisitions may not be successful
and could result in poor financial performance.
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The Company’s plan to grow its nonelectric businesses could be limited by state law.
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Competition is a factor in all of the Company’s businesses.
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Economic uncertainty could have a negative impact on the Company’s future revenues and
earnings.
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Volatile financial markets could restrict the Company’s ability to access capital and
could increase borrowing costs and pension plan expenses.
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The price and availability of raw materials could affect the revenues and earnings of
the Company’s Manufacturing segment.
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The Company’s Food Ingredient Processing segment operates in a highly competitive
market and is dependent on adequate sources of raw materials for processing. Should the
supply of these raw materials be affected by poor growing conditions, this could
negatively impact the results of operations for this segment. This segment could also be
impacted by foreign currency changes between Canadian and United States currency and
prices of natural gas.
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The Company’s Plastics segment is highly dependent on a limited number of vendors for
PVC resin, many of which are located in the Gulf Coast region, and a limited supply of
resin. The loss of a key vendor or an interruption or delay in the supply of PVC resin
could result in reduced sales or increased costs for this segment. Reductions in PVC resin
prices could negatively impact PVC pipe prices, profit margins on PVC pipe sales and the
value of PVC pipe held in inventory.
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Changes in the rates or methods of third-party reimbursements for diagnostic imaging
services could result in reduced demand for those services or create downward pricing
pressure, which would decrease revenues and earnings for the Company’s Health Services
segment.
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The Company’s Health Services businesses may not be able to retain or comply with the
dealership arrangement and other agreements with Philips Medical.
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A significant failure or an inability to properly bid or perform on projects by the
Company’s construction businesses could lead to adverse financial results.
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A further discussion of risk factors and cautionary statements is set forth under “Risk Factors and
Cautionary Statements” and “Critical Accounting Policies Involving Significant Estimates” in
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” on pages 26
through 32 of the Company’s 2006 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 forward-looking statement or contained in any subsequent filings
by the Company with the Securities and Exchange Commission. The Company undertakes no obligation to
correct or update any forward-looking statement, whether as a result of new information, future
events or otherwise.
Item 1A.
RISK FACTORS
The information required by this Item is incorporated by reference to “Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Risk Factors and Cautionary
Statements” on Pages 26 through 30 of the Company’s 2006 Annual Report to Shareholders, filed as
an Exhibit hereto.
30
Item 1B.
UNRESOLVED STAFF COMMENTS
None.
Item 2.
PROPERTIES
The Coyote Station, which commenced operation in 1981, is a 414,000 kW (nameplate rating)
mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned
by the Utility, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern
Public Service Company. The Utility is the operating agent of the Coyote Station and owns 35% of
the plant.
The Utility, jointly with Northwestern Public Service Company and Montana-Dakota Utilities
Co., owns the 414,000 kW (nameplate rating) Big Stone Plant in northeastern South Dakota which
commenced operation in 1975. The Utility is the operating agent of Big Stone Plant and owns 53.9%
of the plant.
Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of three separate
generating units with a combined nameplate rating of 127,000 kW. The oldest Hoot Lake Plant
generating unit was constructed in 1948 (7,500 kW nameplate rating) and was retired on December 31,
2005. A second unit was added in 1959 (53,500 kW nameplate rating) and a third unit was added in
1964 (66,000 kW nameplate rating) and modified in 1988 to provide cycling capability, allowing this
unit to be more efficiently brought online from a standby mode.
As of December 31, 2006 the Utility’s transmission facilities, which are interconnected with
lines of other public utilities, consisted of 48 miles of 345 kV lines; 405 miles of 230 kV lines;
799 miles of 115 kV lines; and 4,039 miles of lower voltage lines, principally 41.6 kV. The Utility
owns the uprated portion of the 48 miles of the 345 kV line, with Minnkota Power Cooperative
retaining title to the original 230 kV construction.
In addition to the properties mentioned above, the Company owns and has investments in offices
and service buildings. The Company’s subsidiaries own facilities and equipment used to manufacture
PVC pipe, produce dehydrated potato products and perform metal stamping, fabricating and contract
machining; construction equipment and tools; medical imaging equipment and a fleet of flatbed
trucks and trailers.
Management of the Company believes the facilities and equipment described above are adequate
for the Company’s present businesses.
All of the common shares of the companies owned by Varistar are pledged to secure indebtedness
of Varistar.
Item 3.
LEGAL PROCEEDINGS
The Company is the subject of various pending or threatened legal actions and proceedings in
the ordinary course of its business. Such matters are subject to many uncertainties and to
outcomes that are not predictable with assurance. The Company records a liability in its
consolidated financial statements for costs related to claims, including future legal costs,
settlements and judgments, where it has assessed that a loss is probable and an amount can be
reasonably estimated. The Company believes the final resolution of currently pending or threatened
legal actions and proceedings, either individually or in the aggregate, will not have a material
adverse effect on the Company’s consolidated financial position, results of operations or cash
flows.
31
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, 2006.
Item 4A.
EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF MARCH 1, 2007)
Set forth below is a summary of the principal occupations and business experience during the
past five years of the executive officers as defined by rules of the Securities and Exchange
Commission. Except as noted below, each of the executive officers has been employed by the Company
for more than five years in an executive or management position either with the Company or its
wholly-owned subsidiary, Varistar.
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NAME AND AGE
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DATES ELECTED TO OFFICE
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PRESENT
POSITION AND BUSINESS EXPERIENCE
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John D. Erickson (48)
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4/8/02
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Present:
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President and Chief
Executive Officer
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Prior to
4/8/02
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President
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George A. Koeck (54)
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4/10/00
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Present:
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Corporate Secretary
and General Counsel
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Lauris N. Molbert (49)
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6/10/02
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Present:
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Executive Vice President and
Chief Operating Officer
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Prior to
6/10/02
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Executive Vice President, Corporate Development
and Varistar President and Chief
Operating Officer
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Kevin G. Moug (47)
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4/9/01
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Present:
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Chief Financial Officer and
Treasurer
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Charles S. MacFarlane (42)
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5/1/03
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President, Otter Tail Power Company
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6/1/02
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Interim President, Otter Tail Power Company
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1/29/02
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Director, Finance & Strategic Planning,
Otter Tail Power Company
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Prior to
1/20/02
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Director, Finance Planning,
Otter Tail Power Company
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With the exception of Charles S. MacFarlane, the term of office for each of the executive
officers is one year and any executive officer elected may be removed by the vote of the Board of
Directors at any time during the term. Mr. MacFarlane is not appointed by the Board of Directors.
Mr. MacFarlane is a son of John MacFarlane, who is the Chairman of the Board of Directors. There
are no other family relationships between any of the executive officers.
32
PART II
Item 5.
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
The information required by this Item is incorporated by reference to the first sentence under
“Otter Tail Corporation stock listing” on Page 64, to “Selected Consolidated Financial Data” on
Page 17 and to “Quarterly Information” on Page 61 of the Company’s 2006 Annual Report to
Shareholders, filed as an Exhibit hereto. The Company did not repurchase any equity securities
during the three months ended December 31, 2006.
PERFORMANCE GRAPH
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
The graph below compares the cumulative total shareholder return on the Company’s common
shares for the last five fiscal years with the cumulative return of the NASDAQ Stock Market Index
and the Edison Electric Institute Index (EEI) over the same period (assuming the investment of $100
in each vehicle on December 31, 2001, and reinvestment of all dividends).
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2001
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2002
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2003
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2004
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2005
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2006
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OTC
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$
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100
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$
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95.83
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$
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99.11
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$
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98.72
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$
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116.59
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$
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130.37
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EEI
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$
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100
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$
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85.27
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$
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105.29
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$
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129.34
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$
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150.10
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$
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181.25
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NASDAQ
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$
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100
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$
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69.13
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$
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103.36
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$
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112.49
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$
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114.88
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$
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126.22
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Item 6.
SELECTED FINANCIAL DATA
The information required by this Item is incorporated by reference to “Selected Consolidated
Financial Data” on Page 17 of the Company’s 2006 Annual Report to Shareholders, filed as an Exhibit
hereto.
33
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The information required by this Item is incorporated by reference to “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” on Pages 18 through 33 of the
Company’s 2006 Annual Report to Shareholders, filed as an Exhibit hereto.
Item 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is incorporated by reference to “Quantitative and
Qualitative Disclosures About Market Risk” on Pages 29 and 30 of the Company’s 2006 Annual Report
to Shareholders, filed as an Exhibit hereto.
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item is incorporated by reference to “Quarterly Information”
on Page 61, the Company’s audited financial statements on Pages 35 through 61 and “Report of
Independent Registered Public Accounting Firm” on Page 34 of the Company’s 2006 Annual Report to
Shareholders, filed as an Exhibit hereto.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
Item 9A.
CONTROLS AND PROCEDURES
Under the supervision and with the participation of the Company’s management, including the
Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of
the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange Act)) as of December 31, 2006, the end of
the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the Company’s disclosure controls and procedures were effective as
of December 31, 2006.
There were no changes in the Company’s internal control over financial reporting (as defined
in Rules 13a-15(f) under the Exchange Act) during the fourth quarter ended December 31, 2006 that
has materially affected, or is reasonably likely to materially affect, the Company’s internal
control over financial reporting.
The annual report of the Company’s management on internal control over financial reporting is
incorporated by reference to “Management’s Report Regarding Internal Controls Over Financial
Reporting” on Page 33 of the Company’s 2006 Annual Report to Shareholders, filed as an Exhibit
hereto. The attestation report of Deloitte & Touche LLP, the Company’s independent registered
public accounting firm, regarding the Company’s internal control over financial reporting is
incorporated by reference to “Report of Independent Registered Public Accounting Firm” on Page 34
of the Company’s 2006 Annual Report to Shareholders, filed as an Exhibit hereto.
34
Item 9B.
OTHER INFORMATION
None.
PART III
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item regarding Directors is incorporated by reference to the
information under “Election of Directors” in the Company’s definitive Proxy Statement for the 2007
Annual Meeting. The information regarding executive officers and family relationships is set forth
in Item 4A hereto. The information regarding Section 16 reporting is incorporated by reference to
the information under “Management’s Security Ownership — Section 16(a) Beneficial Ownership
Reporting Compliance” in the Company’s definitive Proxy Statement for the 2007 Annual Meeting. The
information required by this Item regarding the Company’s procedures for recommending nominees to
the Board of Directors is incorporated by reference to the information under “Meetings and
Committees of the Board of Directors — Corporate Governance Committee” in the Company’s definitive
Proxy Statement for the 2007 Annual Meeting. The information required by this Item in regards to
the Audit Committee is incorporated by reference to the information under “Meetings and Committees
of the Board of Directors — Audit Committee” in the Company’s definitive Proxy Statement for the
2007 Annual Meeting. The information regarding the Company’s Audit Committee financial experts is
incorporated by reference to the information under “Meetings and Committees of the Board — Audit
Committee” in the Company’s definitive Proxy Statement for the 2007 Annual Meeting.
The Company has adopted a code of conduct that applies to all of its directors, officers
(including its principal executive officer, principal financial officer, principal accounting
officer or controller or person performing similar functions) and employees. The Company’s code of
conduct is available on its website at www.ottertail.com. The Company intends to satisfy the
disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a
provision of its code of conduct by posting such information on its website at the address
specified above. Information on the Company’s website is not deemed to be incorporated by reference
into this Annual Report on Form 10-K.
Item 11.
EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information under
“Compensation Discussion and Analysis,” “Report of Compensation Committee,” “Executive
Compensation”, “Director Compensation” and “Director Compensation Table” in the Company’s
definitive Proxy Statement for the 2007 Annual Meeting.
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The information required by this Item regarding security ownership is incorporated by
reference to the information under “Outstanding Voting Shares” and “Management’s Security
Ownership” in the Company’s definitive Proxy Statement for the 2007 Annual Meeting.
35
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2006 about the Company’s common
stock that may be issued under all of its equity compensation plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
|
|
securities
|
|
|
|
|
|
|
|
|
|
|
|
remaining available
|
|
|
|
Number of
|
|
|
|
|
|
for future issuance
|
|
|
|
securities to be
|
|
|
|
|
|
under equity
|
|
|
|
issued upon
|
|
Weighted-average
|
|
compensation plans
|
|
|
|
exercise of
|
|
exercise price of
|
|
(excluding
|
|
|
|
outstanding
|
|
outstanding
|
|
securities
|
|
|
|
options, warrants
|
|
options, warrants
|
|
reflected in column
|
|
Plan Category
|
|
and rights
|
|
and rights
|
|
(a))
|
|
|
|
|
|
|
(a)
|
|
|
|
(b)
|
|
|
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation
plans approved by
security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1999 Stock
Incentive Plan
|
|
|
1,328,291
|
(1)
|
|
$
|
21.15
|
|
|
|
1,338,508
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1999 Employee
Stock Purchase Plan
|
|
|
—
|
|
|
|
N/A
|
|
|
|
449,842
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation
plans not approved
by security holders
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,328,291
|
|
|
$
|
21.15
|
|
|
|
1,788,380
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes 88,050, 75,150 and 23,500 performance based share awards made in 2006, 2005 and
2004, respectively, 38,615 restricted stock units granted in 2006 and 11,738 phantom shares
as part of the deferred director compensation program and excludes 64,441 shares of restricted
stock issued under the 1999 Stock Incentive Plan.
|
|
|
|
(2)
|
|
The 1999 Stock Incentive Plan provides for the issuance of any shares available under the
plan in the form of restricted stock, performance awards and other types of stock-based
awards, in addition to the granting of options, warrants or stock appreciation rights.
|
|
|
|
(3)
|
|
Shares are issued based on employee’s election to participate in the plan.
|
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the information under
“Policy and Procedures Regarding Transactions with Related Persons” and “Election of Directors” in
the Company’s definitive Proxy Statement for the 2007 Annual Meeting.
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information under
“Ratification of Independent Registered Public Accounting Firm — Fees” and “Ratification of
Independent Registered Public Accounting Firm — Pre-approval of Audit/Non-Audit Services Policy”
in the Company’s definitive Proxy Statement for the 2007 Annual Meeting.
36
PART IV
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) List of documents filed:
(1) and (2) See Table of Contents on Page 39 hereof.
(3) See Exhibit Index on Pages 40 through 46 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.
37
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
|
|
OTTER TAIL CORPORATION
|
|
|
|
By
|
/s/ Kevin G. Moug
|
|
|
|
|
Kevin G. Moug
|
|
|
|
|
Chief Financial Officer and Treasurer
|
|
|
|
|
|
Dated:
|
March 1, 2007
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated:
Signature and Title
|
|
|
|
|
|
|
|
|
|
|
|
|
John D. Erickson
|
|
|
)
|
|
|
|
|
|
|
|
|
President and Chief Executive Officer
|
|
|
)
|
|
|
|
|
|
|
|
|
(principal executive officer)
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Kevin G. Moug
|
|
|
)
|
|
|
|
|
|
|
|
|
Chief Financial Officer and Treasurer
|
|
|
)
|
|
|
|
|
|
|
|
|
(principal financial and accounting officer)
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
By
|
|
/s/ John D. Erickson
|
|
|
|
John C. MacFarlane
|
|
|
)
|
|
|
|
|
John D. Erickson
|
|
|
|
Chairman of the Board and Director
|
|
|
)
|
|
|
|
|
Pro Se and Attorney-in-Fact
|
|
|
|
|
|
|
)
|
|
|
|
|
Dated March 1, 2007
|
|
|
|
Karen M. Bohn, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Dennis R. Emmen, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Arvid R. Liebe, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Edward J. McIntyre, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Joyce Nelson Schuette, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Kenneth L. Nelson, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Nathan I. Partain, Director
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
Gary J. Spies, Director
|
|
|
)
|
|
|
|
|
|
|
|
38
OTTER TAIL CORPORATION
TABLE OF CONTENTS
FINANCIAL STATEMENTS, SUPPLEMENTARY FINANCIAL DATA, SUPPLEMENTAL
FINANCIAL SCHEDULES INCLUDED IN ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2006
The following items are incorporated in this Annual Report on Form 10-K by reference to the
registrant’s Annual Report to Shareholders for the year ended December 31, 2006 filed as an Exhibit
hereto:
|
|
|
|
|
|
|
|
|
Page in
|
|
|
|
|
Annual
|
|
|
|
|
Report to
|
|
|
|
|
Shareholders
|
|
|
|
|
|
|
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
Management’s Report Regarding Internal Controls Over Financial Reporting
|
|
|
33
|
|
|
|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
34
|
|
|
|
|
|
|
|
|
Consolidated Statements of Income for the Three Years Ended December 31, 2006
|
|
|
35
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets, December 31, 2006 and 2005
|
|
|
36 & 37
|
|
|
|
|
|
|
|
|
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended
December 31, 2006
|
|
|
38
|
|
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2006
|
|
|
39
|
|
|
|
|
|
|
|
|
Consolidated Statements of Capitalization, December 31, 2006 and 2005
|
|
|
40
|
|
|
|
|
|
|
|
|
Notes to Consolidated Financial Statements
|
|
|
41-61
|
|
|
|
|
|
|
|
|
Selected Consolidated Financial Data for the Five Years Ended December 31, 2006
|
|
|
17
|
|
|
|
|
|
|
|
|
Quarterly Data for the Two Years Ended December 31, 2006
|
|
|
61
|
|
Schedules are omitted because of the absence of the conditions under which they are required,
because the amounts are insignificant or because the information required is included in the
financial statements or the notes thereto.
39
Exhibit Index
to
Annual Report
on Form 10-K
For Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
3-A
|
|
|
8-K
filed 4/10/01
|
|
|
3
|
|
|
—Restated Articles of Incorporation, as amended (including
resolutions creating outstanding series of Cumulative
Preferred Shares).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3-B
|
|
|
|
|
|
|
|
|
—Restated Bylaws, as amended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-A-1
|
|
|
10-K for year
ended 12/31/01
|
|
|
4-D-7
|
|
|
—Note Purchase Agreement dated as of December 1, 2001.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-A-2
|
|
|
10-K for year
ended 12/31/02
|
|
|
4-D-4
|
|
|
—First Amendment dated as of December 1, 2002 to Note
Purchase Agreement dated as of December 1, 2001.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-A-3
|
|
|
10-Q for quarter
ended 9/30/04
|
|
|
4.2
|
|
|
—Second Amendment dated as of October 1, 2004 to Note
Purchase Agreement dated as of December 1, 2001.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-B
|
|
|
8-K filed
5/02/06
|
|
|
4.1
|
|
|
—Credit Agreement, dated as of April 26, 2006, among the
Company, the Banks named therein, U.S. Bank National
Association, as Agent, JPMorgan Chase Bank, N.A., as
Syndication Agent, and Wells Fargo Bank, National
Association, as Documentation Agent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-C
|
|
|
8-K filed 9/06/06
|
|
|
4.1
|
|
|
—Credit Agreement dated as of September 1, 2006, between
Otter Tail Corporation, dba Otter Tail Power Company, and
U.S. Bank National Association.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4-D
|
|
|
8-K filed
2/28/07
|
|
|
4.1
|
|
|
—Note Purchase Agreement, dated as of February 23, 2007,
between Otter Tail Corporation and Cascade Investment L.L.C.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-A
|
|
|
2-39794
|
|
|
4-C
|
|
|
—Integrated Transmission Agreement dated August 25, 1967,
between Cooperative Power Association and the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-A-1
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-A-1
|
|
|
—Amendment No. 1, dated as of September 6, 1979, to
Integrated Transmission Agreement, dated as of August 25,
1967, between Cooperative Power Association and the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-A-2
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-A-2
|
|
|
—Amendment No. 2, dated as of November 19, 1986, to
Integrated Transmission Agreement between Cooperative Power
Association and the Company.
|
-40-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-C-1
|
|
|
2-55813
|
|
|
5-E
|
|
|
—Contract dated July 1, 1958, between Central Power Electric
Corporation, Inc., and the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-C-2
|
|
|
2-55813
|
|
|
5-E-1
|
|
|
—Supplement Seven dated November 21, 1973. (Supplements Nos.
One through Six have been superseded and are no longer in
effect.)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-C-3
|
|
|
2-55813
|
|
|
5-E-2
|
|
|
—Amendment No. 1 dated December 19, 1973, to
Supplement Seven.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-C-4
|
|
|
10-K for year
ended 12/31/91
|
|
|
10-C-4
|
|
|
—Amendment No. 2 dated June 17, 1986, to
Supplement Seven.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-C-5
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-C-5
|
|
|
—Amendment No. 3 dated June 18, 1992, to
Supplement Seven.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-C-6
|
|
|
10-K for year
ended 12/31/93
|
|
|
10-C-6
|
|
|
—Amendment No. 4 dated January 18, 1994 to
Supplement Seven.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-D
|
|
|
2-55813
|
|
|
5-F
|
|
|
—Contract dated April 12, 1973, between the Bureau of
Reclamation and the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-1
|
|
|
2-55813
|
|
|
5-G
|
|
|
—Contract dated January 8, 1973, between East River Electric
Power Cooperative and the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-2
|
|
|
2-62815
|
|
|
5-E-1
|
|
|
—Supplement One dated February 20, 1978.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-3
|
|
|
10-K for year
ended 12/31/89
|
|
|
10-E-3
|
|
|
—Supplement Two dated June 10, 1983.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-4
|
|
|
10-K for year
ended 12/31/90
|
|
|
10-E-4
|
|
|
—Supplement Three dated June 6, 1985.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-5
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-E-5
|
|
|
—Supplement No. Four, dated as of September 10, 1986.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-6
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-E-6
|
|
|
—Supplement No. Five, dated as of January 7, 1993.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-E-7
|
|
|
10-K for year
ended 12/31/93
|
|
|
10-E-7
|
|
|
—Supplement No. Six, dated as of December 2, 1993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F
|
|
|
10-K for year
ended 12/31/89
|
|
|
10-F
|
|
|
—Agreement for Sharing Ownership of Generating Plant by and
between the Company, Montana-Dakota Utilities Co., and
Northwestern Public Service Company (dated as of
January 7, 1970).
|
-41-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-F-1
|
|
|
10-K for year
ended 12/31/89
|
|
|
10-F-1
|
|
|
—Letter of Intent for purchase of share of Big Stone Plant
from Northwestern Public Service Company (dated as of
May 8, 1984).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F-2
|
|
|
10-K for year
ended 12/31/91
|
|
|
10-F-2
|
|
|
—Supplemental Agreement No. 1 to Agreement for Sharing
Ownership of Big Stone Plant (dated as of July 1, 1983).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F-3
|
|
|
10-K for year
ended 12/31/91
|
|
|
10-F-3
|
|
|
—Supplemental Agreement No. 2 to Agreement for Sharing
Ownership of Big Stone Plant (dated as of March 1, 1985).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F-4
|
|
|
10-K for year
ended 12/31/91
|
|
|
10-F-4
|
|
|
—Supplemental Agreement No. 3 to Agreement for Sharing
Ownership of Big Stone Plant (dated as of March 31, 1986).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F-5
|
|
|
10-Q for quarter
ended 9/30/03
|
|
|
10.1
|
|
|
—Supplemental Agreement No. 4 to Agreement for Sharing
Ownership of Big Stone Plant (dated as of April 24, 2003).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-F-6
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-F-5
|
|
|
—Amendment I to Letter of Intent dated May 8, 1984, for
purchase of share of Big Stone Plant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-G
|
|
|
10-Q for quarter
ended 06/30/04
|
|
|
10.3
|
|
|
—Master Coal Purchase and Sale Agreement by and between the
Company, Montana-Dakota Utilities Co., Northwestern
Corporation and Kennecott Coal Sales Company-Big Stone Plant
(dated as of June 1, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-G-1
|
|
|
10-Q for quarter
ended 06/30/04
|
|
|
10.4
|
|
|
—Coal Supply Confirmation Letter by and between the Company,
Montana-Dakota Utilities Co., Northwestern Corporation and
Kennecott Coal Sales Company for shipments of coal from
January 1, 2005 through
December 31, 2007 — Big Stone Plant (dated as of
July 14, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-G-2
|
|
|
10-Q for quarter
ended 06/30/04
|
|
|
10.5
|
|
|
—Coal Supply Agreement by and between the Company,
Montana-Dakota Utilities Co., Northwestern Corporation and
Arch Coal Sales Company, Inc. for the period January 1, 2005
through December 31, 2007 — Big Stone Plant (dated as of July
22, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-H
|
|
|
2-61043
|
|
|
5-H
|
|
|
—Agreement for Sharing Ownership of Coyote Station
Generating Unit No. 1 by and between the Company, Minnkota
Power Cooperative, Inc., Montana-Dakota Utilities Co.,
Northwestern Public Service Company and Minnesota Power &
Light Company (dated as of July 1, 1977).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-H-1
|
|
|
10-K for year
ended 12/31/89
|
|
|
10-H-1
|
|
|
—Supplemental Agreement No. One dated as of November 30,
1978, to Agreement for Sharing Ownership of Coyote Generating
Unit No. 1.
|
-42-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-H-2
|
|
|
10-K for year
ended 12/31/89
|
|
|
10-H-2
|
|
|
—Supplemental Agreement No. 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
ended 12/31/89
|
|
|
10-H-3
|
|
|
—Amendment dated as of July 29, 1983, to Agreement for
Sharing Ownership of Coyote Generating Unit No. 1.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-H-4
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-H-4
|
|
|
—Agreement dated as of September 5, 1985, containing
Amendment No. 3 to Agreement for Sharing Ownership of Coyote
Generating Unit No.1, dated as of July 1, 1977, and Amendment
No. 5 to Coyote Plant Coal Agreement, dated as of January 1,
1978.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-H-5
|
|
|
10-Q for quarter
ended 9/30/01
|
|
|
10-A
|
|
|
—Amendment dated as of June 14, 2001, to Agreement for
Sharing Ownership of Coyote Generating Unit No. 1.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-H-6
|
|
|
10-Q for quarter
ended 9/30/03
|
|
|
10.2
|
|
|
—Amendment dated as of April 24, 2003, to Agreement for
Sharing Ownership of Coyote Generating Unit No. 1.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I
|
|
|
2-63744
|
|
|
5-I
|
|
|
—Coyote Plant Coal Agreement by and between the Company,
Minnkota Power Cooperative, Inc., Montana-Dakota Utilities
Co., Northwestern Public Service Company, Minnesota Power &
Light Company, and Knife River Coal Mining Company (dated as
of January 1, 1978).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I-1
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-I-1
|
|
|
—Addendum, dated as of March 10, 1980, to Coyote Plant Coal
Agreement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I-2
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-I-2
|
|
|
—Amendment (No. 3), dated as of May 28, 1980, to Coyote
Plant Coal Agreement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I-3
|
|
|
10-K for year
ended 12/31/92
|
|
|
10-I-3
|
|
|
—Fourth Amendment, dated as of August 19, 1985 to Coyote
Plant Coal Agreement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I-4
|
|
|
10-Q for quarter
ended 6/30/93
|
|
|
19-A
|
|
|
—Sixth Amendment, dated as of February 17, 1993 to Coyote
Plant Coal Agreement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-I-5
|
|
|
10-K for year
ended 12/31/01
|
|
|
10-I-5
|
|
|
—Agreement and Consent to Assignment of the Coyote Plant
Coal Agreement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-1
|
|
|
10-Q for quarter
ended 06/30/05
|
|
|
10.1
|
|
|
—Big Stone II Power Plant Participation Agreement by and
among the Company, Central Minnesota Municipal Power Agency,
Great River Energy, Heartland Consumers Power District,
Montana-Dakota Utilities Co., a division of MDU Resources
Group, Inc., Southern Minnesota Municipal Power Agency and
Western Minnesota Municipal Power Agency, as Owners (dated as
of June 30, 2005).
|
-43-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-J-1a
|
|
|
10-Q for quarter
ended 6/30/06
|
|
|
10.6
|
|
|
—Amendment No. 1, dated as of June 1, 2006, to
Participation Agreement (dated as of June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-1b
|
|
|
8-K filed 8/31/06
|
|
|
10.1
|
|
|
—Amendment No. 2, dated as of August 18, 2006, to
Participation Agreement (dated as of June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-1c
|
|
|
8-K filed 10/11/06
|
|
|
10.1
|
|
|
—Amendment No. 3, effective September 1, 2006, to
Participation Agreement (dated as of June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-2
|
|
|
10-Q for quarter
ended 06/30/05
|
|
|
10.2
|
|
|
—Big Stone II Power Plant Operation & Maintenance Services
Agreement by and among the Company, Central Minnesota
Municipal Power Agency, Great River Energy, Heartland
Consumers Power District, Montana-Dakota Utilities Co., a
division of MDU Resources Group, Inc., Southern Minnesota
Municipal Power Agency and Western Minnesota Municipal Power
Agency, as Owners, and the Company, as Operator (dated as of
June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-3
|
|
|
10-Q for quarter
ended 06/30/05
|
|
|
10.3
|
|
|
—Big Stone I and Big Stone II 2005 Joint Facilities
Agreement by and among the Company, Central Minnesota
Municipal Power Agency, Great River Energy, Heartland
Consumers Power District, Montana-Dakota Utilities Co., a
division of MDU Resources Group, Inc., NorthWestern
Corporation dba NorthWestern Energy, Southern Minnesota
Municipal Power Agency and Western Minnesota Municipal Power
Agency, as Owners (dated as of June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-J-3a
|
|
|
8-K filed 8/25/06
|
|
|
10.1
|
|
|
—Amendment No. 1, dated as of July 13, 2006, to Joint
Facilities Agreement (dated as of June 30, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-K-1
|
|
|
10-Q for quarter
ended 9/30/99
|
|
|
10
|
|
|
—Power Sales Agreement between the Company and Manitoba
Hydro Electric Board (dated as of July 1, 1999).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-L
|
|
|
10-K for year
ended 12/31/91
|
|
|
10-L
|
|
|
—Integrated Transmission 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
ended 12/31/88
|
|
|
10-L-1
|
|
|
—Amendment No. 1, dated as of December 28, 1988, to
Integrated Transmission Agreement (dated as of
March 31, 1986).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-M
|
|
|
10-Q for quarter
ended 06/30/04
|
|
|
10.1
|
|
|
—Master Coal Purchase Agreement by and between the Company
and Kennecott Coal Sales Company — Hoot Lake Plant (dated as
of December 31, 2001).
|
-44-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-M-1
|
|
|
10-Q for quarter
ended 06/30/04
|
|
|
10.2
|
|
|
—Coal Supply Confirmation Letter by and between the Company
and Kennecott Coal Sales Company for shipments of coal from
July 1, 2004 through December 31, 2007 — Hoot Lake Plant
(dated as of May 26, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-1
|
|
|
10-K for year
ended 12/31/02
|
|
|
10-N-1
|
|
|
—Deferred Compensation Plan for Directors, as amended*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-2
|
|
|
8-K filed
02/04/05
|
|
|
10.1
|
|
|
—Executive Survivor and Supplemental Retirement Plan (2005
Restatement).*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-2a
|
|
|
|
|
|
|
|
|
—First Amendment of Executive Survivor and Supplemental
Retirement Plan (2005 Restatement).*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-3
|
|
|
10-K for year
ended 12/31/93
|
|
|
10-N-5
|
|
|
—Nonqualified Profit Sharing Plan.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-4
|
|
|
10-Q for quarter
ended 3/31/02
|
|
|
10-B
|
|
|
—Nonqualified Retirement Savings Plan, as amended.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-5
|
|
|
8-K filed 4/13/06
|
|
|
10.3
|
|
|
—1999 Employee Stock Purchase Plan, As Amended (2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-6
|
|
|
8-K filed 4/13/06
|
|
|
10.4
|
|
|
—1999 Stock Incentive Plan, As Amended (2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-7
|
|
|
10-K for year ended
12/31/05
|
|
|
10-N-7
|
|
|
—Form of Stock Option Agreement*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-8
|
|
|
10-K for year ended
12/31/05
|
|
|
10-N-8
|
|
|
—Form of Restricted Stock Agreement*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-9
|
|
|
8-K filed 4/13/06
|
|
|
10.2
|
|
|
—Form of 2006 Performance Award Agreement.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-10
|
|
|
8-K filed
04/15/05
|
|
|
10.2
|
|
|
—Executive Annual Incentive Plan (Effective April 1, 2005).*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-11
|
|
|
10-Q for quarter
ended 6/30/06
|
|
|
10.5
|
|
|
—Form of 2006 Restricted Stock Unit Award Agreement *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-N-12
|
|
|
8-K filed 4/13/06
|
|
|
10.1
|
|
|
—Form of Restricted Stock Award Agreement for Directors.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-O-1
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-A
|
|
|
—Executive Employment Agreement, John Erickson.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-O-2
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-B
|
|
|
—Executive Employment Agreement and amendment no. 1, Lauris
Molbert.*
|
-45-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Previously Filed
|
|
|
|
|
|
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
|
|
|
|
File No.
|
|
|
No.
|
|
|
|
|
|
10-O-3
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-C
|
|
|
—Executive Employment Agreement, Kevin Moug.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-O-4
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-D
|
|
|
—Executive Employment Agreement, George Koeck.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-P-1
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-E
|
|
|
—Change in Control Severance Agreement, John Erickson.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-P-2
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-F
|
|
|
—Change in Control Severance Agreement, Lauris Molbert.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-P-3
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-G
|
|
|
—Change in Control Severance Agreement, Kevin Moug.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10-P-4
|
|
|
10-Q for quarter
ended 6/30/02
|
|
|
10-H
|
|
|
—Change in Control Severance Agreement, George Koeck.*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13-A
|
|
|
|
|
|
|
|
|
—Portions of 2006 Annual Report to Shareholders incorporated
by reference in this Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21-A
|
|
|
|
|
|
|
|
|
—Subsidiaries of Registrant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23-A
|
|
|
|
|
|
|
|
|
—Consent of Deloitte & Touche LLP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24-A
|
|
|
|
|
|
|
|
|
—Powers of Attorney.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31.1
|
|
|
|
|
|
|
|
|
—Certification of Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31.2
|
|
|
|
|
|
|
|
|
—Certification of Chief Financial Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32.1
|
|
|
|
|
|
|
|
|
—Certification of Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32.2
|
|
|
|
|
|
|
|
|
—Certification of Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
*
|
|
Management contract of compensatory plan or arrangement required to be filed pursuant to Item
601(b)(10)(iii)(A) of Regulation S-K.
|
-46-
Exhibit 13-A
Selected Consolidated Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except number of shareholders and per-share data)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
1996
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
306,014
|
|
|
$
|
312,985
|
|
|
$
|
266,385
|
|
|
$
|
267,494
|
|
|
$
|
244,005
|
|
|
$
|
232,720
|
|
|
$
|
192,849
|
|
|
Plastics
|
|
|
163,135
|
|
|
|
158,548
|
|
|
|
115,426
|
|
|
|
86,009
|
|
|
|
82,931
|
|
|
|
63,216
|
|
|
|
22,049
|
|
|
Manufacturing
|
|
|
311,811
|
|
|
|
244,311
|
|
|
|
201,615
|
|
|
|
157,401
|
|
|
|
119,880
|
|
|
|
96,571
|
|
|
|
34,819
|
|
|
Health services
|
|
|
135,051
|
|
|
|
123,991
|
|
|
|
114,318
|
|
|
|
100,912
|
|
|
|
93,420
|
|
|
|
79,129
|
|
|
|
61,697
|
|
|
Food ingredient processing
|
|
|
45,084
|
|
|
|
38,501
|
|
|
|
14,023
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Other business operations (1)
|
|
|
147,436
|
|
|
|
107,400
|
|
|
|
104,002
|
|
|
|
79,427
|
|
|
|
56,225
|
|
|
|
54,934
|
|
|
|
39,714
|
|
|
Intersegment eliminations
|
|
|
(3,577
|
)
|
|
|
(3,867
|
)
|
|
|
(2,733
|
)
|
|
|
(2,254
|
)
|
|
|
(1,036
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues (1)
|
|
$
|
1,104,954
|
|
|
$
|
981,869
|
|
|
$
|
813,036
|
|
|
$
|
688,989
|
|
|
$
|
595,425
|
|
|
$
|
526,570
|
|
|
$
|
351,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
(1)
|
|
|
50,750
|
|
|
|
53,902
|
|
|
|
40,502
|
|
|
|
38,297
|
|
|
|
44,297
|
|
|
|
39,697
|
|
|
|
28,905
|
|
|
Net income from discontinued operations (1)
|
|
|
362
|
|
|
|
8,649
|
|
|
|
1,693
|
|
|
|
1,359
|
|
|
|
1,831
|
|
|
|
3,906
|
|
|
|
1,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
51,112
|
|
|
|
62,551
|
|
|
|
42,195
|
|
|
|
39,656
|
|
|
|
46,128
|
|
|
|
43,603
|
|
|
|
30,624
|
|
|
Operating cash flow from continuing operations (1)
|
|
|
79,207
|
|
|
|
90,348
|
|
|
|
54,410
|
|
|
|
76,464
|
|
|
|
71,584
|
|
|
|
71,010
|
|
|
|
66,356
|
|
|
Operating cash flow — continuing and discontinued operations
|
|
|
80,246
|
|
|
|
95,800
|
|
|
|
56,301
|
|
|
|
76,955
|
|
|
|
76,797
|
|
|
|
77,529
|
|
|
|
68,611
|
|
|
Capital expenditures — continuing operations (1)
|
|
|
69,448
|
|
|
|
59,969
|
|
|
|
49,484
|
|
|
|
48,783
|
|
|
|
73,442
|
|
|
|
50,723
|
|
|
|
63,335
|
|
|
Total assets
|
|
|
1,258,650
|
|
|
|
1,181,496
|
|
|
|
1,134,148
|
|
|
|
986,423
|
|
|
|
914,112
|
|
|
|
817,778
|
|
|
|
703,881
|
|
|
Long-term debt
|
|
|
255,436
|
|
|
|
258,260
|
|
|
|
261,805
|
|
|
|
262,311
|
|
|
|
254,015
|
|
|
|
221,643
|
|
|
|
153,452
|
|
|
Redeemable preferred
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
18,000
|
|
|
Basic earnings per share — continuing operations (1) (2)
|
|
|
1.70
|
|
|
|
1.82
|
|
|
|
1.53
|
|
|
|
1.47
|
|
|
|
1.73
|
|
|
|
1.53
|
|
|
|
1.15
|
|
|
Basic earnings per share — total (2)
|
|
|
1.71
|
|
|
|
2.12
|
|
|
|
1.59
|
|
|
|
1.52
|
|
|
|
1.80
|
|
|
|
1.69
|
|
|
|
1.23
|
|
|
Diluted earnings per share — continuing operations (1) (2)
|
|
|
1.69
|
|
|
|
1.81
|
|
|
|
1.52
|
|
|
|
1.46
|
|
|
|
1.72
|
|
|
|
1.52
|
|
|
|
1.15
|
|
|
Diluted earnings per share — total (2)
|
|
|
1.70
|
|
|
|
2.11
|
|
|
|
1.58
|
|
|
|
1.51
|
|
|
|
1.79
|
|
|
|
1.68
|
|
|
|
1.23
|
|
|
Return on average common equity
|
|
|
10.6
|
%
|
|
|
13.9
|
%
|
|
|
12.0
|
%
|
|
|
12.2
|
%
|
|
|
15.3
|
%
|
|
|
15.5
|
%
|
|
|
14.9
|
%
|
|
Dividends per common share
|
|
|
1.15
|
|
|
|
1.12
|
|
|
|
1.10
|
|
|
|
1.08
|
|
|
|
1.06
|
|
|
|
1.04
|
|
|
|
0.90
|
|
|
Dividend payout ratio
|
|
|
68
|
%
|
|
|
53
|
%
|
|
|
70
|
%
|
|
|
72
|
%
|
|
|
59
|
%
|
|
|
62
|
%
|
|
|
73
|
%
|
|
Common shares outstanding — year end
|
|
|
29,522
|
|
|
|
29,401
|
|
|
|
28,977
|
|
|
|
25,724
|
|
|
|
25,592
|
|
|
|
24,653
|
|
|
|
23,072
|
|
|
Number of common shareholders (3)
|
|
|
14,692
|
|
|
|
14,801
|
|
|
|
14,889
|
|
|
|
14,723
|
|
|
|
14,503
|
|
|
|
14,358
|
|
|
|
13,829
|
|
|
|
Notes:
|
(1)
|
|
Prior years are restated to exclude OTESCO’s gas
marketing operations, which were sold in 2006 and are now classified as discontinued.
