exv13wa

Exhibit 13-A

Selected Consolidated Financial Data


(thousands, except number of shareholders and per-share data)	2005			2004			2003			2002			2001			2000			1995
Revenues
Electric	$	312,985		$	266,385		$	267,494		$	244,005		$	232,720		$	219,718		$	192,053
Plastics		158,548			115,426			86,009			82,931			63,216			82,667			4,569
Manufacturing (1)		244,311			201,615			157,401			119,880			96,571			73,940			34,121
Health services		123,991			114,318			100,912			93,420			79,129			66,319			50,896
Food Ingredient Processing		38,501			14,023			—			—			—			—			—
Other business operations (1)		171,939			148,328			114,726			75,947			72,191			70,145			28,984
Intersegment eliminations		(3,867	)		(2,733	)		(2,254	)		(1,036	)		—			—			—

Total operating revenues	$	1,046,408		$	857,362		$	724,288		$	615,147		$	543,827		$	512,789		$	310,623

Income from continuing operations (1)		52,855			40,632			38,225			44,222			40,055			37,654			28,305
Income from discontinued operations (1)		9,696			1,563			1,431			1,906			3,548			3,388			640

Net income		62,551			42,195			39,656			46,128			43,603			41,042			28,945
Operating cash flow from continuing operations (1)		90,358			54,330			76,314			71,582			71,025			57,110			56,404
Operating cash flow — continuing and discontinued operations		95,800			56,301			76,955			76,797			77,529			61,761			58,077
Capital expenditures — continuing operations (1)		59,969			49,484			48,783			73,447			50,727			44,655			36,343
Total assets		1,181,496			1,134,148			986,423			914,112			817,778			772,562			643,173
Long-term debt (1)		258,260			261,805			262,311			254,015			221,643			188,031			160,235
Redeemable preferred		—			—			—			—			—			18,000			18,000
Basic earnings per share — continuing operations (1) (2)		1.79			1.53			1.46			1.73			1.55			1.46			1.16
Basic earnings per share — total (2)		2.12			1.59			1.52			1.80			1.69			1.59			1.19
Diluted earnings per share — continuing operations (1) (2)		1.78			1.52			1.45			1.71			1.53			1.45			1.16
Diluted earnings per share — total (2)		2.11			1.58			1.51			1.79			1.68			1.59			1.19
Return on average common equity		13.9	%		12.0	%		12.2	%		15.3	%		15.5	%		15.4	%		14.8	%
Dividends per common share		1.12			1.10			1.08			1.06			1.04			1.02			0.88
Dividend payout ratio		53	%		70	%		72	%		59	%		62	%		64	%		74	%
Common shares outstanding — year end		29,401			28,977			25,724			25,592			24,653			24,574			22,360
Number of common shareholders (3)		14,801			14,889			14,723			14,503			14,358			14,103			13,933

Notes:

(1)		Prior years are restated to exclude the operations of Midwest Information Systems, Inc., St George Steel Fabrication, Inc. and Chassis Liner Corporation, which are classified as discontinued operations. See note 15 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 vision is to create value and growth through ownership and acquisition of well-run companies in diverse businesses. 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 since our aim is to add companies that will produce an immediate positive impact on earnings and provide long-term growth potential. Owning well-run, profitable companies across different industries can 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 if they do not meet these criteria over the long term.

The following major events occurred in our company in 2005:

	•		Our annual consolidated revenues topped $1 billion for the first time in our history.

	•		We reported record consolidated earnings and record earnings in our electric and plastics segments.

	•		We sold three of our operating companies for a net after-tax gain of $10.0 million.

	•		In June we jointly announced an agreement with six other regional utilities to build a new 600-megawatt coal-fired electric generating plant (BSP II) on the site of the existing Big Stone Plant if all necessary permits and approvals are granted on a timely basis.

Major growth strategies and initiatives in our company’s future include:

	•		Planned capital budget expenditures of $477 million for the years 2006-2010, including $247 million related to BSP II, if built.

	•		The continued investigation and evaluation of strategic acquisition opportunities.

	•		Pursuing the regulatory approvals, financing and other arrangements necessary to build BSP II.