See note 16 to consolidated financial statements.
|
|
|
|
(2)
|
|
Based on average number of shares outstanding.
|
|
|
|
(3)
|
|
Holders of record at year end.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Otter Tail Corporation and our subsidiaries form a diverse group of businesses with operations
classified into six segments: electric, plastics, manufacturing, health services, food ingredient
processing and other business operations. Our primary financial goals are to maximize earnings and
cash flows and to allocate capital profitably toward growth opportunities that will increase
shareholder value. Meeting these objectives enables us to preserve and enhance our financial
capability by maintaining desired capitalization ratios and a strong interest coverage position and
preserving solid credit ratings on outstanding securities, which, in the form of lower interest
rates, benefits both our customers and shareholders.
Our strategy is straightforward: Reliable utility performance combined with growth opportunities at
all our businesses provides long-term value. This includes growing our core electric utility
business which provides a strong base of revenues, earnings and cash flows. In addition, we look to
our nonelectric operating companies to provide growth both organically and through acquisitions.
Organic, internal growth comes from new products and services, market expansion and increased
efficiencies. We adhere to strict guidelines when reviewing acquisition candidates. Our aim is to
add companies that will produce an immediate positive impact on earnings and provide long-term
growth potential. We believe that owning well-run, profitable companies across different industries
will bring more growth opportunities and more balance to results. In doing this, we also avoid
concentrating business risk within a single industry. All our operating companies operate under a
decentralized business model with disciplined corporate oversight.
We assess the performance of our operating companies over time, using the following criteria:
|
|
•
|
|
ability to provide returns on invested capital that exceed our weighted average cost of
capital over the long term; and
|
|
|
|
|
•
|
|
assessment of an operating company’s business and potential for future earnings growth.
|
We are a committed long-term owner and therefore we do not acquire companies in pursuit of
short-term gains. However, we will divest operating companies that do not meet these criteria over
the long term.
The following major events occurred in our company in 2006:
|
|
•
|
|
Our annual consolidated revenues topped $1.1 billion for the first time in our history.
|
|
|
|
|
•
|
|
We reported record earnings in our plastics, manufacturing and construction operations.
|
|
|
|
|
•
|
|
We continued to work with six other regional utilities on the planning and permitting
process for a new 630-megawatt coal-fired electric generating plant (Big Stone II) on the
site of the existing Big Stone Plant.
|
Major growth strategies and initiatives in our company’s future include:
|
|
•
|
|
Planned capital budget expenditures of up to $889 million for the years 2007-2011 of
which $776 million is for capital projects at the electric utility, including $360 million
related to Big Stone II, $64 million for a wind generation project and $59 million for
anticipated expansion of transmission capacity in Minnesota. See “Capital Requirements”
section for further discussion.
|
|
|
|
|
•
|
|
Pursuing the regulatory approvals, financing and other arrangements necessary to build Big Stone II.
|
|
|
•
|
|
Adding more renewable energy to our electric resource mix.
|
|
|
|
|
•
|
|
Increasing wind tower production through expansion and continued improvements in
productivity, including an increase of DMI’s production capacity by 30% at its Ft. Erie,
Ontario facility.
|
|
|
|
|
•
|
|
Focus on improving the operating results of Idaho Pacific Holdings, Inc. (IPH).
|
|
|
|
|
•
|
|
The continued investigation and evaluation of strategic acquisition opportunities.
|
The following table summarizes our consolidated results of operations for the years ended December
31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
305,703
|
|
|
$
|
312,624
|
|
|
Nonelectric
|
|
|
799,251
|
|
|
|
669,245
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
1,104,954
|
|
|
$
|
981,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
24,181
|
|
|
$
|
37,301
|
|
|
Nonelectric
|
|
|
26,569
|
|
|
|
16,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,750
|
|
|
|
53,902
|
|
|
Net income from discontinued operations
|
|
|
362
|
|
|
|
8,649
|
|
|
|
|
|
|
|
|
|
|
Total net income
|
|
$
|
51,112
|
|
|
$
|
62,551
|
|
|
|
|
|
|
|
|
|
The 12.5% increase in consolidated revenues in 2006 compared with 2005 reflects revenue growth in
all our business segments except electric. Revenues increased $67.5 million in our manufacturing
segment in 2006 as a result of increased sales of wind towers and price increases related to higher
raw material costs. Other business operations revenue grew by $40.0 million in 2006, with $35.6
million coming from our construction companies as a result of increased construction activity and
$4.5 million coming from flatbed trucking operations as a result of more miles driven combined with
higher fuel costs. Revenues from our health services segment increased $11.1 million in 2006.
Scanning and other related service revenues were up $8.0 million while revenues from equipment
sales and service increased $3.1 million between the years. Revenues in our food ingredient
processing segment increased $6.6 million in 2006 mainly as a result of a 15.3% increase in the
price per pound of product sold. Revenues grew $4.6 million in our plastics segment in 2006 despite
an 8.8% decrease in pounds of pipe sold primarily as a result of price increases driven by higher
resin prices for polyvinyl chloride (PVC) pipe. Revenues in the electric segment decreased $6.9
million reflecting a $20.4 million decrease in wholesale energy revenues, partially offset by
increases of $12.0 million in retail electric revenue and $1.5 million in other electric revenue.
An $18.8 million decrease in net revenues from energy trading activities in 2006 compared with 2005
was the main contributing factor to the $13.1 million reduction in electric segment net income, as
the electric wholesale market became more efficient. Record net income from our manufacturing
segment and construction companies contributed to the $10.0 million increase in net income from our
nonelectric business segments between the years.
Following is a more detailed analysis of our operating results by business segment for the three
years ended December 31, 2006, 2005 and 2004, followed by our outlook for 2007, a discussion of our
financial position at the end of 2006 and risk factors that may affect our future operating results
and financial position.
RESULTS OF OPERATIONS
This discussion and analysis should be read in conjunction with our consolidated financial
statements and related notes found elsewhere in this report. See note 2 to our consolidated
financial statements for a complete description of our lines of business, locations of operations
and principal products and services.
Amounts presented in the segment tables that follow for 2006, 2005 and 2004 operating revenues,
cost of goods sold and other nonelectric operating expenses will not agree with amounts presented
in the consolidated statements of income due to the elimination of intersegment transactions. The
amounts of intersegment eliminations by income statement line item are listed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
311
|
|
|
$
|
361
|
|
|
$
|
365
|
|
|
Nonelectric
|
|
|
3,266
|
|
|
|
3,506
|
|
|
|
2,368
|
|
|
Cost of goods sold
|
|
|
1,433
|
|
|
|
2,070
|
|
|
|
1,083
|
|
|
Other nonelectric expenses
|
|
|
2,144
|
|
|
|
1,797
|
|
|
|
1,650
|
|
ELECTRIC
The following table summarizes the results of operations for our electric segment for the years
ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
%
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
change
|
|
|
2004
|
|
|
|
|
Retail sales revenues
|
|
$
|
260,926
|
|
|
|
5
|
|
|
$
|
248,939
|
|
|
|
11
|
|
|
$
|
224,326
|
|
|
Wholesale revenues
|
|
|
25,514
|
|
|
|
(39
|
)
|
|
|
41,953
|
|
|
|
75
|
|
|
|
24,000
|
|
|
Net marked-to-market gains
|
|
|
451
|
|
|
|
(90
|
)
|
|
|
4,444
|
|
|
|
38
|
|
|
|
3,228
|
|
|
Other revenues
|
|
|
19,123
|
|
|
|
8
|
|
|
|
17,649
|
|
|
|
19
|
|
|
|
14,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
306,014
|
|
|
|
(2
|
)
|
|
$
|
312,985
|
|
|
|
17
|
|
|
$
|
266,385
|
|
|
Production fuel
|
|
|
58,729
|
|
|
|
5
|
|
|
|
55,927
|
|
|
|
7
|
|
|
|
52,056
|
|
|
Purchased power — system use
|
|
|
58,281
|
|
|
|
(1
|
)
|
|
|
58,828
|
|
|
|
47
|
|
|
|
40,098
|
|
|
Other operation and maintenance expenses
|
|
|
103,548
|
|
|
|
4
|
|
|
|
99,904
|
|
|
|
17
|
|
|
|
85,361
|
|
|
Depreciation and amortization
|
|
|
25,756
|
|
|
|
6
|
|
|
|
24,397
|
|
|
|
1
|
|
|
|
24,236
|
|
|
Property taxes
|
|
|
9,589
|
|
|
|
(5
|
)
|
|
|
10,043
|
|
|
|
(4
|
)
|
|
|
10,411
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
50,111
|
|
|
|
(22
|
)
|
|
$
|
63,886
|
|
|
|
18
|
|
|
$
|
54,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 compared with 2005
The $12.0 million increase in retail electric revenue in 2006 compared with 2005 is due mainly to a
$9.5 million increase in fuel clause adjustment (FCA) revenues related to increases in fuel and
purchased power costs for system use and to a $3.6 million increase in FCA revenue related to the
2006 reversal of a $1.9 million FCA refund provision recorded in December 2005. The refund
provision is related to Midwest Independent Transmission System Operator (MISO) costs subject to
collection through the FCA in Minnesota. In December 2005, the Minnesota Public Utilities
Commission (MPUC) issued an order denying recovery of certain MISO-related costs through the FCA
and requiring a refund of amounts previously collected. In February 2006, the MPUC reconsidered its
order and eliminated the refund requirement. In December 2006, the MPUC ordered the refund of $0.4
million in MISO schedule 16 and 17 administrative costs that had been collected through the FCA,
allowing for deferred recovery of those costs in the electric utility’s next general rate case
which is scheduled to be filed on
or before October 1, 2007. The FCA revenues also include $2.6
million in unrecovered fuel and purchased power costs under an FCA true-up mechanism established by
order of the MPUC. The Minnesota FCA true-up relates to costs incurred from July 2004 through June
2006 that are being recovered from Minnesota customers from August 2006 through July 2007. The
electric utility currently is accruing for the Minnesota FCA true-up on a monthly basis along with
its regular monthly FCA accrual.
Retail megawatt-hour (mwh) sales increased 2.5% between the years as a result of increased sales to
industrial customers mainly due to increased consumption by pipeline customers as higher oil prices
have led to an increase in the volume of product being transported from Canada and the Williston
basin. A 9.8% decline in the price of wholesale mwh sales from company-owned generation in 2006
compared with 2005 resulted in a $1.7 million decrease in revenues despite a 3.4% increase in mwh
sales from company-owned generating units. Advance purchases of electricity in anticipation of
normal winter weather resulted in increased wholesale electric sales in January 2006 due to
unseasonably mild weather. Wholesale sales from company-owned generation were curtailed in February
and March 2006 as generation levels were restricted due to coal supply constraints at Big Stone and
Hoot Lake plants. Advance purchases of electricity in anticipation of continuing coal supply
constraints in the second quarter of 2006 supplemented increased generation when coal supplies
improved in May, providing additional resources for wholesale sales.
Net revenue from energy trading activities, including net mark-to-market gains on forward energy
contracts, were $2.8 million in 2006 compared with $21.6 million in 2005. The $18.8 million
decrease in revenue from energy trading activities reflects an $11.4 million reduction in net
profits from virtual transactions, a $4.5 million reduction in profits from purchased power resold
and a $4.0 million decrease in net mark-to-market gains on forward energy contracts, offset by a
$1.1 million increase in profits from investments in financial transmission rights (FTRs). With the
inception of the Midwest MISO Day 2 markets in April 2005, MISO introduced two new types of
contracts, virtual transactions and FTRs. Virtual transactions are of two types: (1) a Virtual
Demand Bid, which is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by
physical load; (2) a Virtual Supply Offer, which is an offer submitted by a market participant in
the Day-Ahead Market to sell energy not supported by a physical injection or reduction in
withdrawals in commitment by a resource. An FTR is a financial contract that entitles its holder to
a stream of payments, or charges, based on transmission congestion charges calculated in MISO’s
Day-Ahead Market. A market participant can acquire an FTR from several sources: the annual or
monthly FTR allocation based on existing entitlements, the annual or monthly FTR auction, the FTR
secondary market or FTRs granted in conjunction with a transmission service request. An FTR is
structured to hedge a market participant’s exposure to uncertain cash flows resulting from
congestion of the transmission system. Profits from virtual transactions were $1.2 million in 2006
compared with $12.7 million in 2005 as the MISO market matured and became more efficient and as a
result of a reduction in virtual transactions due to uncertainties related to the status of Revenue
Sufficiency Guarantee charges in MISO’s Transmission and Energy Markets Tariff. In 2006, we
recorded a net loss on purchased power resold of $1.8 million compared with a net gain of $2.7
million in 2005. Of the $2.9 million in net mark-to-market gains recognized on open forward energy
contracts at December 31, 2005, $2.1 million was realized and $0.8 million was reversed in the
first nine months of 2006 as market prices on forward electric contracts declined in response to
decreased demand for electricity due, in part, to regional winter weather that was milder than
expected.
The $2.8 million increase in fuel costs in 2006 compared with 2005 reflects a 3.2% increase in the
cost of fuel per mwh generated combined with a 1.8% increase in mwhs generated. Generation used for
wholesale electric sales increased 3.4% while generation for retail sales increased 1.3% between
the periods. Fuel costs per mwh increased at the Coyote Station and Hoot Lake Plant as a result of
increases in coal and coal transportation costs between the periods. Much of the increase in coal
and coal transportation costs is related to higher diesel fuel prices. The mix of available
generation resources in 2006 compared with 2005 also contributed to the increase in the cost of
fuel per mwh generated. Big Stone Plant’s generation increased 12.9% between the years while Coyote
Station’s generation
was down 5.9%. In the second quarter of 2006, Coyote Station, our lowest cost
baseload plant, was off-line for five weeks for scheduled maintenance. In the second quarter of
2005, the higher cost Big Stone Plant was shut down for seven weeks for scheduled maintenance.
Approximately 90% of the fuel cost increases associated with generation to serve retail electric
customers is subject to recovery through the fuel cost recovery component of retail rates.
The $0.5 million decrease in purchased power — system use (to serve retail customers) in 2006
compared with 2005 is due to a 20.9% reduction in mwh purchases for system use mostly offset by a
25.2% increase in the cost per mwh purchased for system use.
The $3.6 million increase in other operation and maintenance expenses for 2006 compared with 2005
resulted primarily from $2.0 million in increased operating and maintenance costs at the electric
utility’s generation plants, including Coyote Station, which was shut down for five weeks of
scheduled maintenance in the second quarter of 2006, and $1.4 million in increased costs related to
contract work performed for other area utilities. Depreciation expense increased $1.4 million in
2006 compared with 2005 as a result of an increase in effective depreciation rates in 2006 and
increases in electric plant in service. The $0.5 million decrease in property taxes reflects lower
property valuations in Minnesota and South Dakota.
2005 compared with 2004
The $24.6 million increase in retail revenues from 2004 to 2005 includes $16.0 million in increased
FCA revenues directly related to increases in fuel and purchased power costs in 2005 and $8.6
million from a 3.2% increase in retail mwh sales. Residential mwh sales increased 3.9% primarily
due to an 86% increase in cooling degree-days in the summer of 2005 compared with the summer of
2004. Mwh sales to commercial and industrial customers increased 3.0% due to an improving regional
economy.
Wholesale revenues increased $18.0 million in 2005 compared with 2004. In 2005, we recorded $12.7
million in net revenues related to virtual transactions and $1.9 million in net revenue related to
bilateral trading of FTRs in MISO’s secondary market. Net revenues from the purchase and sale of
electric energy contracts, including virtual transactions and FTRs, increased $11.2 million in 2005
compared with 2004 as a result of a 178% increase in mwh volume traded between the years. Revenues
from wholesale energy sales from company-owned generation increased $6.8 million due to a 58.9%
increase in the average price per mwh sold in 2005 compared with 2004, offset by a 13.2% reduction
in mwh sales. The increase in the average price per mwh is reflective of a general increase in
energy prices in 2005 related to increased fuel costs.
The $1.2 million increase in net mark-to-market gains on forward energy contracts is due to an
increase in the volume of forward energy contracts entered into in 2005 compared to 2004 combined
with increasing energy prices in 2005. At December 31, 2005 the electric utility had recorded $2.9
million in net gains on forward energy contracts to be settled in 2006 compared with $0.3 million
in recorded net gains on forward energy contracts at December 31, 2004 that were settled in 2005.
The $2.8 million increase in other electric revenues in 2005 compared with 2004 is related mostly
to transmission studies completed by Otter Tail Power Company for MISO and transmission line
permitting work done for other companies.
In December 2005, the MPUC issued an order denying the recovery of certain MISO-related costs
through the FCA in Minnesota retail rates and requiring a refund of amounts previously collected
pursuant to an interim order issued in April 2005. A $1.9 million reduction in revenue and a refund
payable was recorded in December 2005 by the electric utility to reflect the refund obligation.
The $3.9 million increase in production fuel costs in 2005 compared with 2004 reflects a 15.5%
increase in the cost of fuel per mwh generated, partially offset by a 7.0% reduction in generation.
The decrease in mwhs generated is mainly due to the seven-week maintenance shutdown of the Big
Stone Plant in 2005. Fuel costs per mwh of generation increased at all three of our coal-fired
generating plants as a result of increases in mine operating costs and, in the case of Hoot Lake
and Big Stone plants, increased costs for transporting coal by rail. Much of the increase in mine
operating and coal transportation costs is directly related to a sharp increase in diesel fuel
prices in 2005. Also, the overall increase in production fuel costs is partially attributable to
our generation mix in 2005. Mwh generation at our higher cost Hoot Lake generating units increased
25% in 2005 compared with 2004 while mwh generation at our lower cost Big Stone and Coyote
generating units decreased 21% and 6% respectively. Fuel costs at our combustion turbine peaking
plants increased $2.5 million (110%) while mwh generation increased by only 7.6%, reflecting
increases in natural gas and fuel oil prices in 2005 and decreased plant efficiencies resulting
from MISO dispatch directives.
Purchased power costs to serve retail customers increased $18.7 million as a result of a 28.2%
increase in mwh purchases combined with a 14.5% increase in the cost per mwh purchased. Mwh
purchases increased to make up for the shortfall caused by the Big Stone Plant shutdown and to
provide for increased demand among retail electric customers. The increase in the cost per mwh of
purchased power in 2005 is partially due to increases in fuel costs and partially due to a decrease
in available electricity from hydro-generation in the region due to lower water levels in Upper
Missouri River reservoirs resulting from a prolonged drought in the Upper Missouri River Basin.
The $14.5 million increase in other operation and maintenance expenses in 2005 compared with 2004
includes increases of $7.4 million in labor and benefits expense, $1.8 million in costs related to
contract work performed for others, $1.5 million in storm damage repair costs, $1.3 million in
tree-trimming and transmission line and pole maintenance expenditures and $1.1 million in
maintenance expenses related to the seven-week maintenance shutdown of the Big Stone Plant in 2005.
The increase in labor and benefit expenses is due to wage and salary increases averaging 3.6% and
increases in pension costs, storm-related overtime pay, performance bonuses and safety awards.
The $0.4 million decrease in property taxes in 2005 compared with 2004 is a result of slightly
lower utility property valuations in Minnesota in 2005.
PLASTICS
The following table summarizes the results of operations for our plastics segment for the years
ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
%
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
change
|
|
|
2004
|
|
|
|
|
Operating revenues
|
|
$
|
163,135
|
|
|
|
3
|
|
|
$
|
158,548
|
|
|
|
37
|
|
|
$
|
115,426
|
|
|
Cost of goods sold
|
|
|
126,374
|
|
|
|
4
|
|
|
|
121,245
|
|
|
|
25
|
|
|
|
97,126
|
|
|
Operating expenses
|
|
|
10,239
|
|
|
|
(6
|
)
|
|
|
10,939
|
|
|
|
91
|
|
|
|
5,718
|
|
|
Depreciation and amortization
|
|
|
2,815
|
|
|
|
12
|
|
|
|
2,511
|
|
|
|
9
|
|
|
|
2,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
23,707
|
|
|
|
(1
|
)
|
|
$
|
23,853
|
|
|
|
132
|
|
|
$
|
10,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 compared with 2005
The $4.6 million increase in plastics operating revenues in 2006 compared with 2005 reflects a
12.6% increase in the price per pound of PVC and polyethylene pipe sold offset by an 8.8% decrease
in pounds of pipe sold between the years. The increase in prices reflects the effect of a 13.7%
increase in PVC resin costs per pound of PVC pipe
shipped between the periods. The decrease in
pounds of pipe sold reflects a significant decrease in sales in the third and fourth quarters of
2006 compared with the third and fourth quarters of 2005, reflecting record demand for PVC
pipe in the last half of 2005, as sales were affected by concerns over the adequacy of resin supply
following the 2005 Gulf Coast hurricanes. The increase in cost of goods sold is a result of higher
resin costs. The decrease in plastics segment operating expenses is due to lower selling, general
and administrative expenses between the periods. The increase in depreciation and amortization
expense is related to capital additions in 2005 and 2006, mainly for production equipment.
2005 compared with 2004
The $43.1 million increase in plastics operating revenues in 2005 compared with 2004 reflects a
31.9% increase in the average sales price per pound of PVC pipe sold combined with a 3.2% increase
in pounds of PVC pipe sold between the years. The increase in revenue reflects the effect of rising
resin prices and increased customer demand for PVC pipe. Demand accelerated to record levels late
in the third quarter of 2005 as substantial resin price increases were announced and concerns
developed over the adequacy of resin supply following the 2005 Gulf Coast hurricanes. A majority of
U.S. resin production plants are located in the Gulf Coast region. The increase in revenues was
partially offset by a $24.1 million increase in cost of goods sold, reflecting a 19.9% increase in
the average cost per pound of pipe sold. The average cost per pound of PVC resin increased 16.4%
between the periods. The $5.2 million increase in operating expenses between the periods primarily
is due to increases in costs directly related to increased sales. The increase in depreciation and
amortization expense relates mostly to production equipment purchased in 2004 and 2005.
MANUFACTURING
The following table summarizes the results of operations for our manufacturing segment for the
years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
%
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
change
|
|
|
2004
|
|
|
|
|
Operating revenues
|
|
$
|
311,811
|
|
|
|
28
|
|
|
$
|
244,311
|
|
|
|
21
|
|
|
$
|
201,615
|
|
|
Cost of goods sold
|
|
|
246,649
|
|
|
|
27
|
|
|
|
194,264
|
|
|
|
23
|
|
|
|
157,802
|
|
|
Operating expenses
|
|
|
26,508
|
|
|
|
11
|
|
|
|
23,872
|
|
|
|
13
|
|
|
|
21,098
|
|
|
Depreciation and amortization
|
|
|
11,076
|
|
|
|
17
|
|
|
|
9,447
|
|
|
|
21
|
|
|
|
7,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
27,578
|
|
|
|
65
|
|
|
$
|
16,728
|
|
|
|
12
|
|
|
$
|
14,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 compared with 2005
The increase in revenues in our manufacturing segment in 2006 compared with 2005 relates to the
following:
|
|
•
|
|
Revenues at DMI Industries, Inc. (DMI), our manufacturer of wind towers, increased $64.0
million (88.4%) as a result of increases in production and sales activity due in part to
plant additions, including initial operations at the Ft. Erie, Ontario facility which
generated $25.3 million in revenue in 2006, its first year of operations, and continued
improvements in productivity and capacity utilization.
|
|
|
|
|
•
|
|
Revenues at ShoreMaster, Inc., our waterfront equipment manufacturer, increased $3.2
million (5.7%) between the years due to price increases driven by higher material costs,
especially aluminum and due to the acquisition of Southeast Floating Docks in May 2005.
|
|
|
|
|
•
|
|
Revenues at T.O. Plastics, Inc., our manufacturer of thermoformed plastic and
horticultural products, increased $0.7 million (1.9%) between the periods as a result of a
0.9% increase in unit sales combined with a 1.5% increase in revenue per unit sold.
|
|
|
•
|
|
Revenues at BTD Manufacturing Inc. (BTD), our metal parts stamping and fabrication
company, decreased $0.4 million (0.5%) between the periods. However, BTD’s operating income increased
$3.6 million due, in part, to productivity improvements between the years.
|
The increase in cost of goods sold in our manufacturing segment in 2006 compared with 2005 relates
to the following:
|
|
•
|
|
DMI’s cost of goods sold increased $51.5 million between the periods, including
increases of $39.6 million in material costs, $9.2 million in labor and benefit costs and
$2.7 million in tools and supplies expenditures. The increase in cost of goods sold is
directly related to the increase in DMI’s production and sales activity and initial
operation and start up costs at its Ft. Erie facility.
|
|
|
|
|
•
|
|
Cost of goods sold at ShoreMaster increased $2.4 million between the years as a result
of increases in labor, material (especially aluminum) and other direct costs and a full
year of operations relating to the acquisition of Southeast Floating Docks, which occurred
in May 2005.
|
|
|
|
|
•
|
|
Cost of goods sold at T.O. Plastics increased $2.0 million, reflecting $1.0 million in
material cost increases and $0.8 million in increased labor and benefit costs between the
years.
|
|
|
|
|
•
|
|
Cost of goods sold at BTD decreased $3.3 million between the periods mainly due to a
decrease in labor costs between the years due to a reduction in the number of production
employees, a decrease in overtime pay between the periods and a reduction in production
hours in December 2006. Productivity gains at BTD were achieved through efforts to better
utilize and allocate available labor resources.
|
The increase in operating expenses in our manufacturing segment in 2006 compared with 2005 relates
to the following:
|
|
•
|
|
Operating expenses at DMI increased $2.7 million as a result of increases in labor,
professional services and maintenance expenses mainly related to initial operation and
start-up costs at the Ft. Erie plant.
|
|
|
|
|
•
|
|
ShoreMaster’s operating expenses increased $0.2 million between the years.
|
|
|
|
|
•
|
|
T.O. Plastics’ operating expenses increased $0.2 million between the years.
|
|
|
|
|
•
|
|
BTD’s operating expenses decreased $0.4 million between the years.
|
Depreciation expense increased between the years as a result of $21.1 million in capital additions
from October 2005 through September 2006 at all four manufacturing companies. Capital additions at
DMI’s Ft. Erie plant totaled $8.0 million in 2006.
2005 compared with 2004
Revenue increases at the manufacturing companies in 2005 compared with 2004 are due to a
combination of factors including increased unit sales, increased sales of higher-priced products,
higher prices related to material cost increases and 2005 acquisitions. The increase in cost of
goods sold in the manufacturing segment was proportional to the increase in sales revenue resulting
in a $6.2 million increase in manufacturing segment gross profits between the periods.
The increase in revenues in our manufacturing segment in 2005 compared with 2004 relates to the
following:
|
|
•
|
|
Revenues at DMI increased $23.8 million (48.9%) due to increased production and sales
activity. This is in part related to the production tax credits for wind-generated
electricity being in place for 2005 as well as improvements in productivity and capacity
utilization.
|
|
|
|
|
•
|
|
Revenues at BTD increased $10.2 million (14.9%) mainly as a result of product price
increases to cover rising material costs reflected in an 11.8% increase in revenue per unit
sold between the periods. The purchase of Performance Tool in January 2005 contributed $3.8
million toward BTD’s revenue increase.
|
|
|
|
|
•
|
|
Revenues at ShoreMaster increased $4.9 million (9.5%) due to the acquisitions of
Shoreline Industries and Southeast Floating Docks, offset in part by a decline in revenues
in its residential and commercial divisions.
|
|
|
|
|
•
|
|
Revenues at T.O. Plastics increased $3.8 million (11.6%) as a result of productivity
improvements and higher prices that provided for recovery of increased raw material costs.
|
The increase in cost of goods sold in our manufacturing segment in 2005 compared with 2004 relates
to the following:
|
|
•
|
|
DMI cost of goods sold increased $18.4 million between the periods as a result of
increased production and higher raw material costs, subcontractor and labor costs. DMI cost
of goods sold also includes a $1.0 million write-down of inventory in the third quarter
2005 for tower sections that had limited use in the wind business due to changes in wind
tower design requirements.
|
|
|
|
|
•
|
|
Cost of goods sold at BTD increased $12.1 million as a result of higher raw material and
labor costs mainly related to increased production. The purchase of Performance Tool in
January 2005 contributed $2.8 million toward BTD’s increase in cost of goods sold.
|
|
|
|
|
•
|
|
ShoreMaster’s cost of goods sold increased $3.8 million mainly due to the acquisitions
of Shoreline Industries and Southeast Floating Docks and increases in material costs.
|
|
|
|
|
•
|
|
T.O. Plastics cost of goods sold increased $2.3 million between the periods as a result
of increased material costs.
|
The increase in operating expenses in our manufacturing segment in 2005 compared with 2004 relates
to the following:
|
|
•
|
|
DMI operating expenses increased $1.2 million as a result of a $0.5 million increase in
wages, salaries and benefit expenses, a $0.4 million increase in costs associated with
changes in plant layout to improve productivity and a $0.2 million increase in repairs and
maintenance costs.
|
|
|
|
|
•
|
|
ShoreMaster’s operating expenses increased $1.5 million mainly as a result of the
acquisitions of Shoreline Industries and Southeast Floating Docks in January and May of
2005.
|
Depreciation expense increased in 2005 compared with 2004 as a result of 2004 equipment additions
and the 2005 manufacturing segment acquisitions.
HEALTH SERVICES
The following table summarizes the results of operations for our health services segment for the
years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
%
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
change
|
|
|
2004
|
|
|
|
|
Operating revenues
|
|
$
|
135,051
|
|
|
|
9
|
|
|
$
|
123,991
|
|
|
|
8
|
|
|
$
|
114,318
|
|
|
Cost of goods sold
|
|
|
104,108
|
|
|
|
15
|
|
|
|
90,327
|
|
|
|
5
|
|
|
|
85,731
|
|
|
Operating expenses
|
|
|
22,745
|
|
|
|
3
|
|
|
|
21,989
|
|
|
|
25
|
|
|
|
17,593
|
|
|
Depreciation and amortization
|
|
|
3,660
|
|
|
|
(9
|
)
|
|
|
4,038
|
|
|
|
(20
|
)
|
|
|
5,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
4,538
|
|
|
|
(41
|
)
|
|
$
|
7,637
|
|
|
|
28
|
|
|
$
|
5,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 compared with 2005
The $11.1 million increase in health services operating revenues in 2006 compared with 2005
reflects an $8.0 million increase in imaging revenues combined with a $3.1 million increase in
revenues from sales and servicing of diagnostic imaging equipment. On the imaging side of the
business, $3.5 million of the $8.0 million increase in revenue came from imaging services where the
revenue per scan increased 15.7% between the years while the number of scans completed decreased
8.9%. Revenues from rentals and interim installations of scanning equipment along with providing
technical support services for those rental and interim installations increased $4.5 million
between the years. The increase in health services revenue was more than offset by the $13.8
million increase in health services cost of goods sold, mainly as a result of increases in costs of
equipment purchased for resale, increases in unit rental and sublease costs related to units that
were out of service in the first six months of 2006 and increases in labor and other direct costs.
The $0.8 million increase in operating expenses is mainly due to increases in property tax
expenses. The $0.4 million decrease in depreciation and amortization expense is the result of
certain assets reaching the ends of their depreciable lives. When these assets are replaced, they
are generally replaced with assets leased under operating leases.
2005 compared with 2004
The $9.7 million increase in health services operating revenues for 2005 compared with 2004
reflects an increase of $13.9 million in scanning and other related service revenues offset by a
decline in revenues from equipment sales and service of $4.2 million between the periods. The
revenue per scan and the number of scans completed increased 9.6% and 5.9%, respectively. The
imaging business added to its fleet of medical imaging equipment in 2005 resulting in an increase
in revenue from rentals and interim installations of scanning equipment and related technical
support services. The increase in health services revenue was partially offset by
increases in cost of goods sold and operating expenses of $9.0 million to support the increases in
imaging services activity. The increase in cost of goods sold is mainly related to increased
equipment rental costs and increased labor costs partially offset by decreases in materials and
maintenance costs. The increase in operating expenses is mainly due to increased payroll and travel
expenses and increases in contractual allowances and bad debt expense between the periods and
losses on equipment sales in 2005. The decrease in depreciation and amortization expense is the
result of certain assets reaching the ends of their depreciable lives. When these assets are
replaced, they are generally replaced with assets leased under operating leases. Improved operating
efficiencies in the imaging business and service cost reductions initiated in 2004 along with
growing scan counts contributed to improved results in the health services segment in 2005.
FOOD INGREDIENT PROCESSING
The following table summarizes the results of operations for our food ingredient processing segment
for the periods ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
2004
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
(19 weeks)
|
|
|
|
|
Operating revenues
|
|
$
|
45,084
|
|
|
|
17
|
|
|
$
|
38,501
|
|
|
$
|
14,023
|
|
|
Cost of goods sold
|
|
|
44,233
|
|
|
|
43
|
|
|
|
30,930
|
|
|
|
11,379
|
|
|
Operating expenses
|
|
|
2,920
|
|
|
|
15
|
|
|
|
2,533
|
|
|
|
876
|
|
|
Depreciation and amortization
|
|
|
3,759
|
|
|
|
11
|
|
|
|
3,399
|
|
|
|
1,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(5,828
|
)
|
|
|
(456
|
)
|
|
$
|
1,639
|
|
|
$
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 compared with 2005
The $6.6 million increase in food ingredient processing revenues in 2006 compared with 2005
reflects a 15.3% increase in sales price per pound of product combined with a 1.5% increase in
pounds of product sold between the years. The food ingredient processing segment has been
negatively impacted by raw potato supply shortages in Idaho and Prince Edward Island. Higher than
expected raw product costs related to the supply shortages have resulted in operating
inefficiencies and a 40.8% increase in the cost per pound of product sold. The increase in
operating expenses is due to an increase in selling and administrative expenses between the
periods.
Consistent with trends in the industry, operating income for 2006 was less than expected due to raw
potato supply shortages, increasing raw material costs and the increasing value of the Canadian
dollar relative to the U.S. dollar.
2005 compared with 2004
The increases in revenues, cost of goods sold, operating expenses and depreciation and amortization
are due to 2004 results reflecting only 19 weeks of operating activity as a result of the
acquisition of IPH in August 2004.
OTHER BUSINESS OPERATIONS
Revenue and expense amounts for 2005 and 2004 have changed from last year’s annual report as a
result of the sale of OTESCO’s natural gas marketing operations in June 2006 and its subsequent
reclassification to discontinued operations. The following table summarizes the results of
operations for our other business operations segment for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
%
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
change
|
|
|
2005
|
|
|
change
|
|
|
2004
|
|
|
|
|
Operating revenues
|
|
$
|
147,436
|
|
|
|
37
|
|
|
$
|
107,400
|
|
|
|
3
|
|
|
$
|
104,002
|
|
|
Cost of goods sold
|
|
|
91,806
|
|
|
|
36
|
|
|
|
67,711
|
|
|
|
(2
|
)
|
|
|
69,439
|
|
|
Operating expenses
|
|
|
55,022
|
|
|
|
5
|
|
|
|
52,171
|
|
|
|
23
|
|
|
|
42,402
|
|
|
Depreciation and amortization
|
|
|
2,917
|
|
|
|
9
|
|
|
|
2,666
|
|
|
|
(9
|
)
|
|
|
2,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$
|
(2,309
|
)
|
|
|
85
|
|
|
$
|
(15,148
|
)
|
|
|
(40
|
)
|
|
$
|
(10,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate general and administrative expenses included in the net operating loss from other
business operations were $11.9 million, $15.0 million and $10.1 million for the years ended
December 31, 2006, 2005 and 2004, respectively. Net operating income (loss) from other business
operations before corporate general and administrative expenses was $9.6 million, ($0.1 million)
and ($0.7 million) for the years ended December 31, 2006, 2005 and 2004, respectively.
2006 compared with 2005
The increase in operating revenues in our other business operations in 2006 compared with 2005 is
due to the following:
|
|
•
|
|
Revenues at Foley Company, a mechanical and prime contractor on industrial projects,
increased $33.3 million (106.4%) due to an increase in the volume of work performed between
the years.
|
|
|
|
|
•
|
|
Revenues at E.W. Wylie Corporation (Wylie), our flatbed trucking company, increased $4.5
million (14.8%) between the years mainly due to an 8.4% net increase in miles driven by
owner-operated and company-operated trucks. Miles driven by owner-operated trucks increased
50.3% while miles driven by company-operated trucks decreased 9.3% between the periods.
Wylie’s increased revenues also reflect higher rates related to increased fuel costs
recovered through fuel surcharges between the periods for both owner-operated and
company-operated trucks.
|
|
|
|
|
•
|
|
Revenues at Midwest Construction Services, Inc. (MCS), our electrical design and
construction services company, increased $2.3 million (5.2%) between the periods as a
result of increased activity on several wind projects in the fourth quarter of 2006.
|
The increase in cost of goods sold in our other business operations in 2006 compared with 2005 is
due to the following:
|
|
•
|
|
Foley Company’s cost of goods sold increased $28.3 million mainly in the areas of
materials, subcontractor and labor costs as a result of an increase in the volume of work
performed between the years.
|
|
|
|
|
•
|
|
Cost of goods sold at MCS decreased $4.2 million mainly due to a reduction in material
and labor costs between the periods mostly related to a job completed in 2005 on which
large losses were incurred as a result of higher than expected costs.
|
The increase in operating expenses in the other business operations segment is due to the
following:
|
|
•
|
|
Wylie’s revenue increase was entirely offset by a $4.5 million increase in operating
expenses, including $4.0 million in contractor costs related to higher fuel costs combined
with an increase in miles driven by owner-operated trucks between the periods and $0.5
million in increased insurance costs.
|
|
|
|
|
•
|
|
Foley Company’s operating expenses increased $0.7 million between the periods as a
result of increases in employee benefit costs.
|
|
|
|
|
•
|
|
MCS operating expenses increased $1.0 million between the periods, mainly due to
increases in employee benefit costs.
|
|
|
|
|
•
|
|
Other operating expenses decreased $3.3 million as a result of lower corporate costs
consisting of lower health insurance plan costs, improved claims experience in our captive
insurance company and a gain on the sale of property.
|
The increase in depreciation and amortization expense in 2006 compared with 2005 is mainly related
to equipment purchases at Foley Company in 2005 and 2006.
2005 compared with 2004
The increases in operating revenues and cost of goods sold in our other business operations in 2005
compared with 2004 are due to the following:
|
|
•
|
|
Revenues at MCS increased $16.6 million (61.4%) between the years as a result of an
increase in work in progress, which was mostly offset by a $13.7 million increase in cost
of goods sold including $4.4 million in increased material and labor costs incurred on a
single project that resulted in a significant loss on that project.
|
|
|
|
|
•
|
|
Revenues at Wylie increased $3.7 million (13.7%) in 2005 compared with 2004 due to a
9.7% increase in miles driven by company-operated and owner-operated trucks and a $0.9
million increase in fuel surcharge revenue.
|
|
|
|
|
•
|
|
Revenues at Foley Company decreased $17.2 million (35.4%) in 2005 compared with 2004 due
to a decrease in jobs in progress. The decrease in Foley’s revenues was mostly offset by a
decrease of $15.4 million in material, subcontractor, labor and insurance costs between the
periods.
|
The increase in operating expenses in our other business operations segment in 2005 compared with
2004 relates to the following:
|
|
•
|
|
Wylie’s operating expenses increased $3.9 million as a result of higher fuel prices,
increased fuel usage and labor costs related to the increase in miles driven and increases
in truck leasing costs between the periods.
|
|
|
|
|
•
|
|
Increases in employee health insurance and other employee benefit costs and increases in
insurance costs at our captive insurance company contributed $1.9 million to the increase
in net losses in this segment.
|
|
|
|
|
•
|
|
MCS reported increased expenses of $0.8 million for wages and benefits, outside
contracted services and advertising and promotions in 2005 compared with 2004.
|
Wylie’s depreciation and amortization expenses decreased by $0.3 million between the periods as a
result of a 2004 decision to lease rather than buy replacement trucks for their fleet.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS
Other income and deductions decreased by $2.2 million in 2006 compared with 2005. The major item
contributing to the decrease was a noncash charge of $3.3 million in 2006 resulting from
uncertainty with respect to the capitalized cost of construction funds included in the electric
utility’s rate base.
CONSOLIDATED INTEREST CHARGES
Interest expense increased $1.0 million in 2006 compared to 2005 primarily as a result of increased
interest rates on short-term debt. In 2006, short-term debt interest expense was $2.5 million at an
average rate of 5.8% on an average daily balance of $41.9 million, compared with $1.6 million at an
average rate of 3.7% on an average daily balance of $42.6 million in 2005.
Interest expense increased $0.3 million in 2005 compared to 2004 primarily as a result of increased
interest rates on short-term debt. In 2005, short-term debt interest expense was $1.6 million at an
average rate of 3.7% on an average daily balance of $42.6 million, compared with $1.2 million at an
average rate of 2.2% on an average daily balance of $57.8 million in 2004.
CONSOLIDATED INCOME TAXES
The 3.2% decrease in income tax expense from continuing operations in 2006 compared to 2005 is due,
in part, to a 4.9% decrease in income from continuing operations before income taxes. Our effective
tax rate on income from continuing operations was 34.8% for 2006 compared with 34.2% for 2005.
The 61.3% increase in income tax expense from continuing operations in 2005 compared to 2004 is
due, in part, to a 41.5% increase in income from continuing operations before income taxes. Our
effective tax rate on income from continuing operations was 34.2% for 2005 compared with 30.0% for
2004. The difference in the effective tax rate for 2005 compared to 2004 is a function of the level
of fixed deductions and credits in proportion to higher net income before tax in 2005 compared to
2004. See note 15 to consolidated financial statements.
DISCONTINUED OPERATIONS
In 2006, we sold the natural gas marketing operations of OTESCO, our energy services subsidiary.
Discontinued operations includes the operating results of OTESCO’s natural gas marketing operations
for 2006, 2005 and 2004. Discontinued operations also includes an after-tax gain on the sale of
OTESCO’s natural gas marketing operations of $0.3 million in 2006.
In 2005, we sold Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication, Inc. (SGS)
and Chassis Liner Corporation (CLC). Discontinued operations includes the operating results of MIS,
SGS and CLC for 2005 and 2004. Discontinued operations also includes an after-tax gain on the sale
of MIS of $11.9 million, an after-tax loss on the sale of SGS of $1.7 million and an after-tax loss
on the sale of CLC of $0.2 million in 2005.
The following table presents operating revenues, expenses, including interest and other income and
deductions, and income taxes, included on a net basis in income from discontinued operations on our
2006, 2005 and 2004 consolidated statements of income.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Operating revenues
|
|
$
|
28,234
|
|
|
$
|
80,988
|
|
|
$
|
78,027
|
|
|
Expenses
|
|
|
28,180
|
|
|
|
81,601
|
|
|
|
75,213
|
|
|
Goodwill impairment loss
|
|
|
—
|
|
|
|
1,003
|
|
|
|
—
|
|
|
Income tax expense (benefit)
|
|
|
28
|
|
|
|
(261
|
)
|
|
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations
|
|
$
|
26
|
|
|
$
|
(1,355
|
)
|
|
$
|
1,693
|
|
|
|
|
|
|
|
|
|
|
|
|
The $1.0 million goodwill impairment loss in 2005 relates to the write-off of goodwill at OTESCO
related to its natural gas marketing operations in the third quarter of 2005 as a result of a
reassessment of its future cash flows in light of rising natural gas prices and greater market
volatility in future prices for natural gas.
The following table presents the pre-tax and net-of-tax gains and losses recorded on the sales of
OTESCO’s natural gas marketing operations in 2006 and MIS, SGS and CLC in 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
2005
|
|
|
(in thousands)
|
|
OTESCO-gas
|
|
|
|
MIS
|
|
|
SGS
|
|
|
CLC
|
|
|
Total
|
|
|
|
|
|
|
|
Gain (loss) on sale
|
|
$
|
560
|
|
|
|
$
|
19,025
|
|
|
$
|
(2,919
|
)
|
|
$
|
(271
|
)
|
|
$
|
15,835
|
|
|
Income tax (expense) benefit
|
|
|
(224
|
)
|
|
|
|
(7,107
|
)
|
|
|
1,168
|
|
|
|
108
|
|
|
|
(5,831
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on sale
|
|
$
|
336
|
|
|
|
$
|
11,918
|
|
|
$
|
(1,751
|
)
|
|
$
|
(163
|
)
|
|
$
|
10,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
IMPACT OF INFLATION
The electric utility operates under regulatory provisions that allow price changes in fuel and
certain purchased power costs to be passed to most retail customers through automatic adjustments
to its rate schedules under fuel clause adjustments. Other increases in the cost of electric
service must be recovered through timely filings for electric rate increases with the appropriate
regulatory agency.
Our plastics, manufacturing, health services, food ingredient processing, and other business
operations consist entirely of unregulated businesses. Increased operating costs are reflected in
product or services pricing with any limitations on price increases determined by the marketplace.
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 or other pricing
pressures, with a possible adverse effect on our profitability, especially where increases in these
costs exceed price increases on finished products. In recent years, our operating companies have
faced strong inflationary and other pricing pressures with respect to steel, fuel, resin, lumber,
concrete, aluminum and health care costs, which have been partially mitigated by pricing
adjustments.
2007 EXPECTATIONS
We anticipate 2007 diluted earnings per share from continuing operations to be in a range from
$1.60 to $1.80. Contributing to our earnings guidance for 2007 are the following items:
|
|
•
|
|
We expect slightly improved performance in our electric segment in 2007.
|
|
|
|
|
•
|
|
We expect our plastics segment’s performance to return to more historical levels in 2007
following two strong years in 2005 and 2006.
|
|
|
|
|
•
|
|
We expect continued enhancements in productivity and capacity utilization, strong
backlogs and an announced expansion of DMI’s Ft. Erie, Ontario facility that will increase
the facility’s production capacity by 30% to result in increased net income in our
manufacturing segment in 2007.
|
|
|
|
|
•
|
|
We expect moderate net income growth in our health services segment in 2007.
|
|
|
|
|
•
|
|
We expect our food ingredient processing business (IPH) to generate net income in the
range of $2.0 million to $4.0 million in 2007.
|
|
|
|
|
•
|
|
We expect our other business operations segment to have lower earnings in 2007 compared
with 2006 due to an expected return to more normal unallocated corporate cost levels. The
construction companies are expected to have a strong 2007 given backlogs at December 31,
2006.
|
Our outlook for 2007 is dependent on a variety of factors and is subject to the risks and
uncertainties discussed under “Risk Factors and Cautionary Statements.”
LIQUIDITY
We believe our financial condition is strong and that our cash, other liquid assets, operating cash
flows, access to capital markets through our universal shelf registration and borrowing ability
because of solid credit ratings, when taken together, provide adequate resources to fund ongoing
operating requirements and future capital expenditures related to expansion of existing businesses
and development of new projects. Additional equity or debt financing will be required in the period
2007 through 2011 given our current capital expansion plans over
this period. See “Capital Resources” section for further discussion. Also, our operating cash flow
and access to capital markets can be impacted by macroeconomic factors outside our control. In
addition, our borrowing costs can be impacted by short-term and long-term debt ratings assigned to
us by independent rating agencies, which in part are based on certain credit measures such as
interest coverage and leverage ratios.
We have achieved a high degree of long-term liquidity by maintaining desired capitalization ratios
and solid credit ratings, implementing cost-containment programs and investing in projects that
provide returns in excess of our weighted average cost of capital.
Cash provided by operating activities from continuing and discontinued operations was $80.2 million
in 2006 compared with $95.8 million in 2005. The $15.6 million decrease in cash from operations
reflects an increase in cash used for working capital items of $24.4 million and a $3.2 million
decrease in net income from continuing operations, offset by a $5.7 million reduction in noncash
gains on derivatives, a $3.5 million increase in noncash depreciation expenses and a $3.3 million
noncash reduction in allowance for equity funds used during construction. Net cash used for working
capital items was $30.4 million in 2006 compared with $6.0 million in 2005. The $30.4 million in
cash used for working capital in 2006 reflects increases at DMI of $13.3 million in receivables,
$6.9 million in inventory and $17.4 million in costs in excess of billings, offset by an $18.4
million increase in billings in excess of costs related to increased production of wind towers at
the West Fargo plant and as a result of starting up a new plant in Ft. Erie, Ontario in 2006. The
increase of $13.3 million in receivables at DMI is due to increased sales volumes between the years
and a major customer electing different payment terms in the fourth quarter of 2006. Receivables at
our construction companies are up $12.8 million as of December 31, 2006 compared to December 31,
2005 as a result of increased construction activity. The increase in working capital items also
reflects a $5.7 million increase in inventories at our plastic pipe companies more than offset by a
decrease in receivables of $7.9 million as sales declined in the fourth quarter of 2006.
The $37.5 million increase in net cash used in investing activities in 2006 compared with 2005
reflects a $32.2 million decrease in proceeds from the sales of discontinued operations, mainly
reflecting proceeds from the sales of MIS, SGS and CLC in 2005, and a $9.5 million increase in
capital expenditures. A breakdown of capital expenditures by segment is provided below under
“Capital Requirements.” We completed no acquisitions in 2006.
Net cash used in financing activities was $13.3 million in 2006 compared with net cash used in
financing activities of $62.0 million in 2005. Major uses of cash for financing activities in 2006
were $33.9 million for the payment of dividends on common shares outstanding and $3.3 million for
the retirement of long-term debt. Major sources of cash from financing activities in 2006 were
$22.9 million from a net increase in short-term borrowings and $2.4 million from the issuance of
common stock.
CAPITAL REQUIREMENTS
We have a capital expenditure program for expanding, upgrading and improving our plants and
operating equipment. Typical uses of cash for capital expenditures are investments in electric
generation facilities, transmission and distribution lines, equipment used in the manufacturing
process, purchase of diagnostic medical equipment, transportation equipment and computer hardware
and information systems. The capital expenditure program is subject to review and is revised
annually in light of changes in demands for energy, technology, environmental laws, regulatory
changes, business expansion opportunities, the costs of labor, materials and equipment and our
consolidated financial condition.
Consolidated capital expenditures for the years 2006, 2005 and 2004 were $69.4 million, $60.0
million and $49.5 million, respectively. Estimated capital expenditures for 2007 are $167 million
and the total capital expenditures for the five-year period 2007 through 2011 are estimated to be
approximately $889 million, which includes $360 million for our share of expected expenditures for
construction of the planned Big Stone II electric generating plant and related transmission assets
if all necessary permits and approvals are granted on a timely basis. The breakdown of 2004, 2005
and 2006 actual and 2007 through 2011 estimated capital expenditures by segment is as follows:
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(in millions)
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2004
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2005
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2006
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2007
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2007—2011
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|
|
|
|
|
|
Electric
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$
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25
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$
|
30
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|
|
$
|
35
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|
|
$
|
130
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|
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|
$
|
776
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Plastics
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3
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|
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|
4
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5
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|
|
|
12
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|
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|
|
19
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Manufacturing
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13
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|
|
|
16
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|
|
20
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|
|
|
19
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|
|
|
|
59
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Health services
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|
|
4
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|
|
|
3
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|
|
|
5
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|
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2
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12
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Food ingredient processing
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4
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3
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|
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2
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|
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3
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|
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|
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17
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Other business operations
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1
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4
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2
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1
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6
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|
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Total
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$
|
50
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|
|
$
|
60
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|
|
$
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69
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|
|
$
|
167
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|
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$
|
889
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The following table summarizes our contractual obligations at December 31, 2006 and the effect
these obligations are expected to have on our liquidity and cash flow in future periods.
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Less than
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1—3
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3—5
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More than
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(in millions)
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Total
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1 year
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years
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years
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5 years
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Long-term debt obligations
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$
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259
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|
|
$
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55
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$
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6
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|
|
$
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93
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|
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$
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105
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|
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Interest on long-term debt obligations
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|
|
130
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|
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15
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|
|
|
24
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|
|
|
24
|
|
|
|
67
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|
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Operating lease obligations
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|
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154
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|
|
|
41
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|
|
|
69
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|
|
|
33
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|
|
|
11
|
|
|
Capacity and energy requirements
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|
|
95
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|
|
|
20
|
|
|
|
40
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|
|
|
11
|
|
|
|
24
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|
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Coal contracts (required minimums)
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|
|
80
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|
|
|
17
|
|
|
|
14
|
|
|
|
14
|
|
|
|
35
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|
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Postretirement benefit obligations
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|
|
49
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|
|
|
4
|
|
|
|
7
|
|
|
|
7
|
|
|
|
31
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|
|
Other purchase obligations
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|
|
38
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|
|
|
38
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|
|
|
—
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|
|
—
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|
|
—
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|
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Total contractual cash obligations
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$
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805
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|
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$
|
190
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|
|
$
|
160
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|
|
$
|
182
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|
|
$
|
273
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Interest on $10.4 million of variable-rate debt outstanding on December 31, 2006 was projected
based on the interest rates applicable to that debt instrument on December 31, 2006.
CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, our universal shelf registration, unused
lines of credit, strong financial coverages, solid credit ratings, and alternative financing
arrangements such as leasing. We have the ability to issue up to $256 million of common stock,
preferred stock, debt and certain other securities from time to time under our universal shelf
registration statement filed with the Securities and Exchange Commission. Additional equity or debt
financing will be required in the period 2007 through 2011 given the expansion plans related to our
electric segment to fund the construction of the proposed new Big Stone II generating station at
the Big Stone Plant site and a proposed new wind generation project, in the event we decide to
refund or retire early any of our presently outstanding debt or cumulative preferred shares, to
complete acquisitions or for other corporate purposes. There can be no assurance that any
additional required financing will be available through bank borrowings, debt or equity financing
or otherwise, or that if such financing is available, it will be available on terms acceptable to
us. If adequate funds are not available on acceptable terms, our businesses, results of operations
and financial condition could be adversely affected.
On April 26, 2006 we renewed our line of credit with U.S. Bank National Association, JPMorgan Chase
Bank, N.A., Wells Fargo Bank, National Association, Harris Nesbitt Financing, Inc., Keybank
National Association, Union Bank of California, N.A., Bank of America, N.A., Bank Hapoalim B.M.,
and Bank of the West and increased the amount available under the line from $100 million to $150
million. The renewed agreement expires on April 26, 2009. The terms of the renewed line of credit
are essentially the same as those in place prior to the renewal. However, outstanding letters of
credit issued by the company can reduce the amount available for borrowing under the line by up to
$30 million and can increase our commitments under the renewed line of credit up to $200 million.
Borrowings under the line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based
on the ratings of our senior unsecured debt. Our bank line of credit is a key source of operating
capital and can provide interim financing of working capital and other capital requirements, if
needed. This line is an unsecured revolving credit facility available only to support borrowings of
our nonelectric operations. Our obligations under this line of credit are guaranteed by a
100%-owned subsidiary that owns substantially all of our nonelectric companies. As of December 31,
2006, $35.0 million of the $150 million line of credit was in use and $18.3 million was restricted
from use to cover outstanding letters of credit.
On September 1, 2006 we entered into a separate $25 million line of credit with U.S. Bank National
Association. This line of credit creates an unsecured revolving credit facility the electric
utility can draw on to support the
working capital needs and other capital requirements of its
electric operations. This line of credit expires on September 1, 2007. Borrowings under this line
of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of our
senior unsecured debt. This line of credit contains terms that are substantially the same as those
under the $150 million line of credit. As of December 31, 2006, $3.9 million of the $25 million
line of credit was in use.
In February 2007, we entered into a note purchase agreement with Cascade Investment L.L.C.
(Cascade) pursuant to which we agreed to issue to Cascade, in a private placement transaction, $50
million aggregate principal amount of our senior notes due November 30, 2017. Cascade is our
largest shareholder, owning approximately 8.7% of our outstanding common stock as of December 31,
2006. The notes are expected to be priced based on the 10 year US Treasury Forward rate plus 110
basis points, subject to adjustment in the event certain ratings assigned to our long-term senior
unsecured indebtedness are downgraded below specific levels prior to the closing of the note
purchase. The terms of the note purchase agreement are substantially similar to the terms of the
note purchase agreement entered into in connection with the issuance of our $90 million 6.63%
senior notes due December 1, 2011. The closing is expected to occur on December 3, 2007 subject to
the satisfaction of certain conditions to closing, such as, there has been no event or events
having a material adverse effect on the company as a whole, certain senior executives will still be
in their roles, there has been no change in control nor impermissible sale of assets, the
consolidated debt ratio to earnings before interest, taxes, depreciation and amortization as of
September 30, 2007 will be less than 3.5 to 1, certain waivers will have been obtained and certain
other customary conditions of closing will have been satisfied.
We have the right to terminate the note purchase agreement by giving at least 30 days’ prior
written notice to Cascade and paying a termination fee of $1 million. The proceeds of this
financing will be used to redeem our $50 million 6.375% senior debentures due December 1, 2007.
Our lines of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain
the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest
and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority
debt not be in excess of 20% of total capitalization. We were in compliance with all of the
covenants under our financing agreements as of December 31, 2006.
Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns
substantially all of our nonelectric companies. Our Grant County and Mercer County pollution
control refunding revenue bonds and our 5.625% insured senior notes require that we grant to Ambac
Assurance Corporation, under a financial guaranty insurance policy relating to the bonds and notes,
a security interest in the assets of the electric utility if the rating on our senior unsecured
debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).
Our securities ratings at December 31, 2006 are:
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|
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|
|
|
|
|
|
|
|
Moody’s
|
|
|
|
|
|
|
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Investors
|
|
|
Standard
|
|
|
|
|
Service
|
|
|
& Poor’s
|
|
|
Senior unsecured debt
|
|
|
A3
|
|
|
BBB+
|
|
Preferred stock
|
|
Baa2
|
|
BBB-
|
|
Outlook
|
|
Stable
|
|
Stable
|
Disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities.
Downgrades in these securities ratings could adversely affect our company. Further downgrades could
increase borrowing costs
resulting in possible reductions to net income in future periods and
increase the risk of default on our debt obligations.
Our ratio of earnings to fixed charges from continuing operations, which includes imputed finance
costs on operating leases, was 3.9x for 2006 compared to 4.3x for 2005 and our long-term debt interest
coverage ratio before taxes was 6.2x for 2006 compared to 6.4x for 2005. During 2007, we expect
these coverage ratios to be consistent with 2006 levels assuming 2007 net income meets our
expectations.
OFF-BALANCE-SHEET ARRANGEMENTS
We do not have any off-balance-sheet arrangements or any relationships with unconsolidated entities
or financial partnerships. These entities are often referred to as structured finance special
purpose entities or variable interest entities, which are established for the purpose of
facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes.
We are not exposed to any financing, liquidity, market or credit risk that could arise if we had
such relationships.
RISK FACTORS AND CAUTIONARY STATEMENTS
We are including the following factors and cautionary statements in this Annual Report to make
applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statements made by us or on our behalf. Forward-looking
statements include statements concerning plans, objectives, goals, strategies, future events or
performance, and underlying assumptions (many of which are based, in turn, upon further
assumptions) and other statements that are other than statements of historical facts. From time to
time, we may publish or otherwise make available forward-looking statements of this nature. All
these forward-looking statements, whether written or oral and whether made by us or on our behalf,
are also expressly qualified by these factors and cautionary statements. Forward-looking statements
involve risks and uncertainties, which could cause actual results or outcomes to differ materially
from those expressed.
Any forward-looking statement contained in this document speaks only as of the date on which the
statement is made, and we undertake no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which the statement is
made or to reflect the occurrence of unanticipated events. New factors emerge from time to time,
and it is not possible for us to predict all of the factors, nor can we assess the effect of each
factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement. The following factors and the other matters discussed herein are
important factors that could cause actual results or outcomes for our company to differ materially
from those discussed in the forward-looking statements included elsewhere in this document.
GENERAL
Federal and state environmental regulation could require us to incur substantial capital
expenditures which could result in increased operating costs.
We are subject to federal, state and local environmental laws and regulations relating to air
quality, water quality, waste management, natural resources and health safety. These laws and
regulations regulate the modification and operation of existing facilities, the construction and
operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous
waste and toxic substances. Compliance with these legal requirements requires us to commit
significant resources and funds toward environmental monitoring, installation and operation of
pollution control equipment, payment of emission fees and securing environmental permits. Obtaining
environmental permits can entail significant expense and cause substantial construction delays.
Failure to comply with environmental laws and regulations, even if caused by factors beyond our
control, may result in civil or criminal liabilities, penalties and fines.
Existing environmental laws or regulations may be revised and new laws or regulations may be
adopted or become applicable to us. Revised or additional regulations, which result in increased
compliance costs or additional operating restrictions, particularly if those costs are not fully
recoverable from customers, could have a material effect on our results of operations.
Volatile financial markets could restrict our ability to access capital and increase our borrowing
costs and pension plan expenses.
We rely on access to both short- and long-term capital markets as a source of liquidity for capital
requirements not satisfied by cash flows from operations. If we are not able to access capital at
competitive rates, the ability to implement our business plans may be adversely affected. Market
disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely
affect our ability to access one or more financial markets.
Changes in the U.S. capital markets could also have significant effects on our pension plan. Our
pension income or expense is affected by factors including the market performance of the assets in
the master pension trust maintained for the pension plans for some of our employees, the weighted
average asset allocation and long-term rate of return of our pension plan assets, the discount rate
used to determine the service and interest cost components of our net periodic pension cost and
assumed rates of increase in our employees’ future compensation. If our pension plan assets do not
achieve positive rates of return, or if our estimates and assumed rates are not accurate, our
company’s earnings may decrease because net periodic pension costs would rise and we could be
required to provide additional funds to cover our obligations to employees under the pension plan.
Our plans to grow and diversify through acquisitions may not be successful, which could result in
poor financial performance.
As part of our business strategy, we intend to acquire new businesses. We may not be able to
identify appropriate acquisition candidates or successfully negotiate, finance or integrate
acquisitions. If we are unable to make acquisitions, we may be unable to realize the growth we
anticipate. Future acquisitions could involve numerous risks including: difficulties in integrating
the operations, services, products and personnel of the acquired business; and the potential loss of key employees, customers and suppliers of the acquired
business. If we are unable to successfully manage these risks of an acquisition, we could face
reductions in net income in future periods.
Our plans to grow our nonelectric businesses could be limited by state law.
Our plans to acquire and grow our nonelectric businesses could be adversely affected by legislation
in one or more states that may attempt to limit the amount of diversification permitted in a
holding company system that includes a regulated utility company or affiliated nonelectric
companies.
ELECTRIC
We may experience fluctuations in revenues and expenses related to our electric operations, which
may cause our financial results to fluctuate and could impair our ability to make distributions to
shareholders or scheduled payments on our debt obligations.
A number of factors, many of which are beyond our control, may contribute to fluctuations in our
revenues and expenses from electric operations, causing our net income to fluctuate from period to
period. These risks include fluctuations in the volume and price of sales of electricity to
customers or other utilities, which may be affected by factors such as mergers and acquisitions of
other utilities, geographic location of other utilities, transmission costs (including increased
costs related to operations of regional transmission organizations), changes in the manner in which
wholesale power is sold and purchased, unplanned interruptions at our generating plants, the
effects of regulation and legislation, demographic changes in our customer base and changes in our
customer demand or load growth. Electric wholesale margins have been significantly and adversely
affected by increased efficiencies in the MISO market. Electric wholesale trading margins could
also be adversely affected by losses due to trading activities. Other risks include weather
conditions (including severe weather that could result in damage to our assets), fuel and purchased
power costs and the rate of economic growth or decline in our service areas. A decrease in revenues
or an increase in expenses related to our electric operations may reduce the amount of funds
available for our existing and future businesses, which could result in increased financing
requirements, impair our ability to make expected distributions to shareholders or impair our
ability to make scheduled payments on our debt obligations.
As of December 31, 2006, we had capitalized $6.1 million in costs related to the planned
construction of a second electric generating unit at our Big Stone Plant site. If the project is
abandoned for permitting or other reasons, these capitalized costs and others incurred in future
periods may be subject to expense and may not be recoverable.
Actions by the regulators of our electric operations could result in rate reductions, lower
revenues and earnings or delays in recovering capital expenditures.
We are subject to federal and state legislation, government regulations and regulatory actions that
may have a negative impact on our business and results of operations. The electric rates that we
are allowed to charge for our electric services are one of the most important items influencing our
financial position, results of operations and liquidity. The rates that we charge our electric
customers are subject to review and determination by state public utility commissions in Minnesota,
North Dakota and South Dakota. We are scheduled to file a rate case in Minnesota on or before
October 1, 2007. We are also regulated by the Federal Energy Regulatory Commission. An adverse
decision by one or more regulatory commissions concerning the level or method of determining
electric utility rates, the authorized returns on equity, implementation of enforceable federal
reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of
nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other
proceeding (including with respect to the recovery of capital expenditures in rates) could result
in lower revenues and net income.
Recovery of MISO schedule 16 and 17 administrative costs associated with providing electric service
to Minnesota customers are currently being deferred pending our next general rate case scheduled to
be filed on or before October 1, 2007. If we are not granted recovery of $0.4 million in deferred
costs as of December 31, 2006, we could be required to recognize these costs immediately in expense
at the time recovery is denied. Also, all MISO-related energy administrative and other costs
associated with providing electric service to North Dakota customers have been, and continue to be,
recovered under a temporary order from the North Dakota Public Service Commission and are subject
to refund if later disallowed.
We may not be able to respond effectively to deregulation initiatives in the electric industry,
which could result in reduced revenues and earnings.
We may not be able to respond in a timely or effective manner to the changes in the electric
industry that may occur as a result of regulatory initiatives to increase wholesale competition.
These regulatory initiatives may include further deregulation of the electric utility industry in
wholesale markets. Although we do not expect retail competition to come to the states of Minnesota,
North Dakota and South Dakota in the foreseeable future, we expect competitive forces in the
electric supply segment of the electric business to continue to increase, which could reduce our
revenues and earnings.
Our electric generating facilities are subject to operational risks that could result in
unscheduled plant outages, unanticipated operation and maintenance expenses and increased power
purchase costs.
Operation of electric generating facilities involves risks which can adversely affect energy output
and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number
of suppliers of coal, making us vulnerable to increased prices for fuel as existing contracts
expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper
of the Burlington Northern Santa Fe Railroad for shipments of coal to our Big Stone and Hoot Lake
plants, making us vulnerable to increased prices for coal transportation from a sole supplier.
Higher fuel prices result in higher electric rates for our retail customers through fuel clause
adjustments and could make us less competitive in wholesale electric markets. Operational risks
also include facility shutdowns due to breakdown or failure of equipment or processes, labor
disputes, operator error and catastrophic events such as fires, explosions, floods, intentional
acts of destruction or other similar occurrences affecting the electric generating facilities. The
loss of a major generating facility would require us to find other sources of supply, if available,
and expose us to higher purchased power costs.
Changes to regulation of generating plant emissions, including but not limited to carbon dioxide
(CO2) emissions, could affect our operating costs and the costs of supplying electricity to our
customers.
PLASTICS
Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a
limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply
of PVC resin, could result in reduced sales or increased costs for our plastics business.
We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two
vendors accounted for approximately 99% of our total purchases of PVC resin in 2006 and
approximately 97% of our total purchases of PVC resin in 2005. In addition, the supply of PVC resin
may be limited primarily due to manufacturing capacity and the limited availability of raw material
components. A majority of U.S. resin production plants are located in the Gulf Coast region, which may increase the risk of a shortage
of resin in the event of a hurricane or other natural disaster in that region. The loss of a key
vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our
ability to deliver our plastic products, cause customers to cancel orders or require us to incur
additional expenses to obtain PVC resin from alternative sources, if such sources are available.
We compete against a large number of other manufacturers of PVC pipe and manufacturers of
alternative products. Customers may not distinguish our products from those of our competitors.
The plastic pipe industry is highly fragmented and competitive, due to the large number of
producers and the fungible nature of the product. We compete not only against other PVC pipe
manufacturers, but also against ductile iron, steel, concrete and clay pipe manufacturers. Due to
shipping costs, competition is usually regional, instead of national, in scope, and the principal
areas of competition are a combination of price, service, warranty and product performance. Our
inability to compete effectively in each of these areas and to distinguish our plastic pipe
products from competing products may adversely affect the financial performance of our plastics
business.
Reductions in PVC resin prices can negatively affect our plastics business.
The PVC pipe industry is highly sensitive to commodity raw material pricing volatility.
Historically, when resin prices are rising or stable, margins and sales volume have been higher and
when resin prices are falling, sales volumes and margins have been lower. Reductions in PVC resin
prices could negatively affect PVC pipe prices, profit margins on PVC pipe sales and the value of
PVC pipe held in inventory.
MANUFACTURING
Competition from foreign and domestic manufacturers, the price and availability of raw materials,
the availability of production tax credits and general economic conditions could affect the
revenues and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to risks associated with competition from foreign and
domestic manufacturers that have excess capacity, labor advantages and other capabilities that may
place downward pressure on margins and profitability. Raw material costs for items such as steel,
lumber, concrete, aluminum and resin have increased significantly and may continue to increase. Our
manufacturers may not be able to pass on the cost of such increases to their respective customers.
Each of our manufacturing companies has significant customers and concentrated sales to such
customers. If our relationships with significant customers should change materially, it would be
difficult to immediately and profitably replace lost sales. We believe the demand for wind towers
that we manufacture will depend primarily on the existence of either renewable portfolio standards
or a
federal production tax credit for wind energy. A federal production tax credit is in place
through December 31, 2008. Our wind tower manufacturer and electrical contractor could be adversely
affected if the tax credit in not extended or renewed.
HEALTH SERVICES
Changes in the rates or methods of third-party reimbursements for our diagnostic imaging services
could result in reduced demand for those services or create downward pricing pressure, which would
decrease our revenues and earnings.
Our health services businesses derive significant revenue from direct billings to customers and
third-party payors such as Medicare, Medicaid, managed care and private health insurance companies
for our diagnostic imaging services. Moreover, customers who use our diagnostic imaging services
generally rely on reimbursement from third-party payors. Adverse changes in the rates or methods of
third-party reimbursements could reduce the number of procedures for which we or our customers can obtain reimbursement or the amounts
reimbursed to us or our customers.
Our health services operations has a dealership and other agreements with Philips Medical from
which it derives significant revenues from the sale and service of Philips Medical diagnostic
imaging equipment.
This agreement can be terminated on 180 days written notice by either party for any reason. It also
includes other compliance requirements. If this agreement were terminated within the notice
provisions or we were not able to renew such agreements or comply with the agreement, the financial
results of our health services operations would be adversely affected.
Technological change in the diagnostic imaging industry could reduce the demand for diagnostic
imaging services and require our health services operations to incur significant costs to upgrade
its equipment.
Although we believe substantially all of our diagnostic imaging systems can be upgraded to maintain
their state-of-the-art character, the development of new technologies or refinements of existing
technologies might make our existing systems technologically or economically obsolete, or cause a
reduction in the value of, or reduce the need for, our systems.
Actions by regulators of our health services operations could result in monetary penalties or
restrictions in our health services operations.
Our health services operations are subject to federal and state regulations relating to licensure,
conduct of operations, ownership of facilities, addition of facilities and services and payment of
services. Our failure to comply with these regulations, or our inability to obtain and maintain
necessary regulatory approvals, may result in adverse actions by regulators with respect to our
health services operations, which may include civil and criminal penalties, damages, fines,
injunctions, operating restrictions or suspension of operations. Any such action could adversely
affect our financial results. Courts and regulatory authorities have not fully interpreted a
significant number of these laws and regulations, and this uncertainty in interpretation increases
the risk that we may be found to be in violation. Any action brought against us for violation of
these laws or regulations, even if successfully defended, may result in significant legal expenses
and divert management’s attention from the operation of our businesses.
FOOD INGREDIENT PROCESSING
Our company that processes dehydrated potato flakes, flour and granules competes in a highly
competitive market and is dependent on adequate sources of potatoes for processing.
The market for processed, dehydrated potato flakes, flour and granules is highly competitive.
The profitability and success of our potato processing company is dependent on superior product
quality, competitive product pricing, strong customer relationships, raw material costs, natural
gas prices and availability and customer demand for finished goods. In most product categories, our
company competes with numerous manufacturers of varying sizes in the United States.