The following table summarizes our consolidated results of operations for the years ended December 31:


(in thousands)	2005		2004
Operating revenues:
Electric	$	312,985	$	266,385
Nonelectric		733,423		590,977

Total operating revenues	$	1,046,408	$	857,362


Net income from continuing operations:
Electric	$	37,301	$	31,535
Nonelectric		15,554		9,097

		52,855		40,632
Net income from discontinued operations		9,696		1,563

Total net income	$	62,551	$	42,195

The 22.0% increase in consolidated revenues in 2005 compared with 2004 reflects revenue growth in all our business segments. Revenues in the electric segment increased $46.6 million reflecting a $24.6 million increase in retail electric revenue, a $19.2 million increase in wholesale energy and mark-to-market revenues and a $2.8 million increase in other electric revenue. Revenues grew $43.1 million in our plastics segment in 2005 primarily as a result of rising resin prices and increased demand for polyvinyl chloride (PVC) pipe, particularly following the 2005 Gulf Coast hurricanes. Revenues increased $42.7 million in our manufacturing segment in 2005 as a result of increased unit sales and price increases related to increases in raw material costs, sales of higher priced products and the acquisitions of three companies in 2005. Revenues from our health services segment increased $9.7 million. Scanning and other related service revenues increased $13.9 million while revenues from equipment sales and service decreased $4.2 million between the years. Revenues in our food ingredient processing segment were $38.5 million for 2005 compared with $14.0 million from our 19 weeks of ownership in 2004. Other business operations revenue grew by $23.6 million with most of the increase coming from our energy services company as a result of higher natural gas prices in 2005.

A 93% increase in net margins from wholesale electric sales and energy trading activities and a 3.2% increase in retail electric megawatt-hour sales were the main contributing factors to the $5.8 million increase in electric segment net income. A record year in our plastics segment and an increase in earnings from continued improvements in our health services segment were the major factors contributing to the $6.5 million increase in net income from our nonelectric business segments in 2005 compared with 2004.

Following is a more detailed analysis of our operating results by business segment for the three years ended December 31, 2005, 2004 and 2003, followed by our outlook for 2006, a discussion of our financial position at the end of 2005 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 2005, 2004 and 2003 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)	2005		2004		2003

Operating revenues	$	3,867	$	2,733	$	2,254
Cost of goods sold		2,070		1,083		527
Other nonelectric expenses		1,797		1,650		1,727

ELECTRIC

The following table summarizes the results of operations for our electric segment for the years ended December 31:


			%				%
(in thousands)	2005		change		2004		change		2003

Retail sales revenues	$	248,939		11	$	224,326		3	$	217,439
Wholesale revenues		41,953		75		24,000		(6)		25,644
Net marked-to-market gains		4,444		38		3,228		(20)		4,058
Other revenues		17,649		19		14,831		(27)		20,353

Total operating revenues	$	312,985		17	$	266,385		—	$	267,494
Production fuel		55,927		7		52,056		2		51,163
Purchased power – system use		58,828		47		40,098		11		36,002
Other operation and maintenance expenses		99,904		17		85,361		(2)		87,186
Depreciation and amortization		24,397		1		24,236		(7)		26,008
Property taxes		10,043		(4)		10,411		8		9,598

Operating income	$	63,886		18	$	54,223		(6)	$	57,537

The $24.6 million increase in retail revenues from 2004 to 2005 includes $16.0 million in increased fuel clause adjustment (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 kilowatt-hour (kwh) sales. Residential kwh 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. Kwh 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. With the inception of the Midwest Independent Transmission System Operator (MISO) Day 2 markets in April 2005, MISO introduced two new types of contracts, virtual transactions and Financial Transmission Rights (FTRs). Virtual transactions are of two types: 1) A Virtual Demand Bid is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by physical load. 2) A Virtual Supply Offer 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. We recorded $12.7 million in net revenues related to virtual transactions in 2005. 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 can be 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. We recorded $1.9 million in net revenue related to bilateral trading of FTRs in MISO’s secondary market in 2005. In 2005, net revenues from the purchase and sale of electric energy contracts, including virtual transactions and FTRs, increased $11.2 million, compared with net revenues from energy trading activities in 2004, on a 178% increase in kwh volume traded between the years. As the MISO markets evolve and become more efficient, profits from virtual and FTR transactions may be reduced. Revenues from wholesale energy sales from company-owned generation increased $6.8 million due to a 58.9% increase in the average price per kwh sold in 2005 compared with 2004, offset by a 13.2% reduction in kwh sales. The increase in the average price per kwh 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 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 Minnesota Public Utilities Commission (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. On February 9, 2006 the MPUC reconsidered its December 2005 order. On reconsideration, the MPUC 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 possible recovery through base rates in the electric utility’s next general rate case. The MPUC’s final written order of this action is pending. When the final order is issued, the electric utility will recognize the $1.9 million in revenue and reverse the refund payable.

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 kwh generated, partially offset by a 7.0% reduction in generation. The decrease in kwhs generated is mainly due to the seven-week maintenance shutdown of Big Stone Plant in 2005. Fuel costs per kwh 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. Kwh generation at our higher-cost Hoot Lake generating units increased 25% in 2005 compared with 2004 while kwh generation at our lower-cost Big Stone and Coyote generating units decreased 21% and 6%, respectively, between the years. Fuel costs at our combustion turbine peaking plants increased $2.5 million (110%) while kwh 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 kwh purchases combined with a 14.5% increase in the cost per kwh purchased. Kwh 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 kwh 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. Approximately 90% of fuel and purchased power cost increases associated with service to retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

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 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.

The $6.9 million increase in retail revenues from 2003 to 2004 is mainly due to a $4.0 million increase in FCA revenues. The remaining increase in retail revenues was due to a 1.5% increase in retail kwh sales. The increase in retail sales reflects a 3.2% increase in kwh sales to commercial and industrial customers, partially offset by a 2.0% decrease in kwh sales to residential customers. The increase in commercial and industrial kwh sales reflects increased sales to pipeline customers related to increased oil prices and increased sales to large commercial customers due to a rebounding economy in 2004. Residential kwh sales decreased mainly as a result of a 55.7% decrease in cooling degree-days in the summer of 2004 compared with the summer of 2003. The increase in FCA revenues is due to a 16.3% increase in kwh purchases for retail use in 2004 compared with 2003. Fuel and purchased power costs for retail use also increased as a result of higher retail kwh demand in 2004 compared with 2003.

Wholesale revenues from sales of company-owned generation decreased $0.6 million in 2004 compared with 2003 due to a 1.9% decrease in kwh sales combined with a 1.5% decrease in revenue per kwh of generation sold. Fuel costs per kwh of generation used for wholesale sales decreased 2.6% between the years resulting in a decrease in the gross margin per kwh sold from company-owned generation of only 0.2%. Net margins on purchased power resold decreased $1.0 million despite a 2.2% increase in kwh sales as a result of a 16.3% decrease in the gross margin per kwh of purchased power resold. The 2003 mid-year change in the revenue recognition methodology (applied to resales of purchased power from contract-based prices to market-based prices as a result of adopting SFAS No. 133 in July 2003) is a contributing factor to the 16.3% decrease in the gross margin per kwh of purchased power resold between 2003 and 2004. The $0.8 million decrease in net mark-to-market gains on forward energy contracts reflects the recognition of $2.1 million in net gains related to the initial adoption of mark-to-market accounting on forward energy contracts in July 2003, partially offset by a $1.3 million increase in mark-to-market gains recognized in 2004 compared with 2003 as a result of applying mark-to-market accounting to forward energy contracts for all of 2004 compared with applying it for only six months of 2003.

In 2003, other electric operating revenues included revenues from contracted construction work completed on a large wind farm project in North Dakota. The electric utility did not have a construction contract of similar magnitude in 2004, which is the main reason for the $5.5 million reduction in other electric revenues between 2003 and 2004.

The $1.8 million decrease in other operation and maintenance expenses in 2004 compared with 2003 includes a $3.2 million reduction in costs related to contracted construction work on the wind farm project completed in 2003. This reduction was partially offset by increases in regulatory expenses and increases in expenses related to transmission services, and a $0.6 million net increase in labor and benefit expenses after taking into account a $0.7 million reduction in retiree medical benefit costs related to the Medicare prescription drug benefit subsidy recorded in 2004.

The $1.8 million decrease in depreciation and amortization expense for 2004 compared with 2003 is related to the extension of the depreciable service lives of certain units of electric utility property. The extension of these depreciable service lives was included in the electric utility’s annual depreciation study and depreciation rates approved by the MPUC. The $0.8 million increase in property taxes in 2004 compared with 2003 is mainly related to a 9.0% increase in the value of electric utility property apportioned to Minnesota related to the value the State of Minnesota assigned to the utility’s Solway combustion turbine generator property.