The principal raw material used by our potato processing company is washed process-grade potatoes
from growers. These potatoes are unsuitable for use in other markets due to imperfections. They are
not subject to the United States Department of Agriculture’s general requirements and expectations
for size, shape or color. While our food ingredient processing company has processing capabilities
in three geographically distinct growing regions, there can be no assurance it will be able to
obtain raw materials due to poor growing conditions, a loss of key growers and other factors. A
loss or shortage of raw materials or the necessity of paying much higher prices for raw materials
or natural gas could adversely affect the financial performance of this company. Fluctuations in
foreign currency exchange rates could have a negative impact on our potato processing company’s net
income and competitive position because approximately 32% of its sales are outside the United
States and the Canadian plant pays its operating expenses in Canadian dollars.
We currently have $24.2 million of goodwill and a $3.2 million nonamortizable trade name recorded
on our balance sheet related to the acquisition of IPH in 2004. If current conditions of low sales
prices, high energy and raw material costs, shortage of raw potato supplies and the increased value
of the Canadian dollar relative to the U.S. dollar persist and operating margins do not improve
according to our projections, the reductions in anticipated cash flows from this business may
indicate that its fair value is less than its book value resulting in an impairment of goodwill and
nonamortizable intangible assets and a corresponding charge against earnings.
OTHER BUSINESS OPERATIONS
Our construction companies may be unable to properly bid and perform on projects.
The profitability and success of our construction companies require us to identify, estimate and
timely bid on profitable projects. The quantity and quality of projects up for bids at any time is
uncertain. Additionally, once a project is awarded, we must be able to perform within cost
estimates that were set when the bid was submitted and accepted. A significant failure or an
inability to properly bid or perform on projects could lead to adverse financial results for our
construction companies.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At December 31, 2006 we had limited exposure to market risk associated with interest rates and
commodity prices and limited exposure to market risk associated with changes in foreign currency
exchange rates. Outstanding trade accounts receivable of the Canadian operations of IPH are not at
risk of valuation change due to changes in foreign currency exchange rates because the Canadian
company transacts all sales in U.S. dollars. However, IPH does have market risk related to changes
in foreign currency exchange rates because approximately 32% of IPH sales are outside the United
States and the Canadian operations of IPH pays its operating expenses in Canadian dollars.
The majority of our consolidated long-term debt has fixed interest rates. The interest rate on
variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We
manage our interest rate risk through the issuance of fixed-rate debt with varying maturities,
through economic refunding of debt through optional refundings, limiting the amount of variable
interest rate debt, and the utilization of short-term borrowings
to allow flexibility in the timing
and placement of long-term debt. As of December 31, 2006 we had $10.4 million of long-term debt
subject to variable interest rates. Assuming no change in our financial structure, if variable
interest rates were to average one percentage point higher or lower than the average variable rate
on December 31, 2006, annualized interest expense and pre-tax earnings would change by
approximately $104,000.
We have not used interest rate swaps to manage net exposure to interest rate changes related to our
portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain
range. It is our policy to enter into interest rate transactions and other financial instruments
only to the extent considered necessary to meet our stated objectives. We do not enter into
interest rate transactions for speculative or trading purposes.
The plastics companies are exposed to market risk related to changes in commodity prices for PVC
resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to
commodity raw material pricing volatility. Historically, when resin prices are rising or stable,
margins and sales volume have been higher and when resin prices are falling, sales volumes and
margins have been lower. Gross margins also decline when the supply of PVC pipe increases faster
than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors
worldwide, it is very difficult to predict gross margin percentages or to assume that historical
trends will continue.
The electric utility has market, price and credit risk associated with forward contracts for the
purchase and sale of electricity. As of December 31, 2006 the electric utility had recognized, on a
pretax basis, $203,000 in net unrealized gains on open forward contracts for the purchase and sale
of electricity. Due to the nature of electricity and the physical aspects of the electricity
transmission system, unanticipated events affecting the transmission grid can cause transmission
constraints that result in unanticipated gains or losses in the process of settling transactions.
The market prices used to value the electric utility’s forward contracts for the purchases and
sales of electricity are determined by survey of counterparties or brokers used by the electric
utility’s power services’ personnel responsible for contract pricing, as well as prices gathered
from daily settlement prices published by the Intercontinental Exchange. Prices are benchmarked to
regional hub prices as published in
Megawatt Daily
and forward price curves and indices acquired
from a third party price forecasting service. Of the forward energy contracts that are marked to
market as of December 31, 2006, all of the forward sales of electricity had offsetting purchases in
terms of volumes and delivery periods.
We have in place an energy risk management policy with a goal to manage, through the use of defined
risk management practices, price risk and credit risk associated with wholesale power purchases and
sales. With the advent of the MISO Day 2 market in April 2005, we made several changes to our
energy risk management policy to recognize new trading opportunities created by this new market.
Most of the changes were in new volumetric limits and loss limits to adequately manage the risks
associated with these new opportunities. In addition, we implemented a Value at Risk (VaR) limit to
further manage market price risk. Exposure to price risk on any open positions as of December 31,
2006 was not material.
The following tables show the effect of marking to market forward contracts for the purchase and
sale of electricity on our consolidated balance sheet as of December 31, 2006 and the change in our
consolidated balance sheet position from December 31, 2005 to December 31, 2006:
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
|
|
Current asset — marked-to-market gain
|
|
$
|
2,215
|
|
|
Regulatory asset — deferred marked-to-market loss
|
|
|
—
|
|
|
|
|
|
|
|
Total assets
|
|
|
2,215
|
|
|
Current liability — marked-to-market loss
|
|
|
(2,012
|
)
|
|
Regulatory liability — deferred marked-to-market gain
|
|
|
—
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
(2,012
|
)
|
|
|
|
|
|
|
Net fair value of marked-to-market energy contracts
|
|
$
|
203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
(in thousands)
|
|
December 31, 2006
|
|
|
|
|
Fair value at beginning of year
|
|
$
|
2,916
|
|
|
Amount realized on contracts entered into in 2005 and settled in 2006
|
|
|
(2,090
|
)
|
|
Changes in fair value of contracts entered into in 2005
|
|
|
(826
|
)
|
|
|
|
|
|
|
Net fair value of contracts entered into in 2005 at year end 2006
|
|
|
—
|
|
|
Changes in fair value of contracts entered into in 2006
|
|
|
203
|
|
|
|
|
|
|
|
Net fair value at end of year
|
|
$
|
203
|
|
|
|
|
|
|
The $203,000 in recognized but unrealized net gain on the forward energy purchases and sales marked
to market on December 31, 2006 is expected to be realized on physical settlement as scheduled over
the following quarters in the amounts listed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter
|
|
2nd Quarter
|
|
|
|
(in thousands)
|
|
2007
|
|
2007
|
|
Total
|
|
|
|
Net gain
|
|
$
|
159
|
|
|
$
|
44
|
|
|
$
|
203
|
|
We have credit risk associated with the nonperformance or nonpayment by counterparties to our
forward energy purchases and sales agreements. We have established guidelines and limits to manage
credit risk associated with wholesale power purchases and sales. Specific limits are determined by
a counterparty’s financial strength. Our credit risk with our largest counterparty on delivered and
marked-to-market forward contracts as of December 31, 2006 was $4.3 million. As of December 31,
2006 we had a net credit risk exposure of $7.2 million from 12 counterparties with investment grade
credit ratings. We have no exposure at December 31, 2006 to counterparties with credit ratings
below investment grade. Counterparties with investment grade credit ratings have minimum credit
ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch).
The $7.2 million credit risk exposure includes net amounts due to the electric utility on
receivables/payables from completed transactions billed and unbilled plus marked-to-market
gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery
after December 31, 2006. Individual counterparty exposures are offset according to legally
enforceable netting arrangements.
IPH has market risk associated with the price of fuel oil and natural gas used in its potato
dehydration process as IPH may not be able increase prices for its finished products to recover
increases in fuel costs. In the third quarter
of 2006, IPH entered into forward natural gas contracts on the New York Mercantile Exchange market
to hedge its exposure to fluctuations in natural gas prices related to approximately 50% of its
anticipated natural gas needs through March 2007 for its Ririe, Idaho and Center, Colorado
dehydration plants. These forward contracts are derivatives subject to mark-to-market accounting
but they do not qualify for hedge accounting treatment. IPH includes net changes in the market
values of these forward contracts in net income as components of cost of goods sold in the period
of recognition. IPH had $371,000 in marked-to-market losses on forward natural gas contracts
outstanding on December 31, 2006, and had recorded $171,000 in net realized losses on contracts
that settled in 2006. IPH’s forward natural gas swaps marked to market as of December 31, 2006 are
scheduled for settlement in the first quarter of 2007.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
Our significant accounting policies are described in note 1 to consolidated financial statements.
The discussion and analysis of the financial statements and results of operations are based on our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The preparation of these
consolidated financial statements requires management to make estimates and judgments that affect
the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities.
We use estimates based on the best information available in recording transactions and balances
resulting from business operations. Estimates are used for such items as depreciable lives, asset
impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance
programs, valuation of forward energy contracts, unbilled electric revenues, unscheduled power
exchanges, MISO electric market residual load adjustments, service contract maintenance costs,
percentage-of-completion and actuarially determined benefits costs and liabilities. As better
information becomes available or actual amounts are known, estimates are revised. Operating results
can be affected by revised estimates. Actual results may differ from these estimates under
different assumptions or conditions. Management has discussed the application of these critical
accounting policies and the development of these estimates with the Audit Committee of the Board of
Directors. The following critical accounting policies affect the more significant judgments and
estimates used in the preparation of our consolidated financial statements.
PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS
Pension and postretirement benefit liabilities and expenses for our electric utility and corporate
employees are determined by actuaries using assumptions about the discount rate, expected return on
plan assets, rate of compensation increase and healthcare cost-trend rates. Further discussion of
our pension and postretirement benefit plans and related assumptions is included in note 12 to
consolidated financial statements.
These benefits, for any individual employee, can be earned and related expenses can be recognized
and a liability accrued over periods of up to 40 or more years. These benefits can be paid out for
up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to
these benefits are among our most critical accounting estimates. Although deferral and amortization
of fluctuations in actuarially determined benefit obligations and expenses are provided for when
actual results on a year-to-year basis deviate from long-range assumptions, compensation increases
and healthcare cost increases or a reduction in the discount rate applied from one year to the next
can significantly increase our benefit expenses in the year of the change. Also, a reduction in the
expected rate of return on pension plan assets in our funded pension plan or realized rates of
return on plan assets that are well below assumed rates of return could result in significant
increases in recognized pension benefit expenses in the year of the change or for many years
thereafter because actuarial losses can be amortized over the average remaining service lives of
active employees.
The pension benefit cost for 2007 for our noncontributory funded pension plan is expected to be
$5.9 million compared to $5.8 million in 2006. The estimated discount rate used to determine annual
benefit cost accruals will be 6.00% in 2007; the discount rate that was used in 2006 was 5.75%. In
selecting the discount rate, we use the yield of a fixed income debt security, which has a rating
of “Aa” published by a recognized rating agency, along with a bond matching model as a basis to
determine the rate.
Subsequent increases or decreases in actual rates of return on plan assets over assumed rates or
increases or decreases in the discount rate or rate of increase in future compensation levels could
significantly change projected costs. For 2006, all other factors being held constant: a 0.25
increase (or decrease) in the discount rate would have decreased (or increased) our 2006 pension
benefit cost by $620,000; a 0.25 increase (or decrease) in the assumed rate of increase in future
compensation levels would have increased (or decreased) our 2006 pension benefit cost by $570,000;
a 0.25 increase (or decrease) in the expected long-term rate of return on plan assets would have
decreased (or increased) our 2006 pension benefit cost by $360,000.
Increases or decreases in the discount rate or in retiree healthcare cost inflation rates could
significantly change our projected postretirement healthcare benefit costs. A 0.25 increase (or
decrease) in the discount rate would have decreased (or increased) our 2006 postretirement medical
benefit costs by $20,000. See note 12 to consolidated financial statements for the cost impact of a
change in medical cost inflation rates.
We believe the estimates made for our pension and other postretirement benefits are reasonable
based on the information that is known at the point in time the estimates are made. These estimates
and assumptions are subject to a number of variables and are subject to change.
REVENUE RECOGNITION
Our construction companies and two of our manufacturing companies record operating revenues on a
percentage-of-completion basis for fixed-price construction contracts. The method used to determine
the progress of completion is based on the ratio of labor costs incurred to total estimated labor
costs at our wind tower manufacturer, square footage completed to total bid square footage for
certain floating dock projects and costs incurred to total estimated costs on all other
construction projects. The duration of the majority of these contracts is less than a year.
Revenues recognized on jobs in progress as of December 31, 2006 were $284 million. Any expected
losses on jobs in progress at year-end 2006 have been recognized. We believe the accounting
estimate related to the percentage-of-completion accounting on uncompleted contracts is critical to
the extent that any underestimate of total expected costs on fixed-price construction contracts
could result in reduced profit margins being recognized on these contracts at the time of
completion.
FORWARD ENERGY CONTRACTS CLASSIFIED AS DERIVATIVES
Our electric utility’s forward contracts for the purchase and sale of electricity and our food
ingredient processing company’s forward natural gas swap transactions are derivatives subject to
mark-to-market accounting under accounting principles generally accepted in the United States. The
market prices used to value the electric utility’s forward contracts for the purchases and sales of
electricity are determined by survey of counterparties or brokers used by the electric utility’s
power services’ personnel responsible for contract pricing, as well as prices gathered from daily
settlement prices published by the Intercontinental Exchange. Prices are benchmarked to regional
hub prices as published in
Megawatt Daily
and forward price curves and indices acquired from a
third party price forecasting service and, as such, are estimates. Of the forward electric energy
contracts that are marked to market as of December 31, 2006, 100% of the forward energy purchases
for electricity have offsetting sales in terms of volumes and delivery periods. All of the forward
energy contracts for the purchase and sale of electricity marked to market as of December 31, 2006
are scheduled for settlement prior to June 1, 2007.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Our operating companies encounter risks associated with sales and the collection of the associated
accounts receivable. As such, they record provisions for accounts receivable that are considered to
be uncollectible. In order to calculate the appropriate monthly provision, the operating companies
primarily utilize historical rates of accounts receivables written off as a percentage of total
revenue. This historical rate is applied to the current revenues on a monthly basis. The historical
rate is updated periodically based on events that may change the rate, such as a significant
increase or decrease in collection performance and timing of payments as well as the calculated
total exposure in relation to the allowance. Periodically, operating companies compare identified
credit risks with allowances that have been established using historical experience and adjust
allowances accordingly. In circumstances where an operating company is aware of a specific
customer’s inability to meet financial obligations, the operating company records a specific
allowance for bad debts to reduce the net recognized receivable to the amount it reasonably
believes will be collected.
We believe the accounting estimates related to the allowance for doubtful accounts is critical
because the underlying assumptions used for the allowance can change from period to period and
could potentially cause a material impact to the income statement and working capital.
During 2006, $1.3 million of bad debt expense from continuing operations (0.12% of total 2006
revenue of $1.1 billion) was recorded and the allowance for doubtful accounts was $3.0 million
(1.8% of trade accounts receivable) as of December 31, 2006. General economic conditions and
specific geographic concerns are major factors that may affect the adequacy of the allowance and
may result in a change in the annual bad debt expense. An increase or decrease of one percentage
point in our consolidated allowance for doubtful accounts based on outstanding trade receivables at
December 31, 2006 would result in a $1.5 million increase or decrease in bad debt expense.
Although an estimated allowance for doubtful accounts on our operating companies’ accounts
receivable is provided for, the allowance for doubtful accounts on the electric segment’s wholesale
electric sales is insignificant in proportion to annual revenues from these sales. The electric
segment has not experienced a bad debt related to wholesale electric sales largely due to stringent
risk management criteria related to these sales. However, nonpayment on a single wholesale electric
sale could result in a significant bad debt expense.
DEPRECIATION EXPENSE AND DEPRECIABLE LIVES
The provisions for depreciation of electric utility property for financial reporting purposes are
made on the straight-line method based on the estimated service lives (5 to 65 years) of the
properties. Such provisions as a percent of the average balance of depreciable electric utility
property were 2.82% in 2006, 2.74% in 2005 and 2.77% in 2004. Depreciation rates on electric
utility property are subject to annual regulatory review and approval, and depreciation expense is
recovered through rates set by ratemaking authorities. Although the useful lives of electric
utility properties are estimated, the recovery of their cost is dependent on the ratemaking
process. Deregulation of the electric industry could result in changes to the estimated useful
lives of electric utility property that could impact depreciation expense.
Property and equipment of our nonelectric 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 useful lives (3 to 40 years)
of the related assets. We believe the lives and methods of determining depreciation are reasonable,
however, changes in economic conditions affecting the industries in which our nonelectric companies
operate or innovations in technology could result in a reduction of the estimated useful lives of
our nonelectric operating companies’ property, plant and equipment or in an impairment write-down
of the carrying value of these properties.
TAXATION
We are required to make judgments regarding the potential tax effects of various financial
transactions and our ongoing operations to estimate our obligations to taxing authorities. These
tax obligations include income, real estate and use taxes. These judgments include reserves for
potential adverse outcomes regarding uncertain tax positions that we have taken. While we believe
the resulting tax reserve balances as of December 31, 2006 reflect the most likely probable
expected outcome of these tax matters in accordance with SFAS No. 5,
Accounting for Contingencies,
and SFAS No. 109,
Accounting for Income Taxes
, the ultimate outcome of such matters could result in
additional adjustments to our consolidated financial statements. However, we do not believe such
adjustments would be material based on items currently reserved for.
Deferred income taxes are provided for revenue and expenses which are recognized in different
periods for income tax and financial reporting purposes. We assess our deferred tax assets for
recoverability based on both historical and anticipated earnings levels. We have not recorded a
valuation allowance related to the probability of recovery of our deferred tax assets as we believe
reductions in tax payments related to these assets will be fully realized in the future.
ASSET IMPAIRMENT
We are required to test for asset impairment relating to property and equipment whenever events or
changes in circumstances indicate that the carrying value of an asset might not be recoverable. We
apply SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets
, in order to
determine whether or not an asset is impaired. This standard requires an impairment analysis when
indicators of impairment are present. If such indicators are present, the standard requires that if
the sum of the future expected cash flows from a company’s asset, undiscounted and without interest
charges, is less than the carrying value, an asset impairment must be recognized in the financial
statements. The amount of the impairment is the difference between the fair value of the asset and
the carrying value of the asset.
We believe the accounting estimates related to an asset impairment are critical because they are
highly susceptible to change from period to period reflecting changing business cycles and require
management to make assumptions about future cash flows over future years and the impact of
recognizing an impairment could have a significant effect on operations. Management’s assumptions
about future cash flows require significant judgment because actual operating levels have
fluctuated in the past and are expected to continue to do so in the future.
As of December 31, 2006 an assessment of the carrying values of our long-lived assets and other
intangibles indicated that these assets were not impaired.
GOODWILL IMPAIRMENT
Goodwill is required to be evaluated annually for impairment, according to SFAS No. 142,
Goodwill
and Other Intangible Assets
. The standard requires a two-step process be performed to analyze
whether or not goodwill has been impaired. Step one is to test for potential impairment and
requires that the fair value of the reporting unit be compared to its book value including
goodwill. If the fair value is higher than the book value, no impairment is recognized. If the fair
value is lower than the book value, a second step must be performed. The second step is to measure
the amount of impairment loss, if any, and requires that a hypothetical purchase price allocation
be done to determine the implied fair value of goodwill. This fair value is then compared to the
carrying value of goodwill. If the implied fair value is lower than the carrying value, an
impairment must be recorded.
We believe accounting estimates related to goodwill impairment are critical because the underlying
assumptions used for the discounted cash flow can change from period to period and could
potentially cause a material impact to the income statement. Management’s assumptions about
inflation rates and other internal and external economic conditions, such as earnings growth rate,
require significant judgment based on fluctuating rates and
expected revenues. Additionally, SFAS
No. 142 requires goodwill be analyzed for impairment on an annual basis using the
assumptions that apply at the time the analysis is updated.
We evaluate goodwill for impairment on an annual basis and as conditions warrant. As of
December 31, 2006 an assessment of the carrying values of our goodwill indicated no impairment.
PURCHASE ACCOUNTING
We account for our acquisitions under the purchase method of accounting and, accordingly, the
acquired assets and liabilities assumed are recorded at their respective fair values. The excess of
purchase price over the fair value of the assets acquired and liabilities assumed is recorded as
goodwill. The recorded values of assets and liabilities are based on third party estimates and
valuations when available. The remaining values are based on management’s judgments and estimates,
and, accordingly, our consolidated financial position or results of operations may be affected by
changes in estimates and judgments.
Acquired assets and liabilities assumed that are subject to critical estimates include property,
plant and equipment and intangible assets.
The fair value of property, plant and equipment is based on valuations performed by qualified
internal personnel and/or outside appraisers. Fair values assigned to plant and equipment are based
on several factors including the age and condition of the equipment, maintenance records of the
equipment and auction values for equipment with similar characteristics at the time of purchase.
Intangible assets are identified and valued using the guidelines of SFAS No. 141,
Business Combinations
. The fair value of intangible assets is based on estimates including
royalty rates, customer attrition rates and estimated cash flows.
While the allocation of purchase price is subject to a high degree of judgment and uncertainty, we
do not expect the estimates to vary significantly once an acquisition is complete. We believe our
estimates have been reasonable in the past as there have been no significant valuation adjustments
to the final allocation of purchase price.
KEY ACCOUNTING PRONOUNCEMENTS
SFAS No. 123(R) (revised 2004),
Share-Based Payment,
issued in December 2004 is a revision of SFAS
No. 123,
Accounting for Stock-based Compensation,
and supersedes Accounting Principles Board
Opinion (APB) No. 25,
Accounting for Stock Issued to Employees
. Beginning in January 2006, we
adopted SFAS No. 123(R) on a modified prospective basis. We are required to record stock-based
compensation as an expense on our income statement over the period earned based on the fair value
of the stock or options awarded on their grant date. The application of SFAS No. 123(R) reporting
requirements resulted in recording incremental after-tax compensation expense in 2006 as follows:
|
|
•
|
|
$163,000 for non-vested stock options that were outstanding on December 31, 2005.
|
|
|
|
|
•
|
|
$235,000 for the 15% discount offered under our Employee Stock Purchase Plan.
|
See additional discussion under Share-based Payments in the footnotes to the consolidated financial
statements that follow. For years prior to 2006, we reported our stock-based compensation under the
requirements of APB No. 25 and furnished related pro forma footnote information required under SFAS
No. 123.
In November 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP)
No.
FAS 123(R)-3,
Transition Election Related to Accounting for Tax Effects of Share-Based Payment
Awards.
We elected to adopt the alternative transition method provided in FSP No. FAS 123(R)-3 for calculating the tax
effects of stock-based compensation. The alternative transition method includes simplified methods
to determine the beginning balance of the additional paid-in capital (APIC) pool related to the tax
effects of stock-based compensation, and to determine the subsequent impact on the APIC pool and
the statement of cash flows of the tax effects of stock-based awards that were fully vested and
outstanding upon the adoption of SFAS No. 123(R).
FASB Interpretation (FIN) No. 48,
Accounting for Uncertainty in Income Taxes — an interpretation of
FASB Statement No. 109,
was issued by the FASB in June 2006. FIN No. 48 clarifies the accounting
for uncertain tax positions in accordance with SFAS 109,
Accounting for Income Taxes
. We will be
required to recognize, in our financial statements, the tax effects of a tax position that is
“more-likely-than-not” to be sustained on audit based solely on the technical merits of the
position as of the reporting date. The term “more-likely-than-not” means a likelihood of more than
50%. FIN No. 48 also provides guidance on new disclosure requirements, reporting and accrual of
interest and penalties, accounting in interim periods and transition. FIN No. 48 is effective as of
the beginning of the first fiscal year after December 15, 2006, which is January 1, 2007, for our
company. Only tax positions that meet the “more-likely-than-not” threshold at that date may be
recognized. The cumulative effect of initially applying FIN No. 48 will be recognized as a change
in accounting principle as of the end of the period in which FIN No. 48 is adopted. We have
assessed the impact of FIN No. 48 on our uncertain tax positions as of January 1, 2007 and
determined that it will have no material impact on our consolidated financial statements on
adoption.
SFAS No. 157,
Fair Value Measurements,
was issued by the FASB in September 2006. SFAS No. 157
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 will be
effective for fiscal years beginning after November 15, 2007. SFAS No. 157 applies under other
accounting pronouncements that require or permit fair value measurements where fair value is the
relevant measurement attribute. Accordingly, this statement does not require any new fair value
measurements. We cannot predict what, if any, impact this new standard will have on our
consolidated financial statements when the standard becomes effective in 2008.
SFAS No. 158,
Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,
was
issued by the FASB in September 2006. SFAS No. 158 requires employers to recognize, on a
prospective basis, the funded status of their defined benefit pension and other postretirement
plans on their consolidated balance sheet and to recognize, as a component of other comprehensive
income, net of tax, the gains or losses and prior service costs or credits and transition assets or
obligations that have not been recognized as components of net periodic benefit cost. SFAS No. 158
also requires additional disclosures in the notes to financial statements. SFAS No. 158 will not
change the amount of net periodic benefit expense recognized in an entity’s income statement. It is
effective for fiscal years ending after December 15, 2006. We determined the balance of
unrecognized net actuarial losses, prior service costs and the SFAS No. 106 transition obligation
related to regulated utility activities would be subject to recovery through rates as those
balances are amortized to expense and the related benefits are earned. Therefore, we charged those
unrecognized amounts to regulatory asset accounts under SFAS No. 71,
Accounting for the Effects of
Certain Types of Regulation,
rather than to Accumulated other comprehensive losses in equity as
prescribed by SFAS No. 158. Application of this standard had the following effects on our December
31, 2006 consolidated balance sheet:
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
|
|
|
Decrease in Executive Survivor and Supplemental Retirement Plan intangible asset
|
|
$
|
(767
|
)
|
|
Increase in regulatory assets for the unrecognized portions of net actuarial
losses, prior service costs and transition obligations that are subject to
recovery through electric rates
|
|
|
36,736
|
|
|
Increase in pension benefit and other postretirement liability
|
|
|
(34,714
|
)
|
|
Increase in deferred tax liability
|
|
|
(502
|
)
|
|
Decrease in accumulated other comprehensive loss for the unrecognized portions
of net actuarial losses, prior service costs and transition obligations that
are not subject to recovery through electric rates (increase to equity)
|
|
|
(753
|
)
|
The adoption of this standard did not affect compliance with debt covenants maintained in our
financing agreements.
Securities and Exchange Commission Staff Accounting Bulletin (SAB) No. 108,
Considering the Effects
of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,
was issued in September 2006 to address diversity in practice in quantifying financial statement
misstatements. SAB No. 108 requires a company to quantify misstatements based on their impact on
each of its consolidated financial statements and related disclosures. SAB 108 is effective for our
company as of December 31, 2006, allowing a one-time transitional cumulative effect adjustment to
retained earnings as of July 1, 2006 for errors that were not previously deemed material, but are
material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on
our consolidated financial statements.
Management’s Report Regarding Internal Controls Over Financial Reporting
Management is responsible for the preparation and integrity of the consolidated financial
statements and representations in this annual report. The consolidated financial statements of
Otter Tail Corporation have been prepared in conformity with generally accepted accounting
principles applied on a consistent basis and include some amounts that are based on informed
judgments and best estimates and assumptions of management.
In order to assure the consolidated financial statements are prepared in conformance with generally
accepted accounting principles, management is responsible for establishing and maintaining adequate
internal controls over financial reporting, as such term is defined in Exchange Act Rules
13a-15(f). These internal controls are designed only to provide reasonable assurance, on a
cost-effective basis, that transactions are carried out in accordance with management’s
authorizations and assets are safeguarded against loss from unauthorized use or disposition.
Management has completed its assessment of the effectiveness of the Company’s internal controls
over financial reporting as of December 31, 2006. In making this assessment, management used the
criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)
in
Internal Control — Integrated Framework
to conduct the required assessment of the effectiveness
of the Company’s internal controls over financial reporting.
There have not been any changes in the Company’s internal control over financial reporting (as such
term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal year to which this
report relates that have materially affected, or are reasonably likely to materially affect, the
Company’s internal control over financial reporting.
Based on this assessment, we believe that, as of December 31, 2006 the Company’s internal controls
over financial reporting are effective based on those criteria.
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the
Company’s consolidated financial statements included in this annual report and has also issued an
attestation report on management’s assessment of the Company’s internal controls over financial
reporting.
|
|
|
|
|
|
|
|
|
|
|
/s/ John Erickson
|
|
|
John Erickson
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
|
/s/ Kevin Moug
|
|
|
Kevin Moug
Chief Financial Officer and Treasurer
|
|
|
|
February 19, 2007
|
|
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE SHAREHOLDERS OF OTTER TAIL CORPORATION
We have audited the accompanying consolidated balance sheets and statements of capitalization of
Otter Tail Corporation and its subsidiaries (the “Company”) as of December 31, 2006 and 2005, and
the related consolidated statements of income, common shareholders’ equity, and cash flows for each
of the three years in the period ended December 31, 2006. We also have audited management’s
assessment, included in the accompanying Management’s Report Regarding Internal Controls Over
Financial Reporting, that the Company maintained effective internal control over financial
reporting as of December 31, 2006, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company’s management is responsible for these financial statements, for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an opinion on these
financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of
the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material
respects. Our audit of financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 2006 and 2005, and the
results of its operations and its cash flows for each of the three years in the period ended
December 31, 2006, in conformity with accounting principles generally accepted in the United States
of America. Also in our opinion, management’s assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2006, is fairly stated, in all
material respects, based on the criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our
opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2006, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
As discussed in notes 1 and 4 to the consolidated financial statements, effective December 31,
2006, the Corporation adopted the recognition and disclosure provisions of Statement of Financial
Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans.”
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 19, 2007
Otter Tail Corporation
Consolidated Statements of Income—For the Years Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per-share amounts)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
305,703
|
|
|
$
|
312,624
|
|
|
$
|
266,020
|
|
|
Nonelectric
|
|
|
799,251
|
|
|
|
669,245
|
|
|
|
547,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,104,954
|
|
|
|
981,869
|
|
|
|
813,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production fuel — electric
|
|
|
58,729
|
|
|
|
55,927
|
|
|
|
52,056
|
|
|
Purchased power — electric system use
|
|
|
58,281
|
|
|
|
58,828
|
|
|
|
40,098
|
|
|
Electric operation and maintenance expenses
|
|
|
103,548
|
|
|
|
99,904
|
|
|
|
85,361
|
|
|
Cost of goods sold — nonelectric (excludes depreciation;
included below)
|
|
|
611,737
|
|
|
|
502,407
|
|
|
|
420,394
|
|
|
Other nonelectric expenses
|
|
|
115,290
|
|
|
|
109,707
|
|
|
|
86,037
|
|
|
Depreciation and amortization
|
|
|
49,983
|
|
|
|
46,458
|
|
|
|
43,471
|
|
|
Property taxes — electric
|
|
|
9,589
|
|
|
|
10,043
|
|
|
|
10,411
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
1,007,157
|
|
|
|
883,274
|
|
|
|
737,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
97,797
|
|
|
|
98,595
|
|
|
|
75,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and deductions
|
|
|
(440
|
)
|
|
|
1,773
|
|
|
|
788
|
|
|
Interest charges
|
|
|
19,501
|
|
|
|
18,459
|
|
|
|
18,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
77,856
|
|
|
|
81,909
|
|
|
|
57,868
|
|
|
Income taxes — continuing operations
|
|
|
27,106
|
|
|
|
28,007
|
|
|
|
17,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
50,750
|
|
|
|
53,902
|
|
|
|
40,502
|
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations net of taxes of
$28 in 2006, ($261) in 2005 and $1,121 in 2004
|
|
|
26
|
|
|
|
(352
|
)
|
|
|
1,693
|
|
|
Goodwill impairment loss
|
|
|
—
|
|
|
|
(1,003
|
)
|
|
|
—
|
|
|
Net gain on disposition of discontinued operations
net of taxes of $224 in 2006 and $5,831 in 2005
|
|
|
336
|
|
|
|
10,004
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued operations
|
|
|
362
|
|
|
|
8,649
|
|
|
|
1,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
51,112
|
|
|
|
62,551
|
|
|
|
42,195
|
|
|
Preferred dividend requirements
|
|
|
736
|
|
|
|
735
|
|
|
|
736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings available for common shares
|
|
$
|
50,376
|
|
|
$
|
61,816
|
|
|
$
|
41,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average number of common shares outstanding—basic
|
|
|
29,394
|
|
|
|
29,223
|
|
|
|
26,089
|
|
|
Average number of common shares outstanding—diluted
|
|
|
29,664
|
|
|
|
29,348
|
|
|
|
26,207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations (net of preferred dividend
requirements)
|
|
$
|
1.70
|
|
|
$
|
1.82
|
|
|
$
|
1.53
|
|
|
Discontinued operations
|
|
|
0.01
|
|
|
|
0.30
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.71
|
|
|
$
|
2.12
|
|
|
$
|
1.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations (net of preferred dividend
requirements)
|
|
$
|
1.69
|
|
|
$
|
1.81
|
|
|
$
|
1.52
|
|
|
Discontinued operations
|
|
|
0.01
|
|
|
|
0.30
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.70
|
|
|
$
|
2.11
|
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per common share
|
|
$
|
1.15
|
|
|
$
|
1.12
|
|
|
$
|
1.10
|
|
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Consolidated Balance Sheets, December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,791
|
|
|
$
|
5,430
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
Trade (less allowance for doubtful accounts of
$2,964 for 2006 and $3,493 for 2005)
|
|
|
135,011
|
|
|
|
117,796
|
|
|
Other
|
|
|
10,265
|
|
|
|
11,790
|
|
|
Inventories
|
|
|
103,002
|
|
|
|
88,677
|
|
|
Deferred income taxes
|
|
|
8,069
|
|
|
|
6,871
|
|
|
Accrued utility revenues
|
|
|
23,931
|
|
|
|
22,892
|
|
|
Costs and estimated earnings in excess of billings
|
|
|
38,384
|
|
|
|
21,542
|
|
|
Other
|
|
|
9,611
|
|
|
|
16,476
|
|
|
Assets of discontinued operations
|
|
|
289
|
|
|
|
13,701
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
335,353
|
|
|
|
305,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments and other assets
|
|
|
29,946
|
|
|
|
33,824
|
|
|
Goodwill—net
|
|
|
98,110
|
|
|
|
98,110
|
|
|
Other intangibles—net
|
|
|
20,080
|
|
|
|
21,160
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred debits
|
|
|
|
|
|
|
|
|
|
Unamortized debt expense and reacquisition premiums
|
|
|
6,133
|
|
|
|
6,520
|
|
|
Regulatory assets and other deferred debits
|
|
|
50,419
|
|
|
|
19,616
|
|
|
|
|
|
|
|
|
|
|
Total deferred debits
|
|
|
56,552
|
|
|
|
26,136
|
|
|
|
|
|
|
|
|
|
|
Plant
|
|
|
|
|
|
|
|
|
|
Electric plant in service
|
|
|
930,689
|
|
|
|
910,766
|
|
|
Nonelectric operations
|
|
|
239,269
|
|
|
|
228,548
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,169,958
|
|
|
|
1,139,314
|
|
|
Less accumulated depreciation and amortization
|
|
|
479,557
|
|
|
|
459,438
|
|
|
|
|
|
|
|
|
|
|
Plant—net of accumulated depreciation and
amortization
|
|
|
690,401
|
|
|
|
679,876
|
|
|
Construction work in progress
|
|
|
28,208
|
|
|
|
17,215
|
|
|
|
|
|
|
|
|
|
|
Net plant
|
|
|
718,609
|
|
|
|
697,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,258,650
|
|
|
$
|
1,181,496
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Consolidated Balance Sheets, December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except share data)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
Short-term debt
|
|
$
|
38,900
|
|
|
$
|
16,000
|
|
|
Current maturities of long-term debt
|
|
|
3,125
|
|
|
|
3,340
|
|
|
Accounts payable
|
|
|
120,195
|
|
|
|
97,239
|
|
|
Accrued salaries and wages
|
|
|
28,653
|
|
|
|
24,326
|
|
|
Accrued federal and state income taxes
|
|
|
2,383
|
|
|
|
8,449
|
|
|
Other accrued taxes
|
|
|
11,509
|
|
|
|
12,518
|
|
|
Other accrued liabilities
|
|
|
10,495
|
|
|
|
14,124
|
|
|
Liabilities of discontinued operations
|
|
|
197
|
|
|
|
10,983
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
215,457
|
|
|
|
186,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pensions benefit liability
|
|
|
44,035
|
|
|
|
23,216
|
|
|
Other postretirement benefits liability
|
|
|
32,254
|
|
|
|
26,982
|
|
|
Other noncurrent liabilities
|
|
|
18,866
|
|
|
|
18,683
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments (note 9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred credits
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
112,740
|
|
|
|
113,737
|
|
|
Deferred investment tax credit
|
|
|
8,181
|
|
|
|
9,327
|
|
|
Regulatory liabilities
|
|
|
63,875
|
|
|
|
61,624
|
|
|
Other
|
|
|
281
|
|
|
|
1,500
|
|
|
|
|
|
|
|
|
|
|
Total deferred credits
|
|
|
185,077
|
|
|
|
186,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization (page 40)
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current maturities
|
|
|
255,436
|
|
|
|
258,260
|
|
|
|
|
|
|
|
|
|
|
|
|
Class B stock options of subsidiary
|
|
|
1,255
|
|
|
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative preferred shares
|
|
|
15,500
|
|
|
|
15,500
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares, par value $5 per share—authorized, 50,000,000 shares;
outstanding, 2006—29,521,770 shares; 2005—29,401,223 shares
|
|
|
147,609
|
|
|
|
147,006
|
|
|
Premium on common shares
|
|
|
99,223
|
|
|
|
96,768
|
|
|
Unearned compensation
|
|
|
—
|
|
|
|
(1,720
|
)
|
|
Retained earnings
|
|
|
245,005
|
|
|
|
228,515
|
|
|
Accumulated other comprehensive loss
|
|
|
(1,067
|
)
|
|
|
(6,139
|
)
|
|
|
|
|
|
|
|
|
|
Total common equity
|
|
|
490,770
|
|
|
|
464,430
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
762,961
|
|
|
|
739,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,258,650
|
|
|
$
|
1,181,496
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Consolidated Statements of Common Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
Common
|
|
Par value,
|
|
Premium on
|
|
|
|
|
|
|
|
|
|
other
|
|
|
|
|
|
shares
|
|
common
|
|
common
|
|
Unearned
|
|
Retained
|
|
comprehensive
|
|
Total
|
|
(in thousands, except common shares
outstanding)
|
|
outstanding
|
|
shares
|
|
shares
|
|
compensation
|
|
earnings
|
|
income/(loss)
|
|
equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
|
25,723,814
|
|
|
$
|
128,619
|
|
|
$
|
26,515
|
|
|
$
|
(3,313
|
)
|
|
$
|
186,495
|
|
|
$
|
(4,429
|
)
|
|
$
|
333,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issuances, net of expenses
|
|
|
3,266,266
|
|
|
|
16,332
|
|
|
|
63,373
|
|
|
|
(566
|
)
|
|
|
|
|
|
|
|
|
|
|
79,139
|
|
|
Common stock retirements
|
|
|
(13,161
|
)
|
|
|
(66
|
)
|
|
|
(283
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(349
|
)
|
|
Amortization of unearned compensation—stock awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,302
|
|
|
|
|
|
|
|
|
|
|
|
1,302
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,195
|
|
|
|
|
|
|
|
42,195
|
|
|
Unrealized loss on marketable equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
|
|
(14
|
)
|
|
Foreign currency exchange translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,014
|
|
|
|
1,014
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,039
|
|
|
|
3,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,234
|
|
|
Tax benefit for exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92
|
|
|
Valuation of stock options of subsidiary acquired in 2004
|
|
|
|
|
|
|
|
|
|
|
(1,832
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,832
|
)
|
|
Cumulative preferred dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(735
|
)
|
|
|
|
|
|
|
(735
|
)
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,528
|
)
|
|
|
|
|
|
|
(28,528
|
)
|
|
|
|
Balance, December 31, 2004
|
|
|
28,976,919
|
|
|
$
|
144,885
|
|
|
$
|
87,865
|
|
|
$
|
(2,577
|
)
|
|
$
|
199,427
|
|
|
$
|
(390
|
)
|
|
$
|
429,210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issuances, net of expenses
|
|
|
456,211
|
|
|
|
2,281
|
|
|
|
8,483
|
|
|
|
(529
|
)
|
|
|
|
|
|
|
|
|
|
|
10,235
|
|
|
Common stock retirements
|
|
|
(31,907
|
)
|
|
|
(160
|
)
|
|
|
(756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(916
|
)
|
|
Amortization of unearned compensation—stock awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,386
|
|
|
|
|
|
|
|
|
|
|
|
1,386
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,551
|
|
|
|
|
|
|
|
62,551
|
|
|
Unrealized loss on marketable equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23
|
)
|
|
|
(23
|
)
|
|
Foreign currency exchange translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
437
|
|
|
|
437
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,163
|
)
|
|
|
(6,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,802
|
|
|
Tax benefit for exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
596
|
|
|
Stock incentive plan performance award accrual
|
|
|
|
|
|
|
|
|
|
|
943
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
943
|
|
|
Premium on purchase of stock for employee purchase plan
|
|
|
|
|
|
|
|
|
|
|
(363
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(363
|
)
|
|
Cumulative preferred dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(735
|
)
|
|
|
|
|
|
|
(735
|
)
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,728
|
)
|
|
|
|
|
|
|
(32,728
|
)
|
|
|
|
Balance, December 31, 2005
|
|
|
29,401,223
|
|
|
$
|
147,006
|
|
|
$
|
96,768
|
|
|
$
|
(1,720
|
)
|
|
$
|
228,515
|
|
|
$
|
(6,139
|
)
|
|
$
|
464,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issuances, net of expenses
|
|
|
136,917
|
|
|
|
685
|
|
|
|
1,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,522
|
|
|
Common stock retirements
|
|
|
(16,370
|
)
|
|
|
(82
|
)
|
|
|
(378
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(460
|
)
|
|
SFAS No. 123(R) reclassifications (note 7)
|
|
|
|
|
|
|
|
|
|
|
(2,490
|
)
|
|
|
1,720
|
|
|
|
|
|
|
|
|
|
|
|
(770
|
)
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,112
|
|
|
|
|
|
|
|
51,112
|
|
|
Unrealized loss on marketable equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
56
|
|
|
Foreign currency exchange translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
6
|
|
|
SFAS No. 87 minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,257
|
|
|
|
4,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,431
|
|
|
SFAS No. 158 items (net-of-tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of 12/31/06 minimum pension liability
balance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,296
|
|
|
|
3,296
|
|
|
Unrecognized postretirement benefit costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,585
|
)
|
|
|
(24,585
|
)
|
|
Unrecognized costs classified as regulatory assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,042
|
|
|
|
22,042
|
|
|
Tax benefit for exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
288
|
|
|
Stock compensation award accruals
|
|
|
|
|
|
|
|
|
|
|
2,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,404
|
|
|
Vesting of restricted stock granted to employees
|
|
|
|
|
|
|
|
|
|
|
1,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,096
|
|
|
Premium on purchase of stock for employee purchase plan
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(302
|
)
|
|
Cumulative preferred dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(736
|
)
|
|
|
|
|
|
|
(736
|
)
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,886
|
)
|
|
|
|
|
|
|
(33,886
|
)
|
|
|
|
Balance, December 31, 2006
|
|
|
29,521,770
|
|
|
$
|
147,609
|
|
|
$
|
99,223
|
|
|
$
|
—
|
|
|
$
|
245,005
|
|
|
$
|
(1,067
|
)(a)
|
|
$
|
490,770
|
|
|
|
|
(a)
|
|
Accumulated other comprehensive loss on December 31, 2006 is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Before tax
|
|
Tax effect
|
|
Net-of-tax
|
|
|
|
Unamortized actuarial losses and transition obligation related to pension and postretirement benefits
|
|
$
|
(4,238
|
)
|
|
$
|
1,695
|
|
|
$
|
(2,543
|
)
|
|
Foreign currency exchange translation
|
|
|
2,430
|
|
|
|
(972
|
)
|
|
|
1,458
|
|
|
Unrealized gain on marketable equity securities
|
|
|
30
|
|
|
|
(12
|
)
|
|
|
18
|
|
|
|
|
Net accumulated other comprehensive loss
|
|
$
|
(1,778
|
)
|
|
$
|
711
|
|
|
$
|
(1,067
|
)
|
|
|
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Consolidated Statements of Cash Flows—For the Years Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
51,112
|
|
|
$
|
62,551
|
|
|
$
|
42,195
|
|
|
Adjustments to reconcile net income to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on sale of discontinued operations
|
|
|
(336
|
)
|
|
|
(10,004
|
)
|
|
|
—
|
|
|
(Income) loss from discontinued operations
|
|
|
(26
|
)
|
|
|
1,355
|
|
|
|
(1,693
|
)
|
|
Depreciation and amortization
|
|
|
49,983
|
|
|
|
46,458
|
|
|
|
43,471
|
|
|
Deferred investment tax credit
|
|
|
(1,146
|
)
|
|
|
(1,150
|
)
|
|
|
(1,152
|
)
|
|
Deferred income taxes
|
|
|
(1,258
|
)
|
|
|
(9,223
|
)
|
|
|
3,950
|
|
|
Change in deferred debits and other assets
|
|
|
(38,499
|
)
|
|
|
8,865
|
|
|
|
(1,641
|
)
|
|
Discretionary contribution to pension plan
|
|
|
(4,000
|
)
|
|
|
(4,000
|
)
|
|
|
(4,000
|
)
|
|
Change in noncurrent liabilities and deferred credits
|
|
|
45,340
|
|
|
|
1,321
|
|
|
|
2,110
|
|
|
Allowance for equity (other) funds used during construction
|
|
|
2,529
|
|
|
|
(723
|
)
|
|
|
(716
|
)
|
|
Change in derivatives net of regulatory deferral
|
|
|
3,083
|
|
|
|
(2,615
|
)
|
|
|
1,755
|
|
|
Stock compensation expense
|
|
|
2,404
|
|
|
|
2,388
|
|
|
|
87
|
|
|
Other—net
|
|
|
418
|
|
|
|
1,118
|
|
|
|
1,343
|
|
|
Cash (used for) provided by current assets and current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in receivables
|
|
|
(15,713
|
)
|
|
|
(9,715
|
)
|
|
|
(7,357
|
)
|
|
Change in inventories
|
|
|
(14,345
|
)
|
|
|
(12,500
|
)
|
|
|
(6,894
|
)
|
|
Change in other current assets
|
|
|
(17,409
|
)
|
|
|
(13,908
|
)
|
|
|
(15,360
|
)
|
|
Change in payables and other current liabilities
|
|
|
23,022
|
|
|
|
32,682
|
|
|
|
(647
|
)
|
|
Change in interest and income taxes payable
|
|
|
(5,952
|
)
|
|
|
(2,552
|
)
|
|
|
(1,041
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by continuing operations
|
|
|
79,207
|
|
|
|
90,348
|
|
|
|
54,410
|
|
|
Net cash provided by discontinued operations
|
|
|
1,039
|
|
|
|
5,452
|
|
|
|
1,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
80,246
|
|
|
|
95,800
|
|
|
|
56,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(69,448
|
)
|
|
|
(59,969
|
)
|
|
|
(49,484
|
)
|
|
Proceeds from disposal of noncurrent assets
|
|
|
5,233
|
|
|
|
4,193
|
|
|
|
5,844
|
|
|
Acquisitions—net of cash acquired
|
|
|
—
|
|
|
|
(11,223
|
)
|
|
|
(69,069
|
)
|
|
(Increases) decreases in other investments
|
|
|
(3,326
|
)
|
|
|
4,171
|
|
|
|
(5,099
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities — continuing operations
|
|
|
(67,541
|
)
|
|
|
(62,828
|
)
|
|
|
(117,808
|
)
|
|
Net proceeds from sale of discontinued operations
|
|
|
1,960
|
|
|
|
34,185
|
|
|
|
—
|
|
|
Net cash provided by (used in) investing activities — discontinued operations
|
|
|
—
|
|
|
|
602
|
|
|
|
(1,310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(65,581
|
)
|
|
|
(28,041
|
)
|
|
|
(119,118
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in checks written in excess of cash
|
|
|
(11
|
)
|
|
|
(3,329
|
)
|
|
|
3,458
|
|
|
Net short-term borrowings (repayments)
|
|
|
22,900
|
|
|
|
(23,950
|
)
|
|
|
9,950
|
|
|
Proceeds from issuance of common stock, net of issuance expenses
|
|
|
2,444
|
|
|
|
9,690
|
|
|
|
78,780
|
|
|
Payments for retirement of common stock and Class B stock of subsidiary
|
|
|
(463
|
)
|
|
|
(939
|
)
|
|
|
(349
|
)
|
|
Proceeds from issuance of long-term debt
|
|
|
149
|
|
|
|
368
|
|
|
|
4,186
|
|
|
Debt issuance expenses
|
|
|
(458
|
)
|
|
|
(140
|
)
|
|
|
(121
|
)
|
|
Payments for retirement of long-term debt
|
|
|
(3,287
|
)
|
|
|
(7,232
|
)
|
|
|
(9,061
|
)
|
|
Dividends paid
|
|
|
(34,621
|
)
|
|
|
(33,463
|
)
|
|
|
(29,263
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities — continuing operations
|
|
|
(13,347
|
)
|
|
|
(58,995
|
)
|
|
|
57,580
|
|
|
Net cash used in financing activities — discontinued operations
|
|
|
—
|
|
|
|
(2,996
|
)
|
|
|
(1,679
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(13,347
|
)
|
|
|
(61,991
|
)
|
|
|
55,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate fluctuations on cash
|
|
|
43
|
|
|
|
(338
|
)
|
|
|
(794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
1,361
|
|
|
|
5,430
|
|
|
|
(7,710
|
)
|
|
Cash and cash equivalents at beginning of year — continuing operations
|
|
|
5,430
|
|
|
|
—
|
|
|
|
7,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year — continuting operations
|
|
$
|
6,791
|
|
|
$
|
5,430
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year from continuing operations for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest (net of amount capitalized)
|
|
$
|
18,456
|
|
|
$
|
17,637
|
|
|
$
|
16,410
|
|
|
Income taxes
|
|
$
|
35,061
|
|
|
$
|
39,548
|
|
|
$
|
16,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year from discontinued operations for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
91
|
|
|
$
|
119
|
|
|
$
|
144
|
|
|
Income taxes
|
|
$
|
423
|
|
|
$
|
323
|
|
|
$
|
833
|
|
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Consolidated Statements of Capitalization, December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except share data)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
|
|
|
|
|
|
Senior notes 6.63%, due December 1, 2011
|
|
$
|
90,000
|
|
|
$
|
90,000
|
|
|
Senior debentures 6.375%, due December 1, 2007
|
|
|
50,000
|
|
|
|
50,000
|
|
|
Insured senior notes 5.625%, due October 1, 2017
|
|
|
40,000
|
|
|
|
40,000
|
|
|
Senior notes 6.80%, due October 1, 2032
|
|
|
25,000
|
|
|
|
25,000
|
|
|
Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022
|
|
|
20,735
|
|
|
|
20,735
|
|
|
Pollution control refunding revenue bonds, variable, 4.31% at December 31, 2006, due December 1, 2012
|
|
|
10,400
|
|
|
|
10,400
|
|
|
Lombard US Equipment Finance note 6.76%, due October 2, 2010
|
|
|
9,314
|
|
|
|
11,643
|
|
|
Grant County, South Dakota pollution control refunding revenue bonds 4.65%, due September 1, 2017
|
|
|
5,185
|
|
|
|
5,185
|
|
|
Obligations of Varistar Corporation — various up to 9.33% at December 31, 2006
|
|
|
8,424
|
|
|
|
9,235
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
259,058
|
|
|
|
262,198
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Current maturities
|
|
|
3,125
|
|
|
|
3,340
|
|
|
Unamortized debt discount
|
|
|
497
|
|
|
|
598
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt—continuing operations
|
|
|
255,436
|
|
|
|
258,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class B stock options of subsidiary
|
|
|
1,255
|
|
|
|
1,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative preferred shares
—without par value (stated and
liquidating value $100 a share)—authorized 1,500,000 shares;
Series outstanding:
|
|
|
|
|
|
|
|
|
|
$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
|
|
|
|
|
|
|
|
|
|
|
Total preferred
|
|
|
15,500
|
|
|
|
15,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative preference shares
—without par value, authorized 1,000,000 shares; outstanding: none
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total common shareholders’ equity
|
|
|
490,770
|
|
|
|
464,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
762,961
|
|
|
$
|
739,448
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
Otter
Tail Corporation
Notes to Consolidated Financial Statements
For the years ended December 31, 2006, 2005 and 2004
1. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements of Otter Tail Corporation and its wholly-owned
subsidiaries (the Company) include the accounts of the following segments: electric, plastics,
manufacturing, health services, food ingredient processing and other business operations. See
note 2 to the consolidated financial statements for further descriptions of the Company’s
business segments. All significant intercompany balances and transactions have been eliminated
in consolidation except profits on sales to the regulated electric utility company from
nonregulated affiliates, which is in accordance with the requirements of Statement of Financial
Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation
.
These amounts are not material.
Regulation and Statement of Financial Accounting Standards No. 71
As a regulated entity, the Company and the electric utility account for the financial effects of
regulation in accordance with SFAS No. 71. This statement allows for the recording of a
regulatory asset or liability for costs that will be collected or refunded through the
ratemaking process in the future. In accordance with regulatory treatment, the Company defers
utility debt redemption premiums and amortizes such costs over the original life of the
reacquired bonds. See note 4 for further discussion.
The Company’s regulated electric utility business is subject to various state and federal agency
regulations. The accounting policies followed by this business are subject to the Uniform System
of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ
in some respects from those used by the Company’s nonelectric businesses.
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
(AFUDC). AFUDC, a noncash item, is included in utility construction work in progress. The amount
of AFUDC capitalized was $952,000 for 2006, $913,000 for 2005 and $949,000 for 2004. In 2006,
the Company recorded a noncash charge to other income and deductions of $3.3 million resulting
from uncertainty with respect to the capitalized cost of construction funds included in the
electric utility’s rate base. The cost of depreciable units of property retired less salvage is
charged to accumulated depreciation. Removal costs, when incurred, are charged against the
accumulated reserve for estimated removal costs, a regulatory liability. 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 2.82% in 2006, 2.74% in 2005 and 2.77% in
2004. Gains or losses on group asset dispositions are taken to the accumulated provision for
depreciation reserve and impact current and future depreciation rates.
Property and equipment of nonelectric operations are carried at historical cost or at the
then-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 assets
estimated useful lives (3 to 40 years). Maintenance and repairs are expensed as incurred. Gains
or losses on asset dispositions are included in the determination of operating income.
Jointly Owned Plants
The consolidated balance sheets include the Company’s ownership interests in the assets and
liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are
included in the December 31, 2006 and 2005 consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Big Stone Plant
|
|
|
Coyote Station
|
|
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
Electric plant in service
|
|
$
|
124,965
|
|
|
$
|
147,319
|
|
|
Accumulated depreciation
|
|
|
(75,872
|
)
|
|
|
(80,336
|
)
|
|
|
|
|
|
|
|
|
|
Net plant
|
|
$
|
49,093
|
|
|
$
|
66,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
|
|
|
|
|
|
|
Electric plant in service
|
|
$
|
124,852
|
|
|
$
|
146,405
|
|
|
Accumulated depreciation
|
|
|
(71,824
|
)
|
|
|
(77,909
|
)
|
|
|
|
|
|
|
|
|
|
Net plant
|
|
$
|
53,028
|
|
|
$
|
68,496
|
|
|
|
|
|
|
|
|
|
The Company’s share of direct revenue and expenses of the jointly owned plants is included in
operating revenue and expenses in the consolidated statements of income.
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. If the sum of the expected
future net cash flows is 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.
Revenue Recognition
Due to the diverse business operations of the Company, revenue recognition depends on the
product produced and sold or service performed. The Company recognizes revenue when the earnings
process is complete, evidenced by an agreement with the customer, there has been delivery and
acceptance, and the price is fixed or determinable. In cases where significant obligations
remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for
sales returns and warranty costs are recorded at the time of the sale based on historical
information and current trends. In the case of derivative instruments, such as the electric
utility’s forward energy contracts and the energy services company’s swap transactions,
marked-to-market and realized gains and losses are recognized on a net basis in revenue in
accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities,
as
amended and interpreted. Gains and losses on forward energy contracts subject to regulatory
treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.
For the Company’s operating companies recognizing revenue on certain products when shipped,
those operating companies have no further obligation to provide services related to such
product. The shipping terms used in these instances are FOB shipping point.
Electric customers’ meters are read and bills are rendered monthly. Revenue is accrued for
electricity consumed but not yet billed. Rate schedules applicable to substantially all
customers include a fuel clause adjustment—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. Revenue is accrued for fuel and purchased power costs incurred in
excess of amounts
recovered in base rates but not yet billed through the fuel clause adjustment.
Revenues on wholesale electricity sales from Company-owned generating units are recognized when
energy is delivered.
The Company’s unrealized gains and losses on forward energy contracts that do not meet the
definition of capacity contracts are marked to market and reflected on a net basis in electric
revenue on the Company’s consolidated statement of income. Under SFAS No. 133 as amended and
interpreted, the Company’s forward energy contracts that do not meet the definition of a
capacity contract and are subject to unplanned netting do not qualify for the normal purchase
and sales exception from mark-to-market accounting. The Company is required to mark to market
these forward energy contracts and recognize changes in the fair value of these contracts as
components of income over the life of the contracts. See note 5 for further discussion.
Plastics operating revenues are recorded when the product is shipped.
Manufacturing operating revenues are recorded when products are shipped and on a
percentage-of-completion basis for construction type contracts.
Health services operating revenues on major equipment and installation contracts are recorded
when the equipment is delivered or when installation is completed and accepted. 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 imaging operations are recorded on a
fee-per-scan basis when the scan is performed.
Food ingredient processing revenues are recorded when the product is shipped.
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.
Some of the operating businesses enter into fixed-price construction contracts. Revenues under
these contracts are recognized on a percentage-of-completion basis. The method used to determine
the progress of completion is based on the ratio of labor costs incurred to total estimated
labor costs at the Company’s wind tower manufacturer, square footage completed to total bid
square footage for certain floating dock projects and costs incurred to total estimated costs on
all other construction projects. If a loss is indicated at a point in time during a contract, a
projected loss for the entire contract is estimated and recognized. The following table
summarizes costs incurred and billings and estimated earnings recognized on uncompleted
contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
Costs incurred on uncompleted contracts
|
|
$
|
257,370
|
|
|
$
|
194,076
|
|
|
Less billings to date
|
|
|
(284,273
|
)
|
|
|
(203,862
|
)
|
|
Plus estimated earnings recognized
|
|
|
35,955
|
|
|
|
22,834
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,052
|
|
|
$
|
13,048
|
|
|
|
|
|
|
|
|
|
The following costs and estimated earnings in excess of billings are included in the Company’s
consolidated balance sheet. Billings in excess of costs and estimated earnings on uncompleted
contracts are included in accounts payable.
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
Costs and estimated earnings in excess of billings on uncompleted contracts
|
|
$
|
38,384
|
|
|
$
|
21,542
|
|
|
Billings in excess of costs and estimated earnings on uncompleted contracts
|
|
|
(29,332
|
)
|
|
|
(8,494
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,052
|
|
|
$
|
13,048
|
|
|
|
|
|
|
|
|
|
Foreign Currency Translation
The functional currency for the operations of the Canadian subsidiary of Idaho Pacific Holdings,
Inc. (IPH) is the Canadian dollar. The translation of Canadian currency into U.S. dollars is
performed for balance sheet accounts using exchange rates in effect at the balance sheet dates,
except for the common equity accounts which are at historical rates, and for revenue and expense
accounts using a weighted average exchange during the year. Gains or losses resulting from the
translation are included in Accumulated other comprehensive loss in the equity section of the
Company’s consolidated balance sheet. The functional currency for the Canadian subsidiary of DMI
Industries, Inc., formed in November 2005, is the U.S. dollar. There are no foreign currency
translation gains or losses related to this entity. However, this subsidiary may realize foreign
currency transaction gains or losses on settlement of liabilities related to goods or services
purchased in Canadian dollars. Foreign currency transaction gains or losses related to balance
sheet adjustments of Canadian dollar liabilities to U.S. dollar equivalents or realized gains
and losses on settlement of those liabilities will be included in other nonelectric expenses on
the Company’s consolidated statements of income.
Pre-Production Costs
The Company incurs costs related to the design and development of molds, dies and tools as part
of the manufacturing process. The Company accounts for these costs under EITF Issue 99-5,
Accounting for Pre-production Costs Related to Long-Term Supply Arrangements
. The Company
capitalizes the costs related to the design and development of molds, dies and tools used to
produce products under a long-term supply arrangement, some of which are owned by the Company.
The balance of pre-production costs deferred on the balance sheet was $2,251,000 as of December
31, 2006 and $2,074,000 as of December 31, 2005. These costs are amortized over a three-year
period and evaluated at least annually, or more often when events indicate an impairment could
exist.
Shipping and Handling Costs
The Company includes revenues received for shipping and handling in operating revenues. Expenses
paid for shipping and handling are recorded as part of cost of goods sold.
Use of Estimates
The Company uses estimates based on the best information available in recording transactions and
balances resulting from business operations. Estimates are used for such items as depreciable
lives, asset impairment evaluations, tax provisions, collectability of trade accounts
receivable, self-insurance programs, unbilled electric revenues, valuations of forward energy
contracts, unscheduled power exchanges and residual load adjustments related to purchase and
sales transactions processed through the Midwest Independent Transmission System Operator (MISO)
that are pending settlement, service contract maintenance costs, percentage-of-completion and
actuarially determined benefits costs and liabilities. As better information becomes available
(or actual amounts are known), the recorded estimates are revised. Consequently, operating
results can be affected by revisions to prior accounting estimates.
Adjustments and Reclassifications
The Company’s consolidated statements of income and consolidated statements of cash flows for
the years ended December 31, 2005 and 2004, and its December 31, 2005 consolidated balance sheet
reflect the reclassifications of the operating results, assets and liabilities of the natural
gas marketing operations of OTESCO, the Company’s energy services company, to discontinued
operations as a result of the sale of these operations in June 2006. The reclassifications had
no impact on the Company’s total consolidated net income or cash flows for the years ended
December 31, 2005 and 2004 or on its total consolidated assets or liabilities as of December 31,
2005.
Cash Equivalents
The Company considers all highly liquid debt instruments purchased with maturity of 90 days or
less to be cash equivalents.
Investments
The following table provides a breakdown of the Company’s investments at December 31, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
December 31,
|
|
(in thousands)
|
|
2006
|
|
2005
|
|
|
|
Cost method:
|
|
|
|
|
|
|
|
|
|
Economic development loan pools
|
|
$
|
569
|
|
|
$
|
742
|
|
|
Other
|
|
|
1,518
|
|
|
|
1,913
|
|
|
Equity method:
|
|
|
|
|
|
|
|
|
|
Affordable housing partnerships
|
|
|
2,228
|
|
|
|
2,980
|
|
|
Marketable securities classified as available-for-sale
|
|
|
4,640
|
|
|
|
3,067
|
|
|
|
|
|
|
|
|
|
|
Total investments
|
|
$
|
8,955
|
|
|
$
|
8,702
|
|
|
|
|
|
|
|
|
|
The Company has investments in eleven limited partnerships that invest in tax-credit-qualifying
affordable-housing projects that provided tax credits of $839,000 in 2006, $1,324,000 in 2005
and $1,418,000 in 2004. The Company owns a majority interest in eight of the eleven limited
partnerships with a total investment of $2,155,000. FASB Interpretation (FIN) No. 46,
Consolidation of Variable Interest Entities,
requires full consolidation of the majority-owned
partnerships. However, the Company includes these entities on its consolidated financial
statements on an equity method basis due to immateriality. Consolidating these entities would
have represented less than 0.6% of total assets, 0.1% of total revenues and (0.2%) of operating
income for the Company as of, and for the year ended, December 31, 2006 and would have no impact
on the Company’s 2006 consolidated net income as the amount is the same under both the equity
and full consolidation methods.
The Company’s marketable securities classified as available-for-sale are held for insurance
reserve purposes and are reflected at their market values on December 31, 2006, with $18,000 in
unrealized gains included in Accumulated other comprehensive income in the equity section of the
Company’s December 31, 2006 consolidated balance sheet. See further discussion under note 13.
Inventories
The electric segment inventories are reported at average cost. All other segments’ inventories
are stated at the lower of cost (first-in, first-out) or market. Inventories consist of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
Finished goods
|
|
$
|
46,477
|
|
|
$
|
38,928
|
|
|
Work in process
|
|
|
5,663
|
|
|
|
7,146
|
|
|
Raw material, fuel and supplies
|
|
|
50,862
|
|
|
|
42,603
|
|
|
|
|
|
|
|
|
|
|
Total inventories
|
|
$
|
103,002
|
|
|
$
|
88,677
|
|
|
|
|
|
|
|
|
|
Goodwill and Intangible Assets
The Company accounts for goodwill and other intangible assets in accordance with the
requirements of SFAS No. 142,
Goodwill and Other Intangible Assets,
requiring goodwill and
indefinite-lived intangible assets to be measured for impairment at least annually and more
often when events indicate an impairment could exist. Intangible assets with finite lives are
amortized over their estimated useful lives and reviewed for impairment in accordance with SFAS
No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets
.
Goodwill did not change in 2006 as the Company did not acquire any businesses or make any
adjustments to goodwill during the period. The following table shows goodwill balances by
segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
Plastics
|
|
$
|
19,302
|
|
|
$
|
19,302
|
|
|
Manufacturing
|
|
|
15,698
|
|
|
|
15,698
|
|
|
Health services
|
|
|
24,328
|
|
|
|
24,328
|
|
|
Food ingredient processing
|
|
|
24,240
|
|
|
|
24,240
|
|
|
Other business operations
|
|
|
14,542
|
|
|
|
14,542
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
98,110
|
|
|
$
|
98,110
|
|
|
|
|
|
|
|
|
|
The following table summarizes components of the Company’s intangible assets as of December
31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross carrying
|
|
|
Accumulated
|
|
|
Net carrying
|
|
|
2006
(in thousands)
|
|
amount
|
|
|
amortization
|
|
|
amount
|
|
|
|
|
Amortized intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Covenants not to compete
|
|
$
|
2,198
|
|
|
$
|
1,813
|
|
|
$
|
385
|
|
|
Customer relationships
|
|
|
10,574
|
|
|
|
1,016
|
|
|
|
9,558
|
|
|
Other intangible assets including contracts
|
|
|
2,083
|
|
|
|
1,291
|
|
|
|
792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
14,855
|
|
|
$
|
4,120
|
|
|
$
|
10,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonamortized intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brand/trade name
|
|
$
|
9,345
|
|
|
$
|
—
|
|
|
$
|
9,345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Covenants not to compete
|
|
$
|
2,338
|
|
|
$
|
1,620
|
|
|
$
|
718
|
|
|
Customer relationships
|
|
|
10,575
|
|
|
|
583
|
|
|
|
9,992
|
|
|
Other intangible assets including contracts
|
|
|
2,785
|
|
|
|
1,680
|
|
|
|
1,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,698
|
|
|
$
|
3,883
|
|
|
$
|
11,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonamortized intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brand/trade name
|
|
$
|
9,345
|
|
|
$
|
—
|
|
|
$
|
9,345
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets with finite lives are being amortized over average lives that vary from one to
25 years. The amortization expense for these intangible assets was $1,079,000 for 2006,
$1,077,000 for 2005 and $701,000 for 2004. The estimated annual amortization expense for these
intangible assets for the next five years is: $872,000 for 2007, $727,000 for 2008, $636,000 for
2009, $507,000 for 2010 and $457,000 for 2011.
New Accounting Standards
SFAS No. 123(R) (revised 2004),
Share-Based Payment,
issued in December 2004 is a revision of
SFAS No. 123,
Accounting for Stock-based Compensation,
and supersedes Accounting Principles
Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees.
Beginning in January 2006,
the Company adopted SFAS No. 123(R) on a modified prospective basis. The Company is required to
record stock-based compensation as an expense on its income statement over the period earned
based on the fair value of the stock or options awarded on their grant date. The application of
SFAS No. 123(R) reporting requirements resulted in recording incremental after-tax compensation
expense in 2006 as follows:
|
|
•
|
|
$163,000, net-of-tax, in 2006 for non-vested stock options that were outstanding on
December 31, 2005.
|
|
|
|
|
•
|
|
$235,000 in 2006 for the 15% discount offered under our Employee Stock Purchase
Plan.
|
See note 7 for additional discussion. For years prior to 2006, the Company reported its
stock-based compensation under the requirements of APB No. 25 and furnished related pro forma
footnote information required under SFAS No. 123.
In November 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position
(FSP) No. FAS 123(R)-3,
Transition Election Related to Accounting for Tax Effects of Share-Based
Payment Awards.
We elected to adopt the alternative transition method provided in FSP No. FAS
123(R)-3 for calculating the tax effects of stock-based compensation. The alternative transition
method includes simplified methods to determine the beginning balance of the additional paid-in
capital (APIC) pool related to the tax effects of stock-based compensation, and to determine the
subsequent impact on the APIC pool and the statement of cash flows of the tax effects of
stock-based awards that were fully vested and outstanding upon the adoption of SFAS No. 123(R).
FIN No. 48,
Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No.
109,
was issued by the FASB in June 2006. FIN No. 48 clarifies the accounting for uncertain tax
positions in accordance with SFAS 109,
Accounting for Income Taxes.
The Company will be required
to recognize, in its financial statements, the tax effects of a tax position that is
“more-likely-than-not” to be sustained on audit based solely on the technical merits of the
position as of the reporting date. The term “more-likely-than-not” means a
likelihood of more than 50%. FIN No. 48 also provides guidance on new disclosure requirements,
reporting and accrual of interest and penalties, accounting in interim periods and transition.
FIN No. 48 is effective as of the beginning of the first fiscal year after December 15, 2006,
which is January 1, 2007 for the Company. Only tax positions that meet the
“more-likely-than-not” threshold at that date may be recognized. The cumulative effect of
initially applying FIN No. 48 will be recognized as a change in accounting principle as of the
end of the period in which FIN No. 48 is adopted. The Company has assessed the impact of FIN No.
48 on its uncertain tax positions as of January 1, 2007 and determined that FIN No. 48 will have
no material impact on the Company’s consolidated financial statements on adoption.
SFAS No. 157,
Fair Value Measurements,
was issued by the FASB in September 2006. SFAS No. 157
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 will
be effective for fiscal years beginning after November 15, 2007. SFAS No. 157 applies under
other accounting pronouncements that require or permit fair value measurements where fair value
is the relevant measurement attribute. Accordingly, this statement does not require any new fair
value measurements. The Company cannot predict what, if any, impact this new standard will have
on its consolidated financial statements when the standard becomes effective in 2008.
SFAS No. 158,
Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,
was issued by the FASB in September 2006. SFAS No. 158 requires employers to recognize, on a
prospective basis, the funded status of their defined benefit pension and other postretirement
plans on their consolidated balance sheet and to recognize, as a component of other
comprehensive income, net of tax, the gains or losses and prior service costs or credits and
transition assets or obligations that have not been recognized as components of net periodic
benefit cost. SFAS No. 158 also requires additional disclosures in the notes to financial
statements. SFAS No. 158 will not change the amount of net periodic benefit expense recognized
in an entity’s income statement. It is effective for fiscal years ending after December 15,
2006. The Company determined the balance of unrecognized net actuarial losses, prior service
costs and the SFAS No. 106 transition obligation related to regulated utility activities would
be subject to recovery through rates as those balances are amortized to expense and the related
benefits are earned. Therefore, the Company charged those unrecognized amounts to regulatory
asset accounts under SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation
,
rather than to Accumulated other comprehensive losses in equity as prescribed by SFAS No. 158.
Application of this standard had the following effects on the Company’s December 31, 2006
consolidated balance sheet:
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Decrease in Executive Survivor and Supplemental Retirement Plan intangible asset
|
|
$
|
(767
|
)
|
|
Increase in regulatory assets for the unrecognized portions of net actuarial
losses, prior service costs and transition obligations that are subject to
recovery through electric rates
|
|
|
36,736
|
|
|
Increase in pension benefit and other postretirement liability
|
|
|
(34,714
|
)
|
|
Increase in deferred tax liability
|
|
|
(502
|
)
|
|
Decrease in accumulated other comprehensive loss for the unrecognized portions
of net actuarial losses, prior service costs and transition obligations that
are not subject to recovery through electric rates (increase to equity)
|
|
|
(753
|
)
|
The adoption of this standard did not affect compliance with debt covenants maintained in
the Company’s financing agreements.
Securities and Exchange Commission Staff Accounting Bulletin (SAB) No. 108,
Considering the
Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements,
was issued in September 2006 to address diversity in practice in quantifying
financial statement misstatements. SAB No. 108 requires a company to quantify misstatements
based on their impact on each of its consolidated financial statements and related disclosures.
SAB 108 is effective for the Company as of December 31, 2006, allowing a one-time transitional
cumulative effect adjustment to retained earnings as of July 1, 2006 for errors that were not
previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB
108 did not have a material impact on the Company’s consolidated financial statements.
2. Business Combinations, Dispositions and Segment Information
The Company acquired no new businesses in 2006.
On January 3, 2005 the Company’s wholly-owned subsidiary, BTD Manufacturing, Inc. (BTD),
acquired the assets of Performance Tool & Die, Inc. (Performance Tool) of Lakeville, Minnesota,
for $4.1 million in cash. Performance Tool specializes in manufacturing mid to large progressive
dies for customers throughout the Midwest, East and West Coasts, and the southern United States.
Performance Tool’s revenues for the year ended December 31, 2004 were $4.1 million. This
acquisition provided expanded growth opportunities for both BTD and Performance Tool.
Also, on January 3, 2005 the Company’s wholly-owned subsidiary, ShoreMaster, Inc. (ShoreMaster),
acquired the common stock of Shoreline Industries, Inc. (Shoreline), of Pine River, Minnesota,
for $2.4 million in cash. Shoreline is a manufacturer of boatlift motors and other accessories
for lifts and docks with sales throughout the United States, but primarily in Minnesota and
Wisconsin. Shoreline’s revenues for the year ended December 31, 2004 were $2.1 million. The
acquisition of Shoreline secures a source of components and expands potential markets for
ShoreMaster products.
On May 31, 2005 ShoreMaster acquired the assets of Southeast Floating Docks, Inc., of St.
Augustine, Florida for $4.0 million in cash. Southeast Floating Docks is a leading manufacturer
of concrete floating dock systems for marinas. They have designed custom floating systems and
conducted installations mainly in the southeast United States and the Caribbean. Southeast
Floating Docks had revenues of $4.5 million in 2004. This acquisition enables ShoreMaster to
offer a wider range of products to its customers and expands its geographic reach in the
Southeast region of the United States.
Below are condensed balance sheets, at the date of the business combinations, disclosing the
allocation of the purchase price assigned to each major asset and liability category of the
acquired companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
|
|
|
Shoreline
|
|
|
Southeast
|
|
|
(in thousands)
|
|
Tool
|
|
|
Industries
|
|
|
Floating Docks
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
748
|
|
|
$
|
464
|
|
|
$
|
2,437
|
|
|
Plant
|
|
|
1,396
|
|
|
|
260
|
|
|
|
415
|
|
|
Deferred income taxes
|
|
|
22
|
|
|
|
—
|
|
|
|
—
|
|
|
Goodwill
|
|
|
1,772
|
|
|
|
1,442
|
|
|
|
2,804
|
|
|
Other intangible assets
|
|
|
800
|
|
|
|
557
|
|
|
|
1,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
4,738
|
|
|
$
|
2,723
|
|
|
$
|
6,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
324
|
|
|
$
|
86
|
|
|
$
|
318
|
|
|
Deferred revenue
|
|
|
—
|
|
|
|
—
|
|
|
|
2,520
|
|
|
Deferred income taxes
|
|
|
—
|
|
|
|
235
|
|
|
|
—
|
|
|
Long-term debt
|
|
|
298
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
622
|
|
|
$
|
321
|
|
|
$
|
2,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid
|
|
$
|
4,116
|
|
|
$
|
2,402
|
|
|
$
|
3,968
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill and other intangible assets related to the Performance Tool acquisition are deductible
for income tax purposes over 15 years. Other intangible assets related to the Performance Tool
acquisition includes $239,000 for a nonamortizable trade name and $561,000 in other intangible
assets being amortized over 3 to 15 years for book purposes. Goodwill and other intangible
assets related to the Shoreline acquisition are not deductible for income tax purposes, except
for a $171,000 noncompete agreement being amortized over 15 years for income tax purposes. Other
intangible assets related to the Shoreline acquisition includes $149,000 for a nonamortizable
brand name and $408,000 in other intangible assets being amortized over 5 to 20 years for book
purposes. Goodwill and other intangible assets related to the Southeast Floating Docks
acquisition are deductible for income tax purposes over 15 years. Other intangible assets
related to the Southeast Floating Docks acquisition includes $1.0 million for a nonamortizable
brand name.
On August 18, 2004 the Company acquired all of the outstanding common stock of IPH, located in
Ririe, Idaho, a leading processor of dehydrated potato products in North America, for $68.2
million in cash. An additional $6.0 million in cash was placed in escrow to pay off earn-out contingencies if IPH achieved certain financial targets
for the period from August 1, 2004 through July 31, 2005. The financial targets were not
achieved and the $6.0 million of funds held in escrow were returned to the Company in the third
quarter of 2005. The results of operations of IPH have been included in the Company’s
consolidated results of operations since the date of acquisition and are included in the food
ingredient processing segment. This acquisition added a new platform to the Company’s
diversified portfolio of businesses. IPH is headquartered in Ririe, Idaho, where its largest
processing facility is located. It also has potato dehydration plants in Souris, Prince Edward
Island, Canada, and Center, Colorado. IPH supplies products for use in foods such as mashed
potatoes, snacks and baked goods. Its customers include many of the largest domestic and
international food manufacturers in the snack food, foodservice and baking industries. IPH
exports potato products to Europe, the Middle East, the Pacific Rim and Central America. IPH had
revenues of $43.5 million for its fiscal year ended July 31, 2004.
Below is a condensed balance sheet of IPH disclosing the final allocation of the purchase price
assigned to each major asset and liability category.
|
|
|
|
|
|
|
(in thousands)
|
|
IPH
|
|
|
|
|
Assets
|
|
|
|
|
|
Current assets
|
|
$
|
17,740
|
|
|
Plant
|
|
|
35,296
|
|
|
Goodwill
|
|
|
24,240
|
|
|
Other intangible assets
|
|
|
13,200
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
90,476
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Current liabilities
|
|
$
|
5,893
|
|
|
Deferred income taxes
|
|
|
12,408
|
|
|
Long-term debt
|
|
|
2,140
|
|
|
Class B common stock options
|
|
|
1,832
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
22,273
|
|
|
|
|
|
|
|
Cash paid
|
|
$
|
68,203
|
|
|
|
|
|
|
Goodwill and other intangible assets related to the IPH acquisition are not deductible for
income tax purposes. Other intangible assets related to the IPH acquisition includes $10.0
million for customer relationships being amortized over 25 years and a $3.2 million
nonamortizable trade name.
All of the acquisitions described above were accounted for using the purchase method of
accounting. The pro forma effect of these acquisitions on 2005 and 2004 revenues, net income or
earnings per share was not significant.
In June 2006, OTESCO, the Company’s energy services company, sold its gas marketing operations.
In 2005, the Company sold Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication,
Inc. (SGS) and Chassis Liner Corporation (CLC). Prior to disposition, OTESCO’s gas marketing
operations and MIS were included in the other business operations segment and SGS and CLC were
included in the manufacturing segment. See note 16 on discontinued operations for further
discussion.
Segment Information
—The accounting policies of the segments are described under note 1
— Summary of Significant Accounting Policies. The Company’s businesses have been classified
into six segments based on products and services and reach customers in all 50 states and
international markets. The six segments are: electric, plastics, manufacturing, health services,
food ingredient processing and other business operations.
Electric includes the production, transmission, distribution and sale of electric energy in
Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. The electric
utility operations have been the Company’s primary business since incorporation. The Company’s
electric operations, including wholesale power sales, are operated as a division of Otter Tail
Corporation.
All
of the businesses in the following segments are owned by a wholly-owned subsidiary of the Company.
Plastics consists of businesses producing polyvinyl chloride and polyethylene pipe in the Upper
Midwest and Southwest regions of the United States.
Manufacturing consists of businesses in the following manufacturing activities: production of
waterfront equipment, wind towers, material and handling trays and horticultural containers,
contract machining, and metal parts stamping and fabrication. These businesses have
manufacturing facilities in Minnesota, North Dakota, South Carolina, Missouri, California,
Florida and Ontario, Canada and sell products primarily in the United States.
Health services consists of businesses involved in the sale of diagnostic medical equipment,
patient monitoring equipment and related supplies and accessories. These businesses also provide
equipment maintenance, diagnostic imaging services and rental of diagnostic medical imaging
equipment to various medical institutions located throughout the United States.
Food ingredient processing consists of IPH, which owns and operates potato dehydration plants in
Ririe, Idaho, Center, Colorado and Souris, Prince Edward Island, Canada. IPH produces dehydrated
potato products that are sold in the United States, Canada, Europe, the Middle East, the Pacific
Rim and Central America.
Other business operations consists of businesses in residential, commercial and industrial
electric contracting industries, fiber optic and electric distribution systems, wastewater and
HVAC systems construction, transportation and energy services, as well as the portion of
corporate general and administrative expenses that are not allocated to other segments. These
businesses operate primarily in the Central United States, except for the transportation company
which operates in 48 states and 6 Canadian provinces.
No single external customer accounts for 10% or more of the Company’s revenues. Substantially
all of the Company’s long-lived assets are within the United States except for a food ingredient
processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower
manufacturing plant in Fort Erie, Ontario, Canada.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of sales revenue by country for the year ended December 31:
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
United States of America
|
|
|
97.2
|
%
|
|
|
97.8
|
%
|
|
|
96.9
|
%
|
|
Canada
|
|
|
1.3
|
%
|
|
|
1.1
|
%
|
|
|
2.2
|
%
|
|
All other countries
|
|
|
1.5
|
%
|
|
|
1.1
|
%
|
|
|
0.9
|
%
|
The Company evaluates the performance of its business segments and allocates resources to them
based on earnings contribution and return on total invested capital. Information on continuing
operations for the business segments for 2006, 2005 and 2004 is presented in the following
table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
306,014
|
|
|
$
|
312,985
|
|
|
$
|
266,385
|
|
|
Plastics
|
|
|
163,135
|
|
|
|
158,548
|
|
|
|
115,426
|
|
|
Manufacturing
|
|
|
311,811
|
|
|
|
244,311
|
|
|
|
201,615
|
|
|
Health services
|
|
|
135,051
|
|
|
|
123,991
|
|
|
|
114,318
|
|
|
Food ingredient processing
|
|
|
45,084
|
|
|
|
38,501
|
|
|
|
14,023
|
|
|
Other business operations
|
|
|
147,436
|
|
|
|
107,400
|
|
|
|
104,002
|
|
|
Intersegment eliminations
|
|
|
(3,577
|
)
|
|
|
(3,867
|
)
|
|
|
(2,733
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,104,954
|
|
|
$
|
981,869
|
|
|
$
|
813,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
25,756
|
|
|
$
|
24,397
|
|
|
$
|
24,236
|
|
|
Plastics
|
|
|
2,815
|
|
|
|
2,511
|
|
|
|
2,297
|
|
|
Manufacturing
|
|
|
11,076
|
|
|
|
9,447
|
|
|
|
7,828
|
|
|
Health services
|
|
|
3,660
|
|
|
|
4,038
|
|
|
|
5,047
|
|
|
Food ingredient processing
|
|
|
3,759
|
|
|
|
3,399
|
|
|
|
1,118
|
|
|
Other business operations
|
|
|
2,917
|
|
|
|
2,666
|
|
|
|
2,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
49,983
|
|
|
$
|
46,458
|
|
|
$
|
43,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
10,315
|
|
|
$
|
10,271
|
|
|
$
|
10,109
|
|
|
Plastics
|
|
|
814
|
|
|
|
1,080
|
|
|
|
834
|
|
|
Manufacturing
|
|
|
6,550
|
|
|
|
4,516
|
|
|
|
2,480
|
|
|
Health services
|
|
|
910
|
|
|
|
822
|
|
|
|
925
|
|
|
Food ingredient processing
|
|
|
481
|
|
|
|
165
|
|
|
|
13
|
|
|
Other business operations
|
|
|
431
|
|
|
|
1,605
|
|
|
|
3,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
19,501
|
|
|
$
|
18,459
|
|
|
$
|
18,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
38,802
|
|
|
$
|
55,984
|
|
|
$
|
45,234
|
|
|
Plastics
|
|
|
22,959
|
|
|
|
22,803
|
|
|
|
9,453
|
|
|
Manufacturing
|
|
|
21,148
|
|
|
|
12,242
|
|
|
|
12,543
|
|
|
Health services
|
|
|
3,909
|
|
|
|
6,875
|
|
|
|
5,075
|
|
|
Food ingredient processing
|
|
|
(6,325
|
)
|
|
|
1,482
|
|
|
|
618
|
|
|
Other business operations*
|
|
|
(2,637
|
)
|
|
|
(17,477
|
)
|
|
|
(15,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
77,856
|
|
|
$
|
81,909
|
|
|
$
|
57,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings available for common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
23,445
|
|
|
$
|
36,566
|
|
|
$
|
30,799
|
|
|
Plastics
|
|
|
14,326
|
|
|
|
13,936
|
|
|
|
5,657
|
|
|
Manufacturing
|
|
|
13,171
|
|
|
|
7,589
|
|
|
|
7,563
|
|
|
Health services
|
|
|
2,230
|
|
|
|
4,007
|
|
|
|
2,951
|
|
|
Food ingredient processing
|
|
|
(4,115
|
)
|
|
|
329
|
|
|
|
351
|
|
|
Other business operations
|
|
|
957
|
|
|
|
(9,260
|
)
|
|
|
(7,555
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
50,014
|
|
|
$
|
53,167
|
|
|
$
|
39,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
35,207
|
|
|
$
|
30,479
|
|
|
$
|
25,368
|
|
|
Plastics
|
|
|
5,504
|
|
|
|
3,636
|
|
|
|
2,544
|
|
|
Manufacturing
|
|
|
20,048
|
|
|
|
16,112
|
|
|
|
13,163
|
|
|
Health services
|
|
|
4,720
|
|
|
|
3,095
|
|
|
|
3,919
|
|
|
Food ingredient processing
|
|
|
1,762
|
|
|
|
2,952
|
|
|
|
3,528
|
|
|
Other business operations
|
|
|
2,207
|
|
|
|
3,695
|
|
|
|
962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
69,448
|
|
|
$
|
59,969
|
|
|
$
|
49,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
689,653
|
|
|
$
|
654,175
|
|
|
$
|
634,433
|
|
|
Plastics
|
|
|
80,666
|
|
|
|
76,573
|
|
|
|
67,574
|
|
|
Manufacturing
|
|
|
219,336
|
|
|
|
177,969
|
|
|
|
150,800
|
|
|
Health services
|
|
|
66,126
|
|
|
|
67,066
|
|
|
|
66,506
|
|
|
Food ingredient processing
|
|
|
94,462
|
|
|
|
96,023
|
|
|
|
92,392
|
|
|
Other business operations
|
|
|
108,118
|
|
|
|
95,989
|
|
|
|
81,851
|
|
|
Discontinued operations
|
|
|
289
|
|
|
|
13,701
|
|
|
|
40,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,258,650
|
|
|
$
|
1,181,496
|
|
|
$
|
1,134,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Income before income taxes of other business operations includes unallocated corporate expenses
of $11,303,000, $16,650,000 and $13,855,000 for the years ended December 31, 2006, 2005 and
2004, respectively.
|
3. Rate Matters
Minnesota
In September 2004, the Company provided a letter to the Minnesota Public Utilities Commission
(MPUC) summarizing issues and conclusions of an internal investigation the Company had
completed related to claims of allegedly improper regulatory filings brought to the Company’s
attention by certain individuals. On November 30, 2004 the electric utility filed a report
with the MPUC responding to these claims. In 2005, the Energy Division of the Department of
Commerce (DOC), the Residential Utilities Division of the Office of Attorney General and the
claimants filed comments in response to the report, to which the Company filed reply comments.
A hearing before the MPUC was held on February 28, 2006. As a result of the hearing, the
electric utility agreed that within 90 days it would file a revised Regulatory Compliance
Plan, an updated Corporate Cost Allocation Manual and documentation of the definitions of its
chart of accounts. The electric utility filed these documents with the MPUC in the second
quarter of 2006. The Company received comments on its filings from the DOC and the claimants
and filed reply comments in August 2006.
The DOC recommended accepting the revised Regulatory Compliance Plan and the chart of accounts
definition. The electric utility filed supplemental comments related to its Corporate
Allocation Manual in November 2006. The electric utility also agreed to file a general rate
case in Minnesota on or before October 1, 2007. At a MPUC meeting on January 25, 2007 all
remaining open issues were resolved. The MPUC accepted the Company’s compliance filing with
minor changes, agreed to allow the electric utility to calculate corporate cost allocations as
proposed, determined not to conduct any further review at this time and required the Company
to include all of its short-term debt in its AFUDC calculations. The Company has agreed to
provide the MPUC the results of the current FERC Operational Audit when available, compare the
corporate allocation method to a commonly accepted methodology in its next rate case, and
provide the results of the Company’s investigation relating to a 2007 hotline complaint. The
Company recorded a noncash charge to other income and deductions of $3.3 million in 2006
related to uncertainty with respect to the capitalized cost of construction funds included in
the electric utility’s rate base.
In December 2005, the MPUC issued an order denying the utility’s request to allow recovery of
certain Midwest Independent Transmission System Operator (MISO)-related costs through the fuel
clause adjustment (FCA) in Minnesota retail rates and requiring a refund of amounts previously
collected pursuant to an interim order issued in April 2005. The utility recorded a $1.9 million
reduction in revenue and a refund payable in December 2005 to reflect the refund obligation. On
February 9, 2006 the MPUC decided to reconsider its December 2005 order. The MPUC’s final order
was issued on February 24, 2006 requiring jurisdictional investor-owned utilities in the state
to participate with the DOC and other parties in a proceeding that would evaluate suitability of
recovery of certain MISO Day 2 energy market costs through the FCA. The February 24, 2006 order
eliminated the refund provision from the December 2005 order and allowed that any MISO-related
costs not recovered through the FCA may be deferred for a period of 36 months, with possible
recovery through base rates in the utility’s next general rate case. As a result, the utility
recognized $1.9 million in revenue and reversed the refund payable in February 2006. The
Minnesota utilities and other parties submitted a final report to the MPUC in July 2006.
On July 24, 2006 the DOC and Residential and Small Business Utilities Division of the Office of
the Attorney General (RUD-OAG) filed comments supporting the idea of convening a technical
conference on the recovery of MISO costs among other things. On August 7, 2006 the MPUC received
reply comments from the RUD-OAG and collectively from the utilities. On October 31, 2006 the
MPUC convened a technical conference at which the parties provided a summary of the Joint
Report. On November 6, 2006 the utilities filed supplemental comments. This matter returned to
the MPUC on November 7, 2006.
In an order issued on December 20, 2006 the MPUC stated that except for schedule 16 and 17
administrative costs, discussed below, each petitioning utility may recover the charges imposed
by the MISO for MISO Day 2 operations (offset by revenues from Day 2 operations via net
accounting) through the calculation of the utility’s FCA from the period April 1, 2005 through a
period of at least three years after the date of this order. The MPUC ordered the utilities to
refund schedule 16 and 17 costs collected through the FCA since the inception of MISO Day 2
Markets in April 2005 and stated that each petitioning utility may use
deferred accounting for MISO schedule 16 and 17 costs incurred since April 1, 2005. Each utility may continue deferring schedule 16 and 17 costs without interest until the
earlier of March 1, 2009 or the utility’s next electric rate case. By March 1, 2009 the utility
shall begin amortizing the balance of the deferred Day 2 costs through March 1, 2012 unless and
until the utility has a rate case addressing the utility’s proposal for recovering the balance.
In its next rate case a utility may seek to recover schedule 16 and 17 costs at an appropriate
level of base rate recovery. The utility may not increase rates to recover MISO administrative
costs unless the costs were prudently incurred, reasonable, resulted in benefits justifying
recovery and not already recovered through other rates. However, a utility may seek to recover
schedule 16 and 17 costs and associated amortizations through interim rates pending the
resolution of a rate case, subject to final MPUC approval. As a result of the December 20, 2006
order, the utility will refund $446,000 to Minnesota retail customers through the FCA over a
twelve-month period beginning in January 2007 and will defer that amount and additional amounts
related to MISO schedule 16 and 17 costs incurred subsequent to December 31, 2006 until it is
allowed recovery of those costs in its next rate case or in interim rates. The electric utility
expects to file its next electric rate case on or before October 1, 2007.
North Dakota
In September 2004, a letter was provided to the North Dakota Public Service Commission (NDPSC)
summarizing issues and conclusions of an internal investigation completed by the Company as it
related to claims of allegedly improper regulatory filings brought to the Company’s attention
by certain individuals. The NDPSC did not open a formal docket, but its staff reviewed the
issues. The Company responded to various data requests and worked with staff and the NDPSC to
resolve issues raised by the internal investigation. In an order issued in May 2006, the NDPSC
stated that in the opinion of staff, the impact of the issues reviewed was not significant
enough to cause a change in the results of the Company’s performance-based ratemaking plan in
place from 2001 through 2005.
In February 2005, the utility filed with the NDPSC a petition to seek recovery of certain
MISO-related costs through the FCA. The NDPSC granted interim recovery through the FCA in
April 2005 but, similar to the decision of the MPUC, conditioned the relief as being subject
to refund until the merits of the case are determined. The NDPSC has taken no further action
regarding this filing.
Federal
On April 25, 2006 the FERC issued an order requiring MISO to refund to customers, with
interest, amounts related to real-time revenue sufficiency guarantee (RSG) charges that were
not allocated to day-ahead virtual supply offers in accordance with MISO’s Transmission and
Energy Markets Tariff (TEMT) going back to the commencement of MISO Day 2 markets in April
2005. On May 17, 2006 the FERC issued a Notice of Extension of Time, permitting MISO to delay
compliance with the directives contained in its April 2006 order, including the requirement to
refund to customers the amounts due, with interest, from April 1, 2005 and the requirement to
submit a compliance filing. The Notice stated that the order on rehearing would provide the
appropriate guidance regarding the timing of compliance filing. On October 26, 2006 the FERC
issued an order on rehearing, stating it would not require refunds related to real-time RSG
charges that had not been allocated to day-ahead virtual supply offers in accordance with
MISO’s TEMT going back to the commencement of the MISO Day 2 market in April 2005. However,
the FERC ordered prospective allocation of RSG charges to virtual transactions consistent with
the TEMT to prevent future inequity and directed MISO to propose a charge that assesses RSG
costs to virtual supply offers based on the RSG costs virtual supply offers cause within 60
days of the October 26, 2006 order. On December 27, 2006 the FERC issued an order granting
rehearing of the October 26, 2006 order.
The Division of Operation Audits of the FERC Office of Market Oversight and Investigations
(OMOI) commenced an audit of the electric utility’s transmission practices in 2005. The
purpose of the audit is to determine whether and how the electric utility’s transmission
practices are in compliance with the FERC’s applicable rules and regulations and tariff
requirements and whether and how the implementation of the electric utility’s waivers from the
requirements of Order No. 889 and Order No. 2004 restricts access to transmission information
that would benefit the electric utility’s off-system sales. The Division of Operation Audits
of the OMOI has not issued an audit report. The Company cannot predict if the results of the audit will have any impact on the Company’s consolidated financial statements.
The Comprehensive Energy Policy Act of 2005 (the 2005 Energy Act) signed into law in August
2005, will substantially affect the regulation of energy companies, including the electric
utility. The 2005 Energy Act amends federal energy laws and provides the FERC with new
oversight responsibilities. Among the important changes to be implemented as a result of this
legislation are the following:
|
|
•
|
|
The Public Utility Holding Company Act of 1935 (PUHCA) was repealed effective February
8, 2006. PUHCA significantly restricted mergers and acquisitions in the electric utility
sector.
|
|
|
|
|
•
|
|
The FERC will appoint and oversee an electric reliability organization to establish
and enforce mandatory reliability rules regarding the interstate electric transmission
system. It is expected that the electric reliability organization will be approved and
begin operation by mid-year 2006.
|
|
|
|
|
•
|
|
The FERC will establish incentives for transmission companies, such as
performance-based rates, recovery of costs to comply with reliability rules and
accelerated depreciation for investments in transmission infrastructure.
|
|
|
|
|
•
|
|
Federal support will be available for certain clean coal power initiatives, nuclear
power projects and renewable energy technologies.
|
The implementation of the 2005 Energy Act requires proceedings at the state level and the
development of regulations by the FERC and the Department of Energy, as well as other federal
agencies. The Company cannot predict when these proceedings and regulations will commence or be
finalized. The Company is still studying the legislation and its effect and cannot predict with
certainty the impact on its electric operations.
4. Regulatory Assets and Liabilities
The following table indicates the amount of regulatory assets and liabilities recorded on the
Company’s consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation, prior service
costs and actuarial losses on pension and other
postretirement benefits
|
|
$
|
36,736
|
|
|
$
|
—
|
|
|
Deferred income taxes
|
|
|
11,712
|
|
|
|
16,724
|
|
|
Accrued cost-of-energy revenue
|
|
|
10,735
|
|
|
|
10,400
|
|
|
Reacquisition premiums
|
|
|
2,694
|
|
|
|
2,995
|
|
|
Deferred conservation program costs
|
|
|
1,036
|
|
|
|
1,064
|
|
|
MISO schedule 16 and 17 deferred administrative costs
|
|
|
541
|
|
|
|
—
|
|
|
Accumulated ARO accretion/depreciation adjustment
|
|
|
249
|
|
|
|
209
|
|
|
Plant acquisition costs
|
|
|
151
|
|
|
|
196
|
|
|
Deferred marked-to-market losses
|
|
|
—
|
|
|
|
1,423
|
|
|
|
|
|
|
|
|
|
|
Total regulatory assets
|
|
$
|
63,854
|
|
|
$
|
33,011
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
|
Accumulated reserve for estimated removal costs
|
|
$
|
58,496
|
|
|
$
|
52,582
|
|
|
Deferred income taxes
|
|
|
5,228
|
|
|
|
5,961
|
|
|
Deferred marked-to-market gains
|
|
|
—
|
|
|
|
2,925
|
|
|
Gain on sale of division office building
|
|
|
151
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
Total regulatory liabilities
|
|
$
|
63,875
|
|
|
$
|
61,624
|
|
|
|
|
|
|
|
|
|
|
Net regulatory liability position
|
|
$
|
21
|
|
|
$
|
28,613
|
|
|
|
|
|
|
|
|
|
The regulatory asset related to the unrecognized transition obligation on postretirement medical
benefits and prior service costs and actuarial losses on pension and other postretirement
benefits represents benefit costs that will be subject to recovery through rates as they are
expensed over the remaining service lives of active employees included in the plans. These
unrecognized benefit costs were required to be recognized as components of Accumulated other
comprehensive
income in equity under SFAS No. 158,
Employer’s Accounting for Defined Benefit
Pension and Other Postretirement Plans,
adopted in December 2006, but were
determined to be eligible for treatment as regulatory assets based on their probable recovery in
future retail electric rates. The regulatory assets and liabilities related to deferred income
taxes result from changes in statutory tax rates accounted for in accordance with SFAS No. 109,
Accounting for Income Taxes
. Accrued cost-of-energy revenue included in Accrued utility revenues
will be recovered over the next nine months. Reacquisition premiums included in Unamortized debt
expense and reacquisition premiums are being recovered from electric utility customers over the
remaining original lives of the reacquired debt issues, the longest of which is 15.6 years.
Deferred conservation program costs represent mandated conservation expenditures recoverable
through retail electric rates over the next 1.5 years. MISO schedule 16 and 17 deferred
administrative costs were excluded from recovery through the FCA in Minnesota in a December 2006
order issued by the MPUC. The MPUC ordered the Company to refund MISO schedule 16 and 17 charges
that had been recovered through the FCA since the inception of MISO Day 2 markets in April 2005,
but allowed for deferral and recovery of those costs through rates established in the Company’s
next rate case scheduled to be filed on or before October 1, 2007. The accumulated reserve for
estimated removal costs is reduced for actual removal costs incurred. Plant acquisition costs
will be amortized over the next 3.4 years. The remaining regulatory assets and liabilities are
being recovered from, or will be paid to, electric customers over the next 30 years.
If for any reason, the Company’s regulated businesses cease to meet the criteria for application
of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities that
no longer meet such criteria would be removed from the consolidated balance sheet and included
in the consolidated statement of income as an extraordinary expense or income item in the period
in which the application of SFAS No. 71 ceases.
5. Forward Energy Contracts Classified as Derivatives
Electricity Contracts
All of the electric utility’s wholesale purchases and sales of energy under forward contracts
that do not meet the definition of capacity contracts are considered derivatives subject to
mark-to-market accounting. The electric utility’s objective in entering into forward contracts
for the purchase and sale of energy is to optimize the use of its generating and transmission
facilities and leverage its knowledge of wholesale energy markets in the region to maximize
financial returns for the benefit of both its customers and shareholders. The electric utility’s
intent in entering into certain of these contracts is to settle them through the physical
delivery of energy when physically possible and economically feasible. The electric utility also
enters into certain contracts for trading purposes with the intent to profit from fluctuations
in market prices through the timing of purchases and sales.
Electric revenues include $25,965,000 in 2006, $46,397,000 in 2005 and $27,228,000 in 2004
related to wholesale electric sales and net unrealized derivative gains on forward energy
contracts and, in 2006 and 2005, sales of financial transmission rights and daily settlements of
virtual transactions in the MISO market, broken down as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Wholesale sales — company—owned generation
|
|
$
|
23,130
|
|
|
$
|
24,799
|
|
|
$
|
17,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from settled contracts at market prices
|
|
|
385,978
|
|
|
|
474,882
|
|
|
|
134,715
|
|
|
Market cost of settled contracts
|
|
|
(383,594
|
)
|
|
|
(457,728
|
)
|
|
|
(128,685
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net margins on settled contracts at market
|
|
|
2,384
|
|
|
|
17,154
|
|
|
|
6,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marked-to-market gains on settled contracts
|
|
|
20,950
|
|
|
|
11,118
|
|
|
|
12,663
|
|
|
Marked-to-market losses on settled contracts
|
|
|
(20,702
|
)
|
|
|
(9,590
|
)
|
|
|
(9,736
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net marked-to-market gain on settled contracts
|
|
|
248
|
|
|
|
1,528
|
|
|
|
2,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized marked-to-market gains on open contracts
|
|
|
2,215
|
|
|
|
5,678
|
|
|
|
514
|
|
|
Unrealized marked-to-market losses on open contracts
|
|
|
(2,012
|
)
|
|
|
(2,762
|
)
|
|
|
(213
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized marked-to-market gain on open contracts
|
|
|
203
|
|
|
|
2,916
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale electric revenue
|
|
$
|
25,965
|
|
|
$
|
46,397
|
|
|
$
|
27,228
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables show the effect of marking to market forward contracts for the
purchase and sale of energy on the Company’s consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
Current asset — marked-to-market gain
|
|
$
|
2,215
|
|
|
$
|
8,603
|
|
|
Regulatory asset — deferred marked-to-market loss
|
|
|
—
|
|
|
|
1,423
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
2,215
|
|
|
|
10,026
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liability — marked-to-market loss
|
|
|
(2,012
|
)
|
|
|
(4,185
|
)
|
|
Regulatory liability — deferred marked-to-market gain
|
|
|
—
|
|
|
|
(2,925
|
)
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
(2,012
|
)
|
|
|
(7,110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net fair value of marked-to-market energy contracts
|
|
$
|
203
|
|
|
$
|
2,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
(in thousands)
|
|
December 31, 2006
|
|
|
|
|
Fair value at beginning of year
|
|
$
|
2,916
|
|
|
Amount realized on contracts entered into in 2005 and settled in
2006
|
|
|
(2,090
|
)
|
|
Changes in fair value of contracts entered into in 2005
|
|
|
(826
|
)
|
|
|
|
|
|
|
Net fair value of contracts entered into in 2005 at year end 2006
|
|
|
—
|
|
|
Changes in fair value of contracts entered into in 2006
|
|
|
203
|
|
|
|
|
|
|
|
Net fair value at end of year
|
|
$
|
203
|
|
|
|
|
|
|
The $203,000 in recognized but unrealized net gains on the forward energy purchases and sales
marked to market as of December 31, 2006 is expected to be realized on physical settlement or
settled by an offsetting agreement with the counterparty to the original contract as scheduled
over the following quarters in the amounts listed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter
|
|
2nd Quarter
|
|
|
|
(in thousands)
|
|
2007
|
|
2007
|
|
Total
|
|
|
|
Net gain
|
|
$
|
159
|
|
|
$
|
44
|
|
|
$
|
203
|
|
All of the forward energy purchase contracts that are marked to market as of December 31, 2006
are offset by forward energy sales contracts in terms of volumes and delivery periods.
Natural Gas Contracts
In the third quarter of 2006, IPH entered into forward natural gas swaps on the New York
Mercantile Exchange market to hedge its exposure to fluctuations in natural gas prices related
to approximately 50% of its anticipated natural gas needs through March 2007 for its Ririe,
Idaho and Center, Colorado dehydration plants. These forward contracts are derivatives subject
to mark-to-market accounting but they do not qualify for hedge accounting treatment as cash flow
hedges because the changes in the NYMEX prices do not correspond closely enough to changes in
natural gas prices at the locations of physical delivery. Therefore, IPH includes net changes in
the market values of these forward contracts in net income as components of cost of goods sold
in the period of recognition.
Cost of goods sold in the food ingredient processing segment includes $542,000 in losses in
2006, of which $171,000 was realized, related to IPH’s forward natural gas contracts on NYMEX as
a result of declining natural gas prices in 2006. The net fair value of contracts held as of
December 31, 2006 was ($371,000). IPH’s forward natural gas swaps marked to market as of
December 31, 2006 are scheduled for settlement in the first quarter of 2007.
6. Common Shares and Earnings Per Share
In 2006, the Company issued 107,458 common shares as a result of stock option exercises, 2,209
common shares and 19,800 restricted common shares as directors’
compensation and 7,450 common shares for restricted stock units that were granted and vested in 2006. The Company retired
16,370 common shares for tax withholding purposes in connection with the vesting of restricted
common shares in 2006.
Stock Incentive Plan
Under the 1999 Stock Incentive Plan (Incentive Plan) a total of 2,600,000 common shares were
authorized for granting stock awards. The Incentive Plan provides for the grant of stock
options, stock appreciation rights, restricted stock, restricted stock units, performance
awards, and other stock and stock-based awards. On April 10, 2006 the Company’s shareholders
approved amendments to the Incentive Plan increasing the number of common shares available under
the Incentive Plan from 2,600,000 common shares to 3,600,000 common shares, extending the term
of the Incentive Plan from December 13, 2008 to December 13, 2013 and making certain other
changes to the terms of the Incentive Plan.
Employee Stock Purchase Plan
The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the
Company’s common shares at 85% of the market price at the end of each six-month purchase period.
On April 10, 2006 the Company’s shareholders approved an amendment to the Purchase Plan
increasing the number of common shares available under the Purchase
Plan from 400,000 common shares to 900,000 common shares, of which 449,842 were still available for purchase as of
December 31, 2006. At the discretion of the Company, shares purchased under the Purchase Plan
can be either new issue shares or shares purchased in the open market. To provide shares for the
Purchase Plan, 53,258 common shares were purchased in the open market
in 2006, 69,401 common shares were purchased in the open market in 2005 and 66,958 common shares were issued in 2004.
The shares to be purchased by employees participating in the Purchase Plan are not considered
dilutive for the purpose of calculating diluted earnings per share during the investment period.
Dividend Reinvestment and Share Purchase Plan
On August 30, 1996 the Company filed a shelf registration statement with the Securities and
Exchange Commission (SEC) 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 in the open market. From June 1999 through December
2003, common shares needed for the Plan were purchased in the open market. From January through
October 2004 new shares were issued for this Plan. Starting in November 2004 the Company began
purchasing common shares in the open market. Through December 31, 2006, 944,507 common shares
had been issued to meet the requirements of the Plan.
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 15, 1997.
One Right was also issued with respect to each common share issued after February 15, 1997. The
Rights expired pursuant to their terms on January 27, 2007.
Earnings Per Share
Basic earnings per common share are calculated by dividing earnings available for common shares
by the weighted average number of common shares outstanding during the period. Diluted earnings
per common share are calculated by adjusting outstanding shares, assuming conversion of all
potentially dilutive stock options. Stock options with exercise prices greater than the market
price are excluded from the calculation of diluted earnings per common share. Nonvested
restricted shares granted to the Company’s directors and employees are considered dilutive for
the purpose of calculating diluted earnings per share but are considered contingently returnable
and not outstanding for the purpose of calculating basic earnings per share. Underlying shares
related to nonvested restricted stock units granted to employees are considered dilutive for the
purpose of calculating diluted earnings per share. Shares expected to be awarded for stock
performance awards granted to executive officers are considered dilutive for the purpose of
calculating diluted earnings per share. Currently, the Company intends to purchase shares on the
open market for stock performance awards earned.
Excluded from the calculation of diluted earnings per share are the following outstanding stock
options which had exercise prices greater than the average market price for the years ended
December 31, 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Options Outstanding
|
|
Range of Exercise Prices
|
|
|
|
2006
|
|
|
210,250
|
|
|
$
|
29.74 — $31.34
|
|
|
2005
|
|
|
237,624
|
|
|
$
|
28.66 — $31.34
|
|
|
2004
|
|
|
1,067,900
|
|
|
$
|
26.25 — $31.34
|
|
7.
Share-Based Payments
On January 1, 2006 the Company adopted the accounting provisions of SFAS No. 123(R) (revised
2004),
Share-Based Payment,
on a modified prospective basis. SFAS No. 123(R) is a revision of
SFAS No. 123,
Accounting for Stock-based Compensation,
and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.
Under SFAS No. 123(R), the Company records stock-based
compensation as an expense on its income statement over the period earned based on the estimated
fair value of the stock or options awarded on their grant date. The Company elected the modified
prospective method of adopting SFAS No. 123(R), under which prior periods are not retroactively
revised. The valuation provisions of SFAS No. 123(R) apply to awards granted after the effective
date. Estimated stock-based compensation expense for awards granted prior to the effective date
but that remain nonvested on the effective date will be recognized over the remaining service
period using the compensation cost estimated for the SFAS No. 123 pro forma disclosures.
Additionally, the adoption of SFAS No. 123(R) resulted in the reclassification of $798,000 in
credits related to outstanding restricted share-based compensation from equity on the Company’s
consolidated balance sheet to a liability on January 1, 2006 because of income tax withholding
provisions in the share-based award agreements. The adoption of SFAS 123(R) also resulted in the
elimination of Unearned compensation from the equity section of the Company’s consolidated
balance sheet on January 1, 2006 by netting the account balance of $1,720,000 against Premium on
common shares.
As of December 31, 2006 the total remaining unrecognized amount of compensation expense related
to stock-based compensation was approximately $3.3 million (before income taxes), which will be
amortized over a weighted-average period of 2.0 years.
The Company has six share-based payment programs. The effect of SFAS No. 123(R) accounting on
each of these programs is explained in the following paragraphs.
Purchase Plan
The Purchase Plan allows employees through payroll withholding to purchase shares of the
Company’s common stock at a 15% discount from the average market price on the last day of a six
month investment period. Under SFAS 123(R), the Company is required to record compensation
expense related to the 15% discount which was not required under APB No. 25. The 15% discount
resulted in compensation expense of $235,000 in 2006. The 15% discount is not taxable to the
employee and is not a deductible expense for tax purposes for the Company.
Stock Options Granted Under the Incentive Plan
Since the inception of the Incentive Plan in 1999, the Company has granted 2,041,500 options for
the purchase of the Company’s common stock. Of the options granted, 1,999,975 had vested or were
forfeited and 41,525 were not vested as of December 31, 2006. The exercise price of the options
granted has been the average market price of the Company’s common stock on the grant date. These
options were not compensatory under APB No. 25 accounting rules. Under SFAS No. 123(R)
accounting, compensation expense is recorded based on the estimated fair value of the options on
their grant date using a fair-value option pricing model. Under SFAS No. 123(R) accounting, the
fair value of the options granted is recorded as compensation expense over the requisite service
period (the vesting period of the options). The estimated fair value of all options granted
under the Incentive Plan has been based on the Black-Scholes option pricing model.
Under the modified prospective application of SFAS No. 123(R) accounting requirements, the
difference between the intrinsic value of nonvested options and the fair value of those options
of $362,000 on January 1, 2006 is being recognized on a straight-line basis as compensation
expense over the remaining
vesting period of the nonvested options, which, for nonvested options
outstanding on January 1, 2006 will be from January 1, 2006 through April 30, 2007. Accordingly, the Company recorded compensation expense of $271,000 in 2006 related to nonvested
options issued under the Incentive Plan.
Had compensation costs for the stock options issued been determined based on estimated fair
value at the award dates, as prescribed by SFAS No. 123, the Company’s net income for 2005 and
2004 would have decreased as presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share amounts)
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
62,551
|
|
|
$
|
42,195
|
|
|
Total stock-based employee compensation
expense determined under fair value-based
method for all awards net of related tax
effects
|
|
|
(640
|
)
|
|
|
(1,087
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
$
|
61,911
|
|
|
$
|
41,108
|
|
|
Basic earnings per share
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
2.12
|
|
|
$
|
1.59
|
|
|
Pro forma
|
|
$
|
2.09
|
|
|
$
|
1.55
|
|
|
Diluted earnings per share
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
2.11
|
|
|
$
|
1.58
|
|
|
Pro forma
|
|
$
|
2.08
|
|
|
$
|
1.54
|
|
Presented below is a summary of the stock options activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
exercise
|
|
|
|
|
|
|
exercise
|
|
|
|
|
|
|
exercise
|
|
|
Stock Option Activity
|
|
Options
|
|
|
price
|
|
|
Options
|
|
|
price
|
|
|
Options
|
|
|
price
|
|
|
Outstanding,
beginning of year
|
|
|
1,237,164
|
|
|
$
|
25.58
|
|
|
|
1,508,277
|
|
|
$
|
25.35
|
|
|
|
1,531,125
|
|
|
$
|
25.16
|
|
|
Granted
|
|
|
—
|
|
|
|
—
|
|
|
|
74,900
|
|
|
|
24.93
|
|
|
|
72,400
|
|
|
|
26.50
|
|
|
Exercised
|
|
|
107,458
|
|
|
|
22.88
|
|
|
|
257,948
|
|
|
|
22.90
|
|
|
|
51,468
|
|
|
|
19.83
|
|
|
Forfeited
|
|
|
38,468
|
|
|
|
28.60
|
|
|
|
88,065
|
|
|
|
28.79
|
|
|
|
43,780
|
|
|
|
27.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, year end
|
|
|
1,091,238
|
|
|
|
25.74
|
|
|
|
1,237,164
|
|
|
|
25.58
|
|
|
|
1,508,277
|
|
|
|
25.35
|
|
|
|
|
Exercisable, year end
|
|
|
1,049,713
|
|
|
|
25.69
|
|
|
|
1,095,272
|
|
|
|
25.16
|
|
|
|
1,111,681
|
|
|
|
24.27
|
|
|
|
|
Cash received for
Options exercised
|
|
$
|
2,458,000
|
|
|
|
|
|
|
$
|
5,911,000
|
|
|
|
|
|
|
$
|
1,022,000
|
|
|
|
|
|
|
Fair value of options
granted during year
|
|
none granted
|
|
|
|
|
|
$
|
4.76
|
|
|
|
|
|
|
$
|
5.27
|
|
|
|
|
|
|
|
No options were granted in 2006. The fair values of the options granted in 2005 and 2004 were
estimated using the Black-Scholes option-pricing model under the following assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Risk-free interest rate
|
|
|
4.3
|
%
|
|
|
3.9
|
%
|
|
Expected lives
|
|
7 years
|
|
7 years
|
|
Expected volatility
|
|
|
25.4
|
%
|
|
|
25.7
|
%
|
|
Dividend yield
|
|
|
4.4
|
%
|
|
|
4.0
|
%
|
The following table summarizes information about options outstanding as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding
|
|
Options exercisable
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
average
|
|
|
Weighted-
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
Outstanding
|
|
|
remaining
|
|
|
average
|
|
|
Exercisable
|
|
|
average
|
|
|
Range of
|
|
as of
|
|
|
contractual
|
|
|
exercise
|
|
|
as of
|
|
|
exercise
|
|
|
exercise prices
|
|
12/31/06
|
|
|
life (yrs)
|
|
|
price
|
|
|
12/31/06
|
|
|
price
|
|
|
|
|
$18.80—$21.94
|
|
|
251,873
|
|
|
|
2.8
|
|
|
$
|
19.50
|
|
|
|
251,873
|
|
|
$
|
19.48
|
|
|
$21.95—$25.07
|
|
|
56,350
|
|
|
|
8.3
|
|
|
$
|
24.93
|
|
|
|
56,350
|
|
|
$
|
24.93
|
|
|
$25.08—$28.21
|
|
|
566,765
|
|
|
|
5.0
|
|
|
$
|
26.52
|
|
|
|
525,240
|
|
|
$
|
26.42
|
|
|
$28.22—$31.34
|
|
|
216,250
|
|
|
|
5.2
|
|
|
$
|
31.19
|
|
|
|
216,250
|
|
|
$
|
31.17
|
|
Restricted Stock Granted to Directors
Under the Incentive Plan, restricted shares of the Company’s common stock have been granted to
members of the Company’s Board of Directors as a form of compensation. Under APB No. 25
accounting rules, the Company had recognized compensation expense for these restricted stock
grants, ratably, over the four-year vesting period of the restricted shares based on the market
value of the Company’s common stock on the grant date. Under the modified prospective
application of SFAS No. 123(R) accounting requirements, compensation expense related to
nonvested restricted shares outstanding will be recorded based on the estimated fair value of
the restricted shares on their grant dates. On April 9, 2006 the Compensation Committee of the
Company’s Board of Directors granted 19,800 shares of restricted stock to the directors under
the Incentive Plan. The restricted shares vest ratably over a four-year vesting period.
Presented below is a summary of the status of directors’ restricted stock awards for the years
ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Weighted average
|
|
|
|
|
|
|
Weighted average
|
|
|
|
|
|
|
Weighted average
|
|
|
|
|
|
|
|
|
grant-date fair
|
|
|
|
|
|
|
grant-date fair
|
|
|
|
|
|
|
grant-date fair
|
|
|
|
|
Shares
|
|
|
value
|
|
|
Shares
|
|
|
value
|
|
|
Shares
|
|
|
value
|
|
|
|
|
Nonvested, beginning of year
|
|
|
27,000
|
|
|
$
|
26.32
|
|
|
|
22,600
|
|
|
$
|
27.61
|
|
|
|
18,450
|
|
|
$
|
28.74
|
|
|
Granted
|
|
|
19,800
|
|
|
$
|
28.24
|
|
|
|
11,700
|
|
|
$
|
24.93
|
|
|
|
10,800
|
|
|
$
|
26.49
|
|
|
Vested
|
|
|
14,025
|
|
|
$
|
26.82
|
|
|
|
7,300
|
|
|
$
|
28.09
|
|
|
|
6,650
|
|
|
$
|
28.94
|
|
|
Forfeited
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested, end of year
|
|
|
32,775
|
|
|
$
|
27.27
|
|
|
|
27,000
|
|
|
$
|
26.32
|
|
|
|
22,600
|
|
|
$
|
27.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense
recognized
|
|
|
|
|
|
$
|
401,000
|
|
|
|
|
|
|
$
|
261,000
|
|
|
|
|
|
|
$
|
219,000
|
|
|
Fair value of shares vested
in year
|
|
|
|
|
|
$
|
376,000
|
|
|
|
|
|
|
$
|
205,057
|
|
|
|
|
|
|
$
|
192,000
|
|
Restricted Stock Granted to Employees
Under the Incentive Plan, restricted shares of the Company’s common stock have been granted to
employees as a form of compensation. Under APB No. 25 accounting rules, the Company had
recognized compensation expense for these restricted stock grants, ratably, over the vesting
periods of the restricted shares based on the market value of the Company’s common stock on the
grant date. Because of income tax withholding provisions in the restricted stock award
agreements related to restricted stock granted to employees, the value of these grants is
considered variable, which, under SFAS No. 123(R), will require the offsetting credit to
compensation expense to be recorded as a liability. Under the modified prospective application
of SFAS No. 123(R) accounting requirements and accounting rules for variable awards,
compensation expense related to nonvested restricted shares granted to employees will be
recorded based on the estimated fair value of the restricted shares on their grant dates and
adjusted for the estimated fair value of any nonvested restricted shares on each subsequent
reporting date. The reporting date fair value of nonvested restricted shares under this program
will be based on the average market value of the Company’s common stock on the reporting date;
$31.47 on December 31, 2006.
In 2006, under SFAS No. 123(R), the amount of compensation expense recorded related to nonvested
restricted shares granted to employees was based on the estimated fair value of the restricted
stock grants. In 2005 and 2004, under APB No. 25, the amount of compensation expense recorded
related to nonvested restricted shares granted to employees was based on the intrinsic value of
the restricted stock grants. The equity account, unearned compensation, was credited when
compensation expense was recorded related to these shares under APB No. 25 accounting. Under
SFAS 123(R) accounting, a current liability account is credited when compensation expense is
recorded. Accumulated liabilities related to nonvested restricted shares issued to employees
under this program will be reversed and credited to the Premium on common shares equity account
as the shares vest.
Presented below is a summary of the status of employees’ restricted stock awards for the
years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
average
|
|
|
|
|
|
|
average
|
|
|
|
|
|
|
average
|
|
|
|
|
|
|
|
|
reporting
|
|
|
|
|
|
|
reporting
|
|
|
|
|
|
|
reporting
|
|
|
|
|
|
|
|
|
date fair
|
|
|
|
|
|
|
date fair
|
|
|
|
|
|
|
date fair
|
|
|
|
|
Shares
|
|
|
value
|
|
|
Shares
|
|
|
value
|
|
|
Shares
|
|
|
value
|
|
|
|
|
Nonvested, beginning of year
|
|
|
72,974
|
|
|
$
|
28.91
|
|
|
|
103,340
|
|
|
$
|
25.31
|
|
|
|
131,800
|
|
|
$
|
27.16
|
|
|
Granted
|
|
|
—
|
|
|
|
|
|
|
|
9,000
|
|
|
$
|
26.31
|
|
|
|
10,540
|
|
|
$
|
26.57
|
|
|
Vested
|
|
|
41,308
|
|
|
$
|
28.98
|
|
|
|
39,126
|
|
|
$
|
25.08
|
|
|
|
39,000
|
|
|
$
|
26.40
|
|
|
Forfeited
|
|
|
—
|
|
|
|
|
|
|
|
240
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested, end of year
|
|
|
31,666
|
|
|
$
|
31.47
|
|
|
|
72,974
|
|
|
$
|
28.91
|
|
|
|
103,340
|
|
|
$
|
25.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense
recognized
|
|
|
|
|
|
$
|
815,000
|
|
|
|
|
|
|
$
|
1,118,000
|
|
|
|
|
|
|
$
|
1,083,000
|
|
|
Fair value of shares vested
in year
|
|
|
|
|
|
$
|
1,197,000
|
|
|
|
|
|
|
$
|
981,000
|
|
|
|
|
|
|
$
|
1,030,000
|
|
Restricted Stock Units Granted to Employees
On April 9, 2006 the Compensation Committee of the Company’s Board of Directors granted 47,425
restricted stock units at a weighted average grant-date fair value of $25.41 per unit to key
employees under the Incentive Plan payable in common shares. Each unit is automatically
converted into one share of common stock on vesting. Vesting occurs from April 10, 2006 through
April 8, 2010, with a weighted average contractual term of stock units outstanding as of
December 31, 2006 of 2.6 years. The fair values of the restricted stock units granted in April
2006 were determined by using a Monte Carlo valuation method.
Presented below is a summary of the status of employees’ restricted stock unit awards for the
year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
Restricted
|
|
|
grant-date
|
|
|
|
|
stock units
|
|
|
fair value
|
|
|
|
|
Outstanding, January 1, 2006
|
|
|
—
|
|
|
$
|
—
|
|
|
Granted
|
|
|
47,425
|
|
|
|
1,205,000
|
|
|
Converted
|
|
|
7,450
|
|
|
|
220,000
|
|
|
Forfeited
|
|
|
1,360
|
|
|
|
33,000
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December, 2006
|
|
|
38,615
|
|
|
$
|
952,000
|
|
|
|
|
|
|
|
|
|
|
Compensation expense recognized in 2006
|
|
|
|
|
|
$
|
427,000
|
|
Stock Performance Awards granted to Executive Officers
The Compensation Committee of the Company’s Board of Directors has approved stock performance
award agreements under the Incentive Plan for the Company’s executive officers. Under these
agreements, the officers could be awarded shares of the Company’s common stock based on the
Company’s total shareholder return relative to that of its peer group of companies in the Edison
Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the
awards are granted. The number of shares earned, if any, will be awarded and issued at the end
of each three-year performance measurement period. The participants have no voting or dividend
rights under these award agreements until the shares are issued at the end of the performance
measurement period. Under APB No. 25 accounting, these awards were valued based on the average
market price of the underlying shares of the Company’s common stock on the award grant date,
multiplied by the estimated probable number of shares to be awarded at the end of the
performance measurement period with compensation expenses recorded ratably over the related
three-year measurement period. Compensation expense recognized was adjusted at each reporting
date subsequent to the grant date of the awards for the difference between the market value of
the underlying shares on their grant date and the market value of the underlying shares on the
reporting date. Under the modified prospective application of SFAS No.123(R) accounting
requirements, the amount of compensation expense that will be recorded subsequent
to January 1, 2006 related to awards granted in 2004 and 2005 and outstanding on December 31,
2006 is based on the estimated grant-date fair value of the awards
as determined under the Black-Scholes option pricing model.
On April 9, 2006 the Compensation Committee of the Company’s Board of Directors granted stock
performance awards to the Company’s executive officers under the Incentive Plan. Under these
awards, the Company’s executive officers could earn up to an aggregate of 88,050 common shares
based on the Company’s total shareholder return relative to the total shareholder return of the
companies that comprise the EEI Index over the performance period of January 1, 2006 through
December 31, 2008. The aggregate target share award is 58,700 shares. Actual payment may range
from zero to 150 percent of the target amount. The executive officers have no voting or dividend
rights related to these shares until the shares, if any, are issued at the end of the
performance period. The amount of compensation expense that will be recorded related to awards
granted in April 2006 and outstanding on December 31, 2006 is based on the estimated grant-date
fair value of the awards as determined under a Monte Carlo valuation method.
The offsetting credit to amounts expensed related to the stock performance awards is included in
common shareholders’ equity. The table below provides a summary of amounts expensed for the
stock performance awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum shares
|
|
Shares used
|
|
|
|
|
|
Expense recognized
|
|
Performance
|
|
subject to
|
|
to estimate
|
|
Fair
|
|
in the year ended
|
|
period
|
|
award
|
|
expense
|
|
Value
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
2004—2006
|
|
|
70,500
|
|
|
|
23,500
|
|
|
$
|
23.90
|
|
|
$
|
187,000
|
|
|
$
|
490,000
|
|
|
|
—
|
|
|
2005—2007
|
|
|
75,150
|
|
|
|
50,872
|
|
|
$
|
22.10
|
|
|
|
375,000
|
|
|
|
453,000
|
|
|
|
—
|
|
|
2006—2008
|
|
|
88,050
|
|
|
|
58,700
|
|
|
$
|
25.95
|
|
|
|
508,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Total
|
|
|
233,700
|
|
|
|
133,072
|
|
|
|
|
|
|
$
|
1,070,000
|
|
|
$
|
943,000
|
|
|
|
—
|
|
|
|
A total of 23,500 shares were earned for the 2004-2006 performance period based on the
Company’s ranking in the EEI Index for total shareholder return during the performance period.
8. Retained Earnings Restriction
The Company’s Articles of Incorporation, as amended, contain
provisions that limit the amount of dividends that may be paid to
common shareholders by the amount of any declared but unpaid dividends
to holders of the Company’s cumulative preferred shares. Under these
provisions none of the Company’s retained earnings were restricted at
December 31, 2006.
9. Commitments and Contingencies
At December 31, 2006 the electric utility had commitments under contracts in connection with
construction programs aggregating approximately $29,232,000. For capacity and energy
requirements, the electric utility has agreements extending through 2011 at annual costs of
approximately $20,485,000 in 2007, $20,089,000 in 2008, $20,051,000 in 2009, $8,499,000 in 2010
and $2,688,000 in 2011.
The electric utility has contracts providing for the purchase and delivery of a significant
portion of its current coal requirements. These contracts expire in 2007 and 2016. In total, the
electric utility is committed to the minimum purchase of approximately $80,515,000 or to make
payments in lieu thereof, under these contracts. The fuel clause adjustment mechanism lessens
the risk of loss from market price changes because it provides for recovery of most fuel costs.
IPH has commitments of approximately $8,800,000 for the purchase of a portion of its 2007 raw
potato supply requirements.
The amounts of future operating lease payments are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
Nonelectric
|
|
|
Total
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
2007
|
|
$
|
2,075
|
|
|
$
|
38,787
|
|
|
$
|
40,862
|
|
|
2008
|
|
|
1,475
|
|
|
|
34,692
|
|
|
|
36,167
|
|
|
2009
|
|
|
1,475
|
|
|
|
31,149
|
|
|
|
32,624
|
|
|
2010
|
|
|
1,475
|
|
|
|
23,058
|
|
|
|
24,533
|
|
|
2011
|
|
|
1,430
|
|
|
|
7,534
|
|
|
|
8,964
|
|
|
Later years
|
|
|
9,931
|
|
|
|
1,262
|
|
|
|
11,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
17,861
|
|
|
$
|
136,482
|
|
|
$
|
154,343
|
|
|
|
|
|
|
|
|
|
|
|
|
The electric future operating lease payments are primarily related to coal rail-car leases. The
nonelectric future operating lease payments are primarily related to medical imaging equipment.
Rent expense from continuing operations was $44,254,000, $37,798,000 and $28,601,000 for 2006,
2005 and 2004, respectively.
The Company occasionally is a party to litigation arising in the normal course of business.
The Company regularly analyzes current information and, as necessary, provides accruals for
liabilities that are probable of occurring and that can be reasonably estimated. The Company
believes the effect on its consolidated results of operations, financial position and cash
flows, if any, for the disposition of all matters pending as of December 31, 2006 will not be
material.
10. Short-Term and Long-Term Borrowings
Short-Term Debt
As of December 31, 2006 the Company had $38.9 million in short-term debt outstanding at a
weighted average interest rate of 5.7%. As of December 31, 2005 the Company had $16 million in
short-term debt outstanding at an interest rate of 4.8%. The average interest rate paid on
short-term debt was 5.8% in 2006 and 3.7% in 2005.
On April 26, 2006 the Company renewed its line of credit with U.S. Bank National Association,
JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Harris Nesbitt Financing,
Inc., Keybank National Association, Union Bank of California, N.A., Bank of America, N.A., Bank
Hapoalim B.M., and Bank of the West and increased the amount available under the line from $100
million to $150 million. The renewed agreement expires on April 26, 2009. The terms of the
renewed line of credit are essentially the same as those in place prior to the renewal. However,
outstanding letters of credit issued by the Company can reduce the amount available for
borrowing under the line by up to $30 million and can increase its commitments under the renewed
line of credit up to $200 million. Borrowings under the line of credit bear interest at LIBOR
plus 0.4%. This line is an unsecured revolving credit facility available to support borrowings
of the Company’s nonelectric operations. The Company’s obligations under this line of credit are
guaranteed by a 100%-owned subsidiary that owns substantially all of the Company’s nonelectric
companies. As of December 31, 2006, $35.0 million of the $150 million line of credit was in use
and $18.3 million was restricted from use to cover outstanding letters of credit.
On September 1, 2006 the Company entered into a separate $25 million line of credit with U.S.
Bank National Association. This line of credit creates an unsecured revolving credit facility
the Company can draw on to support the working capital needs and other capital requirements of
the Company’s electric operations. This line of credit expires on September 1, 2007. Borrowings
under the line of credit bear interest at LIBOR plus 0.4%. The line of credit contains terms
that are substantially the same as those under the $150 million line of credit. As of December
31, 2006, $3.9 million of the $25 million line of credit was in use.
The interest rates under these lines of credit are subject to adjustment in the event of a
change in ratings on the Company’s senior unsecured debt, up to LIBOR plus 1.0% if the ratings
on the Company’s senior unsecured debt fall below BBB- (Standard & Poor’s) and below Baa3
(Moody’s). The Company’s 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.
Long-Term Debt
The Company has the ability to issue up to $256 million of common shares, cumulative preferred shares,
debt and certain other securities from time to time under its universal shelf
registration statement filed with the Securities and Exchange Commission on June 4, 2004 and
declared effective on August 30, 2004. The Company issued no long-term debt under its universal
shelf registration in 2006 or 2005.
On September 24, 2003 the Company borrowed $16.3 million under a loan agreement
with Lombard US Equipment Finance Corporation in the form of an unsecured note. The terms of the
note require quarterly principal payments in the amount of $582,143 commencing in January 2004
with a final installment due on
October 1,
2010. The terms of the note were renegotiated in 2006
and the variable interest rate of three-month LIBOR plus 1.43% on the unpaid principal balance
was replaced with a fixed rate of 6.76% that will be in effect until the note is fully repaid.
Interest payments are due quarterly. The covenants associated with the note are consistent with
existing credit facilities. There are no rating triggers associated with this note.
The Company’s obligations under the 6.63% senior notes are guaranteed by its 100%-owned
subsidiary that owns substantially all of its nonelectric companies. The Company’s Grant County
and Mercer County pollution control refunding revenue bonds and its 5.625% insured senior notes
require that the Company grant to Ambac Assurance Corporation, under a financial guaranty
insurance policy relating to the bonds and notes, a security interest in the assets of the
electric utility if the rating on the Company’s senior unsecured debt is downgraded to Baa2 or
below (Moody’s) or BBB or below (Standard & Poor’s).
In February 2007, the Company entered into a note purchase agreement with Cascade Investment
L.L.C. (Cascade) pursuant to which the Company agreed to issue to Cascade, in a private
placement transaction, $50 million aggregate principal amount of its senior notes due November
30, 2017. Cascade is the Company’s largest shareholder, owning approximately 8.7% of the
Company’s outstanding common stock as of December 31, 2006. The notes are expected to be priced
based on the 10 year US Treasury Forward rate plus 110 basis points, subject to adjustment in
the event certain ratings assigned to the Company’s long-term senior unsecured indebtedness are
downgraded below specific levels prior to the closing of the note purchase. The terms of the
note purchase agreement are substantially similar to the terms of the note purchase agreement
entered into in connection with the issuance of the Company’s $90 million 6.63% senior notes due
December 1, 2011. The closing is expected to occur on December 3, 2007 subject to the
satisfaction of certain conditions to closing, such as, there has been no event or events having
a material adverse effect on the company as a whole, certain senior executives will still be in
their roles, there has been no change in control nor impermissible sale of assets, the
consolidated debt ratio to earnings before interest, taxes, depreciation and amortization as of
September 30, 2007 will be less than 3.5 to 1, certain waivers will have been obtained and
certain other customary conditions of closing will have been satisfied.
The Company has the right to terminate the note purchase agreement by giving at least 30 days’
prior written notice to Cascade and paying a termination fee of $1 million. The proceeds of this
financing will be used to redeem the Company’s $50 million 6.375% senior debentures due December
1, 2007.
The aggregate amounts of maturities on bonds outstanding and other long-term obligations at
December 31, 2006 for each of the next five years are $54,909,000 for 2007, $3,017,000 for 2008,
$2,917,000 for 2009, $2,600,000 for 2010 and $90,114,000 for 2011.
Covenants
The Company’s lines of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance
note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60%
and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also
require that priority debt not be in excess of 20% of total capitalization. The Company was in
compliance with all of the covenants under its financing agreements as of December 31, 2006.
11. Cumulative Preferred Shares and Class B Stock Options of Subsidiary
Cumulative Preferred Shares
All four series of cumulative preferred shares are redeemable at the option of the Company. As
of December 31, 2006 the call price by series is:
|
|
|
|
|
|
|
Series outstanding
|
|
Call price
|
|
|
|
$3.60, 60,000 shares
|
|
$
|
102.25
|
|
|
$4.40, 25,000 shares
|
|
$
|
102.00
|
|
|
$4.65, 30,000 shares
|
|
$
|
101.50
|
|
|
$6.75, 40,000 shares
|
|
$
|
102.3625
|
|
Class B Stock Options of Subsidiary
In connection with the acquisition of IPH in August 2004, IPH management and certain other
employees elected to retain stock options for the purchase of 1,112 IPH Class B common shares
valued at $1.8 million. The options are exercisable at any time and the option holder must
deliver cash to exercise the option. Once the options are exercised for Class B shares, the
Class B shareholder cannot put the shares back to the Company for 181 days. At that time, the
Class B common shares are redeemable at any time during the employment of the individual holder,
subject to certain limits on the total number of Class B common shares redeemable on an annual
basis. The Class B common shares are nonvoting, except in the event of a merger, and do not
participate in dividends but have liquidation rights at par with the Class A common shares owned
by the Company. The value of the Class B common shares issued on exercise of the options
represents an interest in IPH that changes as defined in the agreement. In 2005, options for 357
IPH Class B common shares were exercised and the Class B common shares were redeemed by IPH 181
days after issuance.
In 2006, IPH granted 305 additional options to purchase IPH Class B Common Stock to five
employees at an exercise price of $2,085.88 per option. The options vested immediately on
issuance. On the date the options were granted the value of a share of IPH Class B common stock
was estimated to be $1,041.71. Therefore, the grant-date fair value of the options was $0 and no
expense or liability was recorded related to these options under SFAS No. 123(R). Also in 2006,
2 options were forfeited. As of December 31, 2006 there were 1,058 options outstanding with a
combined exercise price of $952,000, of which 753 options were “in-the-money” with a combined
exercise price of $316,000.
12. Pension Plan and Other Postretirement Benefits
The following footnote reflects the adoption of SFAS No. 158,
Accounting for Defined Benefit
Pension and Other Postretirement Plans,
in December 2006. The Company determined that the
balance of unrecognized net actuarial losses, prior service costs and the SFAS No. 106
transition obligation related to regulated utility activities would be subject to recovery
through rates as those balances are amortized to expense and the related benefits are earned.
Therefore, the Company charged those unrecognized amounts to regulatory asset accounts under
SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation
, rather than to
Accumulated other comprehensive losses in equity as prescribed by SFAS No. 158.
Effective July 1, 2005 the Company remeasured its pension and other postretirement benefit plan
obligations using the RP-2000 Combined Healthy Mortality table in place of the 1983 Group
Annuity Mortality table (GAM ‘83) it used to measure its obligations and determine its annual
costs under these plans in January 2005. The reason for the remeasurement was to update the
mortality table to more accurately reflect current life expectancies of current employees and
retirees included in the plans. Generally accepted accounting principles require that all
assumptions used to measure plan obligations and determine annual plan costs be revised as of a
remeasurement date. The following actuarial assumptions were updated as of the July 1, 2005
remeasurement date:
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2005 through
|
|
July 1, 2005 through
|
|
Key assumptions and data
|
|
June 30, 2005
|
|
December 31, 2005
|
|
Discount rate
|
|
|
6.00%
|
|
|
|
5.25%
|
|
|
Long-term rate of return on plan assets
|
|
|
8.50%
|
|
|
|
8.50%
|
|
|
Social Security wage base
|
|
|
4.00%
|
|
|
|
3.50%
|
|
|
Rate of inflation
|
|
|
3.00%
|
|
|
|
2.50%
|
|
|
Rate of withdrawal
|
|
1% per year through age 54
|
|
2% per year through age 54
|
|
Mortality table
|
|
GAM ‘83
|
|
RP-2000 projected to 2006
|
|
Market value of assets — beginning of period
|
|
$
|
141,685,000
|
|
|
$
|
142,547,832
|
|
Remeasuring the Company’s pension and other postretirement benefit plan obligations as of July
1, 2005 under the revised assumptions had the effect of increasing the Company’s 2005 projected
pension plan costs by $1,364,000, increasing its 2005 projected Executive Survivor and
Supplemental Retirement Plan costs by $123,000 and increasing its 2005 projected costs for
postretirement benefits other than pensions by $137,000.
Pension Plan
The Company’s noncontributory funded pension plan covers substantially all electric utility and
corporate employees hired prior to January 1, 2006. The plan provides 100% vesting after five
vesting years of service and for retirement compensation at age 65, with reduced compensation in
cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but
no change or discontinuance may affect the pensions theretofore vested. The Company’s policy is
to fund pension costs accrued. All past service costs have been provided for.
The pension plan has a trustee who is responsible for pension payments to retirees. Four
investment managers are responsible for managing the plan’s assets. An independent actuary
performs the necessary actuarial valuations for the plan.
The plan assets consist of common stock and bonds of public companies, U.S. government
securities, cash and cash equivalents. None of the plan assets are invested in common stock,
preferred stock or debt securities of the Company.
Components of net periodic pension benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost—benefit earned during the period
|
|
$
|
5,057
|
|
|
$
|
4,695
|
|
|
$
|
4,063
|
|
|
Interest cost on projected benefit obligation
|
|
|
10,435
|
|
|
|
9,721
|
|
|
|
9,458
|
|
|
Expected return on assets
|
|
|
(12,288
|
)
|
|
|
(12,071
|
)
|
|
|
(12,438
|
)
|
|
Amortization of prior-service cost
|
|
|
742
|
|
|
|
726
|
|
|
|
897
|
|
|
Amortization of net actuarial loss
|
|
|
1,844
|
|
|
|
1,364
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
5,790
|
|
|
$
|
4,435
|
|
|
$
|
1,980
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents amounts recognized in the consolidated balance sheets as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid pension cost
|
|
$
|
—
|
|
|
$
|
9,795
|
|
|
Current liability
|
|
|
—
|
|
|
|
—
|
|
|
Noncurrent liability
|
|
|
(19,252
|
)
|
|
|
—
|
|
|
Additional minimum liability
|
|
|
—
|
|
|
|
(13,380
|
)
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(19,252
|
)
|
|
$
|
(3,585
|
)
|
|
|
|
|
|
|
|
|
Net amount recognized as of December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
Unrecognized prior service cost
|
|
$
|
(4,748
|
)
|
|
$
|
—
|
|
|
Unrecognized actuarial loss
|
|
|
(21,771
|
)
|
|
|
—
|
|
|
Accumulated other comprehensive loss
|
|
|
(738
|
)
|
|
|
(7,757
|
)
|
|
Prepaid pension cost
|
|
|
8,005
|
|
|
|
9,795
|
|
|
Intangible asset
|
|
|
—
|
|
|
|
(5,623
|
)
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(19,252
|
)
|
|
$
|
(3,585
|
)
|
|
|
|
|
|
|
|
|
Change in regulatory assets and accumulated comprehensive loss due to SFAS No. 158:
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
|
|
|
|
|
|
Increase in regulatory assets:
|
|
|
|
|
|
Unrecognized actuarial loss
|
|
$
|
21,771
|
|
|
Unrecognized prior service cost
|
|
|
4,748
|
|
|
Increase in accumulated
other comprehensive loss:
|
|
|
|
|
|
Unrecognized actuarial loss
|
|
|
606
|
|
|
Unrecognized prior service cost
|
|
|
132
|
|
|
|
|
|
|
|
Total change
|
|
$
|
27,257
|
|
|
|
|
|
|
Funded status as of December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets
|
|
$
|
167,508
|
|
|
$
|
146,982
|
|
|
Projected benefit obligation
|
|
|
(186,760
|
)
|
|
|
(181,587
|
)
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
$
|
(19,252
|
)
|
|
$
|
(34,605
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated benefit obligation
|
|
$
|
(153,816
|
)
|
|
$
|
(150,567
|
)
|
|
|
|
|
|
|
|
|
The following tables provide a reconciliation of the changes in the fair value of plan assets
and the plan’s benefit obligations and prepaid pension cost over the two-year period ended
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
$
|
146,982
|
|
|
$
|
141,685
|
|
|
Actual return on plan assets
|
|
|
24,856
|
|
|
|
9,864
|
|
|
Discretionary company contributions
|
|
|
4,000
|
|
|
|
4,000
|
|
|
Benefit payments
|
|
|
(8,330
|
)
|
|
|
(8,567
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
$
|
167,508
|
|
|
$
|
146,982
|
|
|
|
|
|
|
|
|
|
|
Estimated asset return
|
|
|
17.24
|
%
|
|
|
7.08
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at January 1
|
|
$
|
181,587
|
|
|
$
|
166,190
|
|
|
Service cost
|
|
|
5,057
|
|
|
|
4,695
|
|
|
Interest cost
|
|
|
10,435
|
|
|
|
9,721
|
|
|
Benefit payments
|
|
|
(8,330
|
)
|
|
|
(8,567
|
)
|
|
Plan amendments
|
|
|
—
|
|
|
|
222
|
|
|
Actuarial (gain) loss
|
|
|
(1,989
|
)
|
|
|
9,326
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at December 31
|
|
$
|
186,760
|
|
|
$
|
181,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of prepaid pension cost:
|
|
|
|
|
|
|
|
|
|
Prepaid pension cost at January 1
|
|
$
|
9,795
|
|
|
$
|
10,230
|
|
|
Net periodic pension cost
|
|
|
(5,790
|
)
|
|
|
(4,435
|
)
|
|
Discretionary company contributions
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
Prepaid pension cost at December 31
|
|
$
|
8,005
|
|
|
$
|
9,795
|
|
|
|
|
|
|
|
|
|
Weighted-average assumptions used to determine benefit obligations at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
Rate of increase in future compensation level
|
|
|
3.75
|
%
|
|
|
3.75
|
%
|
Weighted-average assumptions used to determine net periodic pension cost for the year ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
Discount rate (2005 is remeasurement composite rate)
|
|
|
5.75
|
%
|
|
|
5.625
|
%
|
|
Long-term rate of return on plan assets
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
|
Rate of increase in future compensation level
|
|
|
3.75
|
%
|
|
|
3.75
|
%
|
To develop the expected long-term rate of return on assets assumption, the Company considered
the historical returns and the future expectations for returns for each asset class, as well as
the target asset allocation of the pension portfolio.
Market-related
value of plan assets:
The Company’s expected return on plan assets is determined based on the expected long-term rate
of return on plan assets and the market-related value of plan assets.
The Company bases actuarial determination of pension plan expense or income on a market-related
valuation of assets, which reduces year-to-year volatility. This market-related valuation
calculation recognizes investment gains or losses over a five-year period from the year in which
they occur. Investment gains or losses for this purpose are the difference between the expected
return calculated using the market-related value of assets and the actual return based on the
fair value of assets. Since the market-related valuation calculation recognizes gain or losses
over a five-year period, the future value of the market-related assets will be impacted as
previously deferred gains or losses are recognized.
The assumed rate of return on pension fund assets for the determination of 2007 net periodic
pension cost is 8.50%.
|
|
|
|
|
|
|
Measurement dates:
|
|
2006
|
|
2005
|
|
Net periodic pension cost
|
|
January 1, 2006
|
|
January 1, 2005 & July 1, 2005
|
|
|
|
|
|
|
|
End of year benefit obligations
|
|
January 1, 2006
projected to
December 31, 2006
|
|
January 1, 2005
projected to
December 31, 2005
|
|
|
|
|
|
|
|
Market value of assets
|
|
December 31, 2006
|
|
December 31, 2005
|
The estimated amounts of unrecognized net actuarial losses and prior service costs to be
amortized from regulatory assets and accumulated other comprehensive loss into the net periodic
pension cost in 2007 are:
|
|
|
|
|
|
|
(in thousands)
|
|
2007
|
|
|
|
|
|
|
|
|
Decrease in regulatory assets:
|
|
|
|
|
|
Amortization of unrecognized actuarial loss
|
|
$
|
1,751
|
|
|
Amortization of unrecognized prior service cost
|
|
|
722
|
|
|
Decrease in accumulated other comprehensive loss:
|
|
|
|
|
|
Amortization of unrecognized actuarial loss
|
|
|
49
|
|
|
Amortization of unrecognized prior service cost
|
|
|
20
|
|
|
|
|
|
|
|
Total estimated amortization
|
|
$
|
2,542
|
|
|
|
|
|
|
Cash flows
: The Company is not required to make a contribution to the pension plan in
2007 but can contribute up to $79 million before September 15, 2007 and deduct it for the 2006
plan year.
The following benefit payments, which reflect expected future service, as appropriate, are
expected to be paid out from plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
|
|
(in thousands)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012—2016
|
|
|
|
$
|
8,735
|
|
|
$
|
8,901
|
|
|
$
|
9,072
|
|
|
$
|
9,248
|
|
|
$
|
9,644
|
|
|
$
|
56,411
|
|
The Company’s pension plan asset allocations at December 31, 2006 and 2005, by asset category
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Asset Allocation
|
|
2006
|
|
2005
|
|
Large capitalization equity securities
|
|
|
49.3
|
%
|
|
|
51.2
|
%
|
|
Small capitalization equity securities
|
|
|
11.6
|
%
|
|
|
11.4
|
%
|
|
International equity securities
|
|
|
10.6
|
%
|
|
|
9.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
71.5
|
%
|
|
|
72.4
|
%
|
|
Cash and fixed-income securities
|
|
|
28.5
|
%
|
|
|
27.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
The following objectives guide the investment strategy of the Company’s pension plan (the Plan).
|
|
•
|
|
The Plan is managed to operate in perpetuity.
|
|
|
|
|
•
|
|
The Plan will meet the pension benefit obligation payments of Otter Tail Corporation.
|
|
|
|
|
•
|
|
The Plan’s assets should be invested with the objective of meeting current and future
payment requirements while minimizing annual contributions and their volatility.
|
|
|
|
|
•
|
|
The asset strategy reflects the desire to meet current and future benefit payments
while considering a prudent level of risk and diversification.
|
The asset allocation strategy developed by the Company’s Retirement Plans Administrative
Committee is based on the current needs of the Plan, the investment objectives listed above, the
investment preferences and risk tolerance of the committee and a desired degree of
diversification.
The asset allocation strategy contains guideline percentages, at market value, of the total Plan
invested in various asset classes. The strategic target allocation shown in the table that
follows is a guide that will at times not be reflected in actual asset allocations that may be
dictated by prevailing market conditions, independent actions of the Retirement Plans
Administrative Committee and/or investment managers, and required cash flows to and from the
Plan. The tactical range provides flexibility for the investment managers’ portfolios to vary
around the target allocation without the need for immediate rebalancing. The Company’s
Retirement Plans Administrative Committee monitors actual asset allocations and directs
contributions and withdrawals toward maintaining the targeted allocation percentages listed in
the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
Strategic
|
|
Tactical
|
|
Asset Allocation
|
|
Target
|
|
Range
|
|
Large capitalization equity securities
|
|
|
48
|
%
|
|
|
40%—55
|
%
|
|
Small capitalization equity securities
|
|
|
12
|
%
|
|
|
9%—15
|
%
|
|
International equity securities
|
|
|
10
|
%
|
|
|
5%—15
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Total equity securities
|
|
|
70
|
%
|
|
|
60%—80
|
%
|
|
Fixed-income securities
|
|
|
30
|
%
|
|
|
20%—40
|
%
|
Executive Survivor and Supplemental Retirement Plan (ESSRP)
The ESSRP is an unfunded, nonqualified benefit plan for executive officers and certain key
management employees. The ESSRP provides defined benefit payments to these employees on their
retirements for life or to their beneficiaries on their deaths for a 15-year postretirement
period. Life insurance carried on certain plan participants is payable to the Company on the
employee’s death. There are no plan assets in this nonqualified benefit plan due to the nature
of the plan.
On January 31, 2005 the Board of Directors of the Company amended and restated the ESSRP to
reduce future benefits effective January 1, 2005, which resulted in reduced expense to the
Company. Effective January 1, 2005 new participants in the ESSRP accrue benefits under a new
formula. The new formula is the same as the formula used under the Company’s qualified defined
benefit pension plan but includes bonuses in the computation of covered compensation and is not
subject to statutory compensation and benefit limits. Individuals who became participants in the
ESSRP before January 1, 2005 will receive the greater of the old formula or the new formula
until December 31, 2010. On December 31, 2010, their benefit under the old formula will be
frozen. After 2010, they will receive the greater of their frozen December 31, 2010 benefit or
their benefit calculated under the new formula. The amendments to the ESSRP also provide for
increased service credits for certain participants and eliminate certain distribution features.
On December 19, 2006 the Board of Directors of the Company approved an amendment to the ESSRP
effective January 1, 2006. The Amendment amends the ESSRP to provide that for each of the
Company’s Chief Executive Officer and Corporate Secretary, the “Normal Retirement Benefit” (as
defined in the ESSRP) will be determined based on “Final Average Earnings” rather than “Final
Annual Salary” (defined as the base Salary (as defined in the ESSRP) and annual bonus paid to
the participant during the 12 months prior to termination or death). The ESSRP defines “Final
Average Earnings” as the average of the participant’s total cash payments (Salary (as defined in
the ESSRP) and annual incentive bonus) paid
during the highest consecutive 42 months in the 10
years prior to the date as of which the Final Average Earnings are determined.
Components of net periodic pension benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost—benefit earned during the period
|
|
$
|
426
|
|
|
$
|
406
|
|
|
$
|
820
|
|
|
Interest cost on projected benefit obligation
|
|
|
1,303
|
|
|
|
1,267
|
|
|
|
1,489
|
|
|
Amortization of prior-service cost
|
|
|
71
|
|
|
|
71
|
|
|
|
147
|
|
|
Recognized net actuarial loss
|
|
|
473
|
|
|
|
498
|
|
|
|
680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,273
|
|
|
$
|
2,242
|
|
|
$
|
3,136
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents amounts recognized in the consolidated balance sheets as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
Unrecognized net actuarial loss
|
|
$
|
5,796
|
|
|
$
|
—
|
|
|
Unrecognized prior service cost
|
|
|
496
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total regulatory asset
|
|
|
6,292
|
|
|
|
—
|
|
|
Intangible asset
|
|
|
|
|
|
|
891
|
|
|
Projected benefit obligation liability
|
|
|
(24,783
|
)
|
|
|
|
|
|
Accumulated benefit obligation liability
|
|
|
|
|
|
|
(19,631
|
)
|
|
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
Unrecognized net actuarial loss
|
|
|
3,162
|
|
|
|
|
|
|
Unrecognized prior service cost
|
|
|
271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accumulated other comprehensive loss
|
|
|
3,433
|
|
|
|
4,831
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(15,058
|
)
|
|
$
|
(13,909
|
)
|
|
|
|
|
|
|
|
|
Additional information for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation
|
|
$
|
24,783
|
|
|
$
|
23,271
|
|
|
Accumulated benefit obligation
|
|
|
21,317
|
|
|
|
19,631
|
|
|
Increase in regulatory asset — unrecognized costs
|
|
|
6,292
|
|
|
|
—
|
|
|
Change in comprehensive loss — unrecognized costs
|
|
|
3,433
|
|
|
|
—
|
|
|
Change in minimum liability in comprehensive loss
|
|
|
(4,831
|
)
|
|
|
409
|
|
Incremental effect of applying SFAS No. 158 to individual balance sheet line items as of
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
|
|
|
|
|
|
After
|
|
(in thousands)
|
|
SFAS No. 158
|
|
Adjustments
|
|
SFAS No. 158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible asset
|
|
$
|
767
|
|
|
$
|
(767
|
)
|
|
$
|
—
|
|
|
Regulatory assets
|
|
|
—
|
|
|
|
6,292
|
|
|
|
6,292
|
|
|
Liability for pension benefits
|
|
|
21,317
|
|
|
|
3,466
|
|
|
|
24,783
|
|
|
Accumulated other comprehensive loss
|
|
|
5,492
|
|
|
|
(2,059
|
)
|
|
|
3,433
|
|
The following tables provide a reconciliation of the changes in the fair value of plan assets
and the plan’s projected benefit obligations over the two-year period ended December 31, 2006
and a statement of the funded status as of December 31 of both years:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Actual return on plan assets
|
|
|
—
|
|
|
|
—
|
|
|
Employer contributions
|
|
|
1,124
|
|
|
|
1,094
|
|
|
Benefit payments
|
|
|
(1,124
|
)
|
|
|
(1,094
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at January 1
|
|
$
|
23,271
|
|
|
$
|
23,123
|
|
|
Service cost
|
|
|
426
|
|
|
|
406
|
|
|
Interest cost
|
|
|
1,303
|
|
|
|
1,267
|
|
|
Benefit payments
|
|
|
(1,124
|
)
|
|
|
(1,094
|
)
|
|
Plan amendments
|
|
|
(53
|
)
|
|
|
(663
|
)
|
|
Actuarial loss
|
|
|
960
|
|
|
|
232
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at December 31
|
|
$
|
24,783
|
|
|
$
|
23,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of funded status:
|
|
|
|
|
|
|
|
|
|
Funded status at December 31
|
|
$
|
(24,783
|
)
|
|
$
|
(23,271
|
)
|
|
Unrecognized net actuarial loss
|
|
|
8,958
|
|
|
|
8,471
|
|
|
Unrecognized prior service cost
|
|
|
767
|
|
|
|
891
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(15,058
|
)
|
|
$
|
(13,909
|
)
|
|
|
|
|
|
|
|
|
Weighted-average assumptions used to determine benefit obligations at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
Rate of increase in future compensation level
|
|
|
4.71
|
%
|
|
|
4.69
|
%
|
Weighted-average assumptions used to determine net periodic pension cost for the year ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Discount rate (2005 is remeasurement composite rate)
|
|
|
5.75
|
%
|
|
|
5.625
|
%
|
|
Rate of increase in future compensation level
|
|
|
4.69
|
%
|
|
|
4.69
|
%
|
The estimated amounts of unrecognized net actuarial losses and prior service costs to be
amortized from regulatory assets and accumulated other comprehensive loss into the net periodic
pension cost for the ESSRP in 2007 are:
|
|
|
|
|
|
|
(in thousands)
|
|
2007
|
|
|
-
|
|
|
|
|
|
|
|
Decrease in regulatory assets:
|
|
|
|
|
|
Amortization of unrecognized actuarial loss
|
|
$
|
349
|
|
|
Amortization of unrecognized prior service cost
|
|
|
43
|
|
|
Decrease in accumulated other comprehensive loss:
|
|
|
|
|
|
Amortization of unrecognized actuarial loss
|
|
|
191
|
|
|
Amortization of unrecognized prior service cost
|
|
|
24
|
|
|
|
|
|
|
|
Total estimated amortization
|
|
$
|
607
|
|
|
|
|
|
|
Cash flows:
The ESSRP is unfunded and has no assets; contributions are equal to the
benefits paid to plan participants. The following benefit payments, which reflect future
service, as appropriate, are expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
|
|
(in thousands)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012—2016
|
|
|
|
|
|
|
$1,121
|
|
|
|
$1,105
|
|
|
|
$1,113
|
|
|
|
$1,111
|
|
|
|
$1,202
|
|
|
|
$6,600
|
|
Other Postretirement Benefits
The Company provides a portion of health insurance and life insurance benefits for retired
electric utility and corporate employees. Substantially all of the Company’s electric utility
and corporate employees may become eligible for health insurance benefits if they reach age 55
and have 10 years of service. On adoption of SFAS No. 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.
During the third quarter of 2004, the Company adopted FASB Staff Position No. FAS 106-2 (FSP
106-2),
Accounting and Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003
retroactive to the beginning of 2004. The Company and
its actuarial advisors determined that the expected federal subsidy reduced the Company’s
accumulated postretirement benefit obligation (APBO) at January 1, 2004 by $4,935,000 and
reduced its net periodic benefit cost for 2004 by $757,000. The APBO reduction was accounted for
as an actuarial experience gain in accordance with the guidance in SFAS No. 106 and was not
included as a reduction to the net periodic benefit cost in 2004.
Components of net periodic postretirement benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost—benefit earned during the period
|
|
$
|
1,319
|
|
|
$
|
1,307
|
|
|
$
|
1,170
|
|
|
Interest cost on projected benefit obligation
|
|
|
2,556
|
|
|
|
2,480
|
|
|
|
2,580
|
|
|
Amortization of transition obligation
|
|
|
748
|
|
|
|
748
|
|
|
|
748
|
|
|
Amortization of prior-service cost
|
|
|
(305
|
)
|
|
|
(305
|
)
|
|
|
(305
|
)
|
|
Amortization of net actuarial loss
|
|
|
556
|
|
|
|
742
|
|
|
|
702
|
|
|
Expense decrease due to Medicare Part D subsidy
|
|
|
(1,543
|
)
|
|
|
(1,251
|
)
|
|
|
(757
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement benefit cost
|
|
$
|
3,331
|
|
|
$
|
3,721
|
|
|
$
|
4,138
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents amounts recognized in the consolidated balance sheets as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory asset:
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation
|
|
$
|
4,414
|
|
|
$
|
—
|
|
|
Unrecognized net actuarial gain
|
|
|
(2,077
|
)
|
|
|
—
|
|
|
Unrecognized prior service cost
|
|
|
1,588
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Net regulatory asset
|
|
|
3,925
|
|
|
|
—
|
|
|
Projected benefit obligation liability
|
|
|
(32,254
|
)
|
|
|
|
|
|
Benefit obligation liability
|
|
|
|
|
|
|
(26,982
|
)
|
|
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation
|
|
|
75
|
|
|
|
|
|
|
Unrecognized net actuarial gain
|
|
|
(35
|
)
|
|
|
|
|
|
Unrecognized prior service cost
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
|
|
|
67
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(28,262
|
)
|
|
$
|
(26,982
|
)
|
|
|
|
|
|
|
|
|
Change
in regulatory assets and accumulated comprehensive loss due to SFAS No. 158:
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Increase in regulatory asset — net:
|
|
|
|
|
|
Unrecognized transition obligation
|
|
$
|
4,414
|
|
|
Unrecognized net actuarial gain
|
|
|
(2,077
|
)
|
|
Unrecognized prior service cost
|
|
|
1,588
|
|
|
|
|
|
|
|
Net regulatory asset
|
|
|
3,925
|
|
|
Increase in accumulated other comprehensive loss:
|
|
|
|
|
|
Unrecognized transition obligation
|
|
|
75
|
|
|
Unrecognized net actuarial gain
|
|
|
(35
|
)
|
|
Unrecognized prior service cost
|
|
|
27
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
|
|
|
67
|
|
|
|
|
|
|
|
Total change
|
|
$
|
3,992
|
|
|
|
|
|
|
The following tables provide a reconciliation of the changes in the fair value of
plan assets and the plan’s projected benefit obligations and accrued postretirement benefit cost
over the two-year period ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Actual return on plan assets
|
|
|
—
|
|
|
|
—
|
|
|
Company contributions
|
|
|
2,051
|
|
|
|
1,792
|
|
|
Benefit payments (net of Medicare Part D subsidy)
|
|
|
(3,625
|
)
|
|
|
(3,112
|
)
|
|
Participant premium payments
|
|
|
1,574
|
|
|
|
1,320
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at January 1
|
|
$
|
36,757
|
|
|
$
|
39,639
|
|
|
Service cost (net of Medicare Part D subsidy)
|
|
|
1,110
|
|
|
|
1,172
|
|
|
Interest cost (net of Medicare Part D subsidy)
|
|
|
1,779
|
|
|
|
1,998
|
|
|
Benefit payments (net of Medicare Part D subsidy)
|
|
|
(3,625
|
)
|
|
|
(3,112
|
)
|
|
Participant premium payments
|
|
|
1,574
|
|
|
|
1,320
|
|
|
Actuarial gain
|
|
|
(5,341
|
)
|
|
|
(4,260
|
)
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at December 31
|
|
$
|
32,254
|
|
|
$
|
36,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of accrued postretirement cost:
|
|
|
|
|
|
|
|
|
|
Accrued postretirement cost at January 1
|
|
$
|
(26,982
|
)
|
|
$
|
(25,053
|
)
|
|
Expense
|
|
|
(3,331
|
)
|
|
|
(3,721
|
)
|
|
Net company contribution
|
|
|
2,051
|
|
|
|
1,792
|
|
|
|
|
|
|
|
|
|
|
Accrued postretirement cost at December 31
|
|
$
|
(28,262
|
)
|
|
$
|
(26,982
|
)
|
|
|
|
|
|
|
|
|
Weighted-average assumptions used to determine benefit obligations at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
Weighted-average assumptions used to determine net periodic postretirement benefit cost for the
year ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Discount rate (2005 is remeasurement composite rate)
|
|
|
5.75
|
%
|
|
|
5.625
|
%
|
Assumed healthcare cost-trend rates as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Healthcare cost-trend rate assumed for next year pre-65
|
|
|
9.00
|
%
|
|
|
9.00
|
%
|
|
Healthcare cost-trend rate assumed for next year post-65
|
|
|
10.00
|
%
|
|
|
9.00
|
%
|
|
Rate at which the cost-trend rate is assumed to decline
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
Year the rate reaches the ultimate trend rate
|
|
|
2012
|
|
|
|
2010
|
%
|
Assumed healthcare cost-trend rates have a significant effect on the amounts reported for
healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2006
would have the following effects:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
1 point increase
|
|
|
1 point decrease
|
|
|
|
|
Effect on total of service and interest cost
|
|
$
|
433
|
|
|
$
|
(350
|
)
|
|
Effect on the postretirement benefit obligation
|
|
$
|
2,926
|
|
|
$
|
(2,691
|
)
|
|
|
|
|
|
|
|
Measurement dates:
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement
|
|
January 1, 2006
|
|
January 1, 2005 &
|
|
benefit cost
|
|
|
|
July 1, 2005
|
|
|
|
|
|
|
|
End of year benefit obligations
|
|
January 1, 2006
|
|
January 1, 2005
|
|
|
|
projected to
|
|
projected to
|
|
|
|
December 31, 2006
|
|
December 31, 2005
|
The estimated net amounts of unrecognized transition obligation and prior service costs to be
amortized from regulatory assets and accumulated other comprehensive loss into the net periodic
postretirement benefit cost in 2007 are:
|
|
|
|
|
|
|
(in thousands)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Decrease in regulatory assets:
|
|
|
|
|
|
Amortization of transition obligation
|
|
$
|
735
|
|
|
Accumulation of unrecognized prior service cost
|
|
|
(203
|
)
|
|
Decrease in accumulated other comprehensive loss:
|
|
|
|
|
|
Amortization of transition obligation
|
|
|
13
|
|
|
Accumulation of unrecognized prior service cost
|
|
|
(3
|
)
|
|
|
|
|
|
|
Total estimated amortization
|
|
$
|
542
|
|
|
|
|
|
|
Cash flows:
The Company expects to contribute $2.4 million net of expected employee
contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts
in 2007. The following benefit payments, which reflect expected future service, as appropriate,
are expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
|
|
(in thousands)
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012-2016
|
|
|
|
|
|
$
|
2,391
|
|
|
$
|
2,357
|
|
|
$
|
2,431
|
|
|
$
|
2,433
|
|
|
$
|
2,564
|
|
|
$
|
13,895
|
|
The Company expects to receive a Medicare Part D subsidy from the Federal government of
approximately $439,000 in 2007.
Leveraged Employee Stock Ownership Plan
The Company has a leveraged employee stock ownership plan for the benefit of all its electric
utility employees. Contributions made by the Company were $738,000 for 2006, $830,000 for 2005
and $930,000 for 2004.
13. 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.
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 $10.4 million of the
Company’s long-term debt, which is subject to variable interest rates, approximates fair value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
December 31, 2005
|
|
|
|
(in thousands)
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
|
Amount
|
|
value
|
|
amount
|
|
value
|
|
Cash and short-term investments
|
|
$
|
6,791
|
|
|
$
|
6,791
|
|
|
$
|
5,430
|
|
|
$
|
5,430
|
|
|
Other investments
|
|
|
8,955
|
|
|
|
8,955
|
|
|
|
8,702
|
|
|
|
8,702
|
|
|
Long-term debt
|
|
|
(255,436
|
)
|
|
|
(265,547
|
)
|
|
|
(258,260
|
)
|
|
|
(273,456
|
)
|
14. Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric plant
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
360,304
|
|
|
$
|
357,285
|
|
|
Transmission
|
|
|
189,683
|
|
|
|
182,502
|
|
|
Distribution
|
|
|
307,825
|
|
|
|
296,301
|
|
|
General
|
|
|
72,877
|
|
|
|
74,678
|
|
|
|
|
|
|
|
|
|
|
Electric plant
|
|
|
930,689
|
|
|
|
910,766
|
|
|
Less accumulated depreciation and amortization
|
|
|
388,254
|
|
|
|
374,786
|
|
|
|
|
|
|
|
|
|
|
Electric plant net of accumulated depreciation
|
|
|
542,435
|
|
|
|
535,980
|
|
|
Construction work in progress
|
|
|
18,503
|
|
|
|
12,449
|
|
|
|
|
|
|
|
|
|
|
Net electric plant
|
|
$
|
560,938
|
|
|
$
|
548,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonelectric operations plant
|
|
$
|
239,269
|
|
|
$
|
228,548
|
|
|
Less accumulated depreciation and amortization
|
|
|
91,303
|
|
|
|
84,652
|
|
|
|
|
|
|
|
|
|
|
Nonelectric plant net of accumulated depreciation
|
|
|
147,966
|
|
|
|
143,896
|
|
|
Construction work in progress
|
|
|
9,705
|
|
|
|
4,766
|
|
|
|
|
|
|
|
|
|
|
Net nonelectric operations plant
|
|
$
|
157,671
|
|
|
$
|
148,662
|
|
|
|
|
|
|
|
|
|
|
Net plant
|
|
$
|
718,609
|
|
|
$
|
697,091
|
|
|
|
|
|
|
|
|
|
The estimated service lives for rate-regulated properties is 5 to 65 years. For nonelectric
property the estimated useful lives are from 3 to 40 years.
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Life Range
|
|
(years)
|
|
Low
|
|
High
|
|
|
|
Electric fixed assets:
|
|
|
|
|
|
|
|
|
|
Production plant
|
|
|
34
|
|
|
|
62
|
|
|
Transmission plant
|
|
|
40
|
|
|
|
55
|
|
|
Distribution plant
|
|
|
15
|
|
|
|
55
|
|
|
General plant
|
|
|
5
|
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonelectric fixed assets
|
|
|
3
|
|
|
|
40
|
|
15. Income Taxes
The total income tax expense differs from the amount computed by applying the federal income tax
rate (35% in 2006, 2005 and 2004) to net income before total income tax expense for the
following reasons:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
(in thousands)
|
|
|
Tax computed at federal statutory rate
|
|
$
|
27,232
|
|
|
$
|
28,325
|
|
|
$
|
20,253
|
|
|
Increases (decreases) in tax from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income taxes net of
federal income tax benefit
|
|
|
2,261
|
|
|
|
1,906
|
|
|
|
1,808
|
|
|
Investment tax credit amortization
|
|
|
(1,146
|
)
|
|
|
(1,151
|
)
|
|
|
(1,152
|
)
|
|
Differences reversing in excess of federal rates
|
|
|
1,271
|
|
|
|
(15
|
)
|
|
|
(136
|
)
|
|
Dividend received/paid deduction
|
|
|
(718
|
)
|
|
|
(703
|
)
|
|
|
(703
|
)
|
|
Affordable housing tax credits
|
|
|
(839
|
)
|
|
|
(1,324
|
)
|
|
|
(1,418
|
)
|
|
Permanent and other differences
|
|
|
(955
|
)
|
|
|
969
|
|
|
|
(1,286
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
27,106
|
|
|
$
|
28,007
|
|
|
$
|
17,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense — discontinued operations
|
|
$
|
252
|
|
|
$
|
5,570
|
|
|
$
|
1,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overall effective federal and state income tax rate
|
|
|
34.9
|
%
|
|
|
34.9
|
%
|
|
|
30.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current federal income taxes
|
|
$
|
26,276
|
|
|
$
|
32,795
|
|
|
$
|
15,228
|
|
|
Current state income taxes
|
|
|
4,232
|
|
|
|
5,265
|
|
|
|
2,913
|
|
|
Deferred federal income taxes
|
|
|
(937
|
)
|
|
|
(7,112
|
)
|
|
|
1,776
|
|
|
Deferred state income taxes
|
|
|
(189
|
)
|
|
|
(899
|
)
|
|
|
194
|
|
|
Affordable housing tax credits
|
|
|
(839
|
)
|
|
|
(1,324
|
)
|
|
|
(1,418
|
)
|
|
Investment tax credit amortization
|
|
|
(1,146
|
)
|
|
|
(1,151
|
)
|
|
|
(1,152
|
)
|
|
Foreign income taxes
|
|
|
(291
|
)
|
|
|
433
|
|
|
|
(175
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
27,106
|
|
|
$
|
28,007
|
|
|
$
|
17,366
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company’s deferred tax assets and liabilities were composed of the following on December 31,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(in thousands)
|
|
|
Deferred tax assets
|
|
|
|
|
|
|
|
|
|
Amortization of tax credits
|
|
$
|
5,231
|
|
|
$
|
5,964
|
|
|
Vacation accrual
|
|
|
2,751
|
|
|
|
2,432
|
|
|
Unearned revenue
|
|
|
2,013
|
|
|
|
2,803
|
|
|
Benefit liabilities
|
|
|
29,418
|
|
|
|
29,657
|
|
|
SFAS 158 liabilities
|
|
|
14,694
|
|
|
|
—
|
|
|
Cost of removal
|
|
|
22,813
|
|
|
|
20,507
|
|
|
Differences related to property
|
|
|
7,923
|
|
|
|
7,400
|
|
|
Other
|
|
|
3,382
|
|
|
|
3,689
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
$
|
88,225
|
|
|
$
|
72,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
|
Differences related to property
|
|
$
|
(160,635
|
)
|
|
$
|
(154,833
|
)
|
|
Excess tax over book pension
|
|
|
(3,153
|
)
|
|
|
(3,861
|
)
|
|
Transfer to regulatory asset
|
|
|
(11,712
|
)
|
|
|
(16,724
|
)
|
|
SFAS 158 regulatory asset
|
|
|
(14,694
|
)
|
|
|
—
|
|
|
Other
|
|
|
(2,702
|
)
|
|
|
(3,900
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
$
|
(192,896
|
)
|
|
$
|
(179,318
|
)
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
$
|
(104,671
|
)
|
|
$
|
(106,866
|
)
|
|
|
|
|
|
|
|
|
16. Discontinued Operations
In 2006, the Company sold the natural gas marketing operations of OTESCO, the Company’s energy
services subsidiary. Discontinued operations includes the operating results of OTESCO’s natural
gas marketing operations for 2006, 2005 and 2004. Discontinued operations also includes an
after-tax gain on the sale of OTESCO’s natural gas marketing operations of $0.3 million in 2006.
In 2005, the Company sold Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication,
Inc. (SGS) and Chassis Liner Corporation (CLC). Discontinued operations includes the operating
results of MIS, SGS and CLC for 2005 and 2004. Discontinued operations also includes an
after-tax gain on the sale of MIS of $11.9 million, an after-tax loss on the sale of SGS of $1.7
million and an after-tax loss on the sale of CLC of $0.2 million in 2005. OTESCO’s natural gas
marketing operations, MIS, SGS and CLC meet requirements to be reported as discontinued
operations in accordance with SFAS No. 144,
Accounting for the Impairment or Disposal of
Long-Lived Assets
.
The results of discontinued operations for the years ended December 31, 2006, 2005 and 2004 are
summarized as follows:
|
|
|
|
|
|
|
2006
|
|
(in thousands)
|
|
OTESCO Gas
|
|
|
|
Operating revenues
|
|
$
|
28,234
|
|
|
Income before income taxes
|
|
|
54
|
|
|
Gain on disposition — pretax
|
|
|
560
|
|
|
Income tax expense
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
(in thousands)
|
|
OTESCO Gas
|
|
MIS
|
|
SGS
|
|
CLC
|
|
Total
|
|
|
|
Operating revenues
|
|
$
|
64,539
|
|
|
$
|
3,773
|
|
|
$
|
6,564
|
|
|
$
|
6,112
|
|
|
$
|
80,988
|
|
|
Income (loss) before income taxes
|
|
|
(84
|
)
|
|
|
2,167
|
|
|
|
(1,740
|
)
|
|
|
(956
|
)
|
|
|
(613
|
)
|
|
Goodwill impairment loss
|
|
|
(1,003
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,003
|
)
|
|
Gain (loss) on disposition — pretax
|
|
|
—
|
|
|
|
19,025
|
|
|
|
(2,919
|
)
|
|
|
(271
|
)
|
|
|
15,835
|
|
|
Income tax (benefit) expense
|
|
|
(40
|
)
|
|
|
7,975
|
|
|
|
(1,863
|
)
|
|
|
(502
|
)
|
|
|
5,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
(in thousands)
|
|
OTESCO Gas
|
|
MIS
|
|
SGS
|
|
CLC
|
|
Total
|
|
|
|
Operating revenues
|
|
$
|
44,326
|
|
|
$
|
8,739
|
|
|
$
|
17,209
|
|
|
$
|
7,753
|
|
|
$
|
78,027
|
|
|
Income (loss) before income taxes
|
|
|
211
|
|
|
|
3,698
|
|
|
|
(932
|
)
|
|
|
(163
|
)
|
|
|
2,814
|
|
|
Income tax expense (benefit)
|
|
|
81
|
|
|
|
1,483
|
|
|
|
(371
|
)
|
|
|
(72
|
)
|
|
|
1,121
|
|
At December 31, 2006 and 2005 the major components of assets and liabilities of the discontinued
operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
December 31, 2005
|
|
|
(in thousands)
|
|
SGS
|
|
|
OTESCO Gas
|
|
|
SGS
|
|
|
CLC
|
|
|
Total
|
|
|
|
|
Current assets
|
|
$
|
289
|
|
|
$
|
11,384
|
|
|
$
|
857
|
|
|
$
|
1,455
|
|
|
$
|
13,696
|
|
|
Investments and other assets
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets of discontinued operations
|
|
$
|
289
|
|
|
$
|
11,384
|
|
|
$
|
857
|
|
|
$
|
1,460
|
|
|
$
|
13,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
197
|
|
|
$
|
10,611
|
|
|
$
|
328
|
|
|
$
|
44
|
|
|
$
|
10,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities of discontinued operations
|
|
$
|
197
|
|
|
$
|
10,611
|
|
|
$
|
328
|
|
|
$
|
44
|
|
|
$
|
10,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The remaining assets and liabilities of SGS consist of deferred taxes and warranty reserves at
estimated fair market values that were not settled or disposed of as of December 31, 2006.
17. Asset Retirement Obligations (AROs)
The Company’s AROs are related to coal-fired generation plants and include site restoration,
closure of ash pits, and removal of storage tanks and asbestos. The Company has legal
obligations associated with the retirement of a variety of other long-lived tangible assets used
in electric operations where the estimated settlement costs are individually and collectively
immaterial. The Company has no assets legally restricted for the settlement of any of its AROs.
During 2006, the Company did not record any new obligation or make any revisions to previously
recorded obligations. The Company settled a legal obligation for removal of asbestos at unit one
of its Hoot Lake generating plant. The Company did not settle any asset retirement obligations
in 2005 or 2004.
Reconciliations of carrying amounts of the present value of the Company’s legal AROs,
capitalized asset retirement costs and related accumulated depreciation and a summary of
settlement activity for the years ended December 31, 2006 and 2005 are presented in the
following table:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
1,524
|
|
|
$
|
1,437
|
|
|
New obligations recognized
|
|
|
—
|
|
|
|
—
|
|
|
Adjustments due to revisions in cash flow estimates
|
|
|
—
|
|
|
|
—
|
|
|
Accrued accretion
|
|
|
85
|
|
|
|
87
|
|
|
Settlements
|
|
|
(274
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
1,335
|
|
|
$
|
1524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement costs capitalized
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
349
|
|
|
$
|
349
|
|
|
New obligations recognized
|
|
|
—
|
|
|
|
—
|
|
|
Adjustments due to revisions in cash flow estimates
|
|
|
—
|
|
|
|
—
|
|
|
Settlements
|
|
|
(64
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
285
|
|
|
$
|
349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation — asset retirement costs capitalized
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
234
|
|
|
$
|
225
|
|
|
New obligations recognized
|
|
|
—
|
|
|
|
—
|
|
|
Adjustments due to revisions in cash flow estimates
|
|
|
—
|
|
|
|
—
|
|
|
Accrued depreciation
|
|
|
8
|
|
|
|
9
|
|
|
Settlements
|
|
|
(64
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
178
|
|
|
$
|
234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements
|
|
|
|
|
|
|
|
|
|
Original capitalized asset retirement cost — retired
|
|
$
|
64
|
|
|
$
|
—
|
|
|
Accumulated depreciation
|
|
|
(64
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
$
|
274
|
|
|
$
|
—
|
|
|
Settlement cost
|
|
|
(222
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Gain on settlement — deferred under regulatory accounting
|
|
$
|
52
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
18. Quarterly Information (not audited)
Because of changes in the number of common shares outstanding and the impact of diluted shares,
the sum of the quarterly earnings per common share may not equal total earnings per common share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(in thousands, except per share data)
|
|
|
|
|
Operating revenues
(a)
|
|
$
|
257,807
|
|
|
$
|
216,084
|
|
|
$
|
279,904
|
|
|
$
|
245,799
|
|
|
$
|
280,542
|
|
|
$
|
261,187
|
|
|
$
|
286,701
|
|
|
$
|
258,799
|
|
|
Operating income
(a)
|
|
|
27,374
|
|
|
|
21,107
|
|
|
|
22,136
|
|
|
|
20,821
|
|
|
|
24,170
|
|
|
|
33,479
|
|
|
|
24,117
|
|
|
|
23,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
|
14,855
|
|
|
|
11,076
|
|
|
|
11,137
|
|
|
|
10,952
|
|
|
|
13,476
|
|
|
|
19,168
|
|
|
|
11,282
|
|
|
|
12,706
|
|
|
Discontinued operations
|
|
|
105
|
|
|
|
(1,105
|
)
|
|
|
257
|
|
|
|
11,352
|
|
|
|
—
|
|
|
|
(1,565
|
)
|
|
|
—
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,960
|
|
|
|
9,971
|
|
|
|
11,394
|
|
|
|
22,304
|
|
|
|
13,476
|
|
|
|
17,603
|
|
|
|
11,282
|
|
|
|
12,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings available for common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
|
14,671
|
|
|
|
10,892
|
|
|
|
10,953
|
|
|
|
10,769
|
|
|
|
13,293
|
|
|
|
18,983
|
|
|
|
11,097
|
|
|
|
12,523
|
|
|
Discontinued operations
|
|
|
105
|
|
|
|
(1,105
|
)
|
|
|
257
|
|
|
|
11,352
|
|
|
|
—
|
|
|
|
(1,565
|
)
|
|
|
—
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,776
|
|
|
|
9,787
|
|
|
|
11,210
|
|
|
|
22,121
|
|
|
|
13,293
|
|
|
|
17,418
|
|
|
|
11,097
|
|
|
|
12,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
.50
|
|
|
$
|
.37
|
|
|
$
|
.37
|
|
|
$
|
.37
|
|
|
$
|
.45
|
|
|
$
|
.65
|
|
|
$
|
.38
|
|
|
$
|
.43
|
|
|
Discontinued operations
|
|
|
—
|
|
|
|
(.03
|
)
|
|
|
.01
|
|
|
|
.39
|
|
|
|
—
|
|
|
|
(.05
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
.50
|
|
|
|
.34
|
|
|
|
.38
|
|
|
|
.76
|
|
|
|
.45
|
|
|
|
.60
|
|
|
|
.38
|
|
|
|
.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
|
.50
|
|
|
$
|
.37
|
|
|
|
.37
|
|
|
$
|
.37
|
|
|
|
.45
|
|
|
$
|
.64
|
|
|
|
.37
|
|
|
$
|
.42
|
|
|
Discontinued operations
|
|
|
—
|
|
|
|
(.04
|
)
|
|
|
.01
|
|
|
|
.39
|
|
|
|
—
|
|
|
|
(.05
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
.50
|
|
|
|
.33
|
|
|
|
.38
|
|
|
|
.76
|
|
|
|
.45
|
|
|
|
.59
|
|
|
|
.37
|
|
|
|
.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends paid per common share
|
|
|
.2875
|
|
|
|
.28
|
|
|
|
.2875
|
|
|
|
.28
|
|
|
|
.2875
|
|
|
|
.28
|
|
|
|
.2875
|
|
|
|
.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price range:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
31.34
|
|
|
$
|
25.87
|
|
|
$
|
30.09
|
|
|
$
|
27.77
|
|
|
$
|
30.80
|
|
|
$
|
31.95
|
|
|
$
|
31.92
|
|
|
$
|
31.95
|
|
|
Low
|
|
|
27.32
|
|
|
|
24.17
|
|
|
|
25.78
|
|
|
|
24.02
|
|
|
|
26.50
|
|
|
|
27.20
|
|
|
|
28.60
|
|
|
|
26.76
|
|
|
Average number of common shares
outstanding—basic
|
|
|
29,326
|
|
|
|
29,126
|
|
|
|
29,393
|
|
|
|
29,158
|
|
|
|
29,413
|
|
|
|
29,246
|
|
|
|
29,445
|
|
|
|
29,361
|
|
|
Average number of common shares
outstanding—diluted
|
|
|
29,676
|
|
|
|
29,230
|
|
|
|
29,766
|
|
|
|
29,264
|
|
|
|
29,806
|
|
|
|
29,441
|
|
|
|
29,731
|
|
|
|
29,555
|
|
|
|
|
|
|
(a)
|
|
From continuing operations.
|
Stock Listing
Otter Tail Corporation common stock trades on The Nasdaq Global Select Market.