PLASTICS

The following table summarizes the results of operations for our plastics segment for the years ended December 31:


			%				%
(in thousands)	2005		change		2004		change		2003

Operating revenues	$	158,548		37	$	115,426		34	$	86,009
Cost of goods sold		121,245		25		97,126		28		76,046
Operating expenses		10,939		91		5,718		50		3,824
Depreciation and amortization		2,511		9		2,297		8		2,126

Operating income	$	23,853		132	$	10,285		156	$	4,013

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 resin, the raw material used to produce PVC pipe, 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 manufacturing equipment purchased in 2004 and 2005.

The $29.4 million increase in plastics operating revenues in 2004 compared with 2003 reflects a 10.8% increase in the pounds of PVC pipe sold between the years combined with an 18.2% increase in the average sales price per pound of pipe sold. The increase in revenues was partially offset by a $21.1 million increase in cost of goods sold reflecting an 11.7% increase in the average cost per pound of pipe sold. The average cost per pound of resin increased 19.0% between the periods. The $1.9 million increase in operating expenses between the periods primarily is due to increases in costs directly related to increased sales along with increases in building rental expenses and property taxes related to our polyethylene pipe plant in Hampton, Iowa, which began operations in summer 2003. The increase in depreciation and amortization expense relates mostly to manufacturing equipment purchased in 2003 and 2004.

MANUFACTURING

Operating results for the manufacturing segment for 2004 and 2003 have changed as a result of the reclassification of St. George Steel Fabrication, Inc. and Chassis Liner Corporation to discontinued operations in 2005. The following table summarizes the results of operations for our manufacturing segment for the years ended December 31:


			%				%
(in thousands)	2005		change		2004		change		2003

Operating revenues	$	244,311		21	$	201,615		28	$	157,401
Cost of goods sold		194,264		23		157,802		29		122,763
Operating expenses		23,872		13		21,098		14		18,471
Depreciation and amortization		9,447		21		7,828		14		6,882

Operating income	$	16,728		12	$	14,887		60	$	9,285

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 Industries, Inc. (DMI), our manufacturer of wind towers, 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 Manufacturing Inc. (BTD), our metal parts stamping and fabrication company, 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, Inc., our waterfront equipment manufacturer, 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, Inc., our manufacturer of thermoformed plastic and horticultural products, 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 have 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 $3.8 million increase in cost of goods sold is mainly related 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.

The manufacturing segment’s improved performance in 2004 compared with 2003 can be attributed to certain companies within this segment being able to offset increases in commodity prices with product pricing increases and increased productivity and capacity utilization. The increases in productivity at BTD and DMI resulted in a combined increase in manufacturing segment operating income from these two companies of $6.5 million in 2004 compared with 2003. Revenue increases at the other manufacturing companies were offset by increased costs and operating expenses resulting in a combined net decrease in operating income from these companies of $0.9 million in 2004 compared with 2003.

The increase in revenues in our manufacturing segment in 2004 compared with 2003 relates to the following:

	•		Revenues at BTD increased $18.5 million (36.8%) as a result of product price increases related to increases in raw material costs, especially steel, and a 12.7% increase in the number of units produced and sold at BTD’s expanded manufacturing facilities in 2004 compared with 2003.

	•		DMI revenues increased $11.3 million (30.4%) reflecting product price increases related to increased steel prices and increased productivity and plant utilization in 2004.

	•		ShoreMaster revenues increased $8.6 million (19.7%) as a result of increases in sales of residential waterfront equipment, increases in jobs in progress and product price increases related to higher raw material costs.

	•		Revenues at T.O. Plastics increased $5.8 million (21.8%) as a result of a 14.2% increase in units sold in 2004 compared with 2003.

The $35.0 million increase in cost of goods sold in 2004 compared with 2003 includes increases of $13.3 million at BTD, $8.8 million at ShoreMaster, $7.7 million at DMI and $5.2 million at T.O. Plastics as a result of production increases and higher raw material costs at each of the companies.

The $2.6 million net increase in manufacturing segment operating expenses in 2004 compared with 2003 includes $1.9 million in increased expenses at BTD (reflecting increases in compensation and promotional expenses related to increased sales and losses related to the disposal of equipment no longer used in production) and $0.9 million in increased sales commissions at ShoreMaster. The $0.9 million increase in depreciation and amortization expense in 2004 compared with 2003 is mainly due to 2004 and 2003 equipment purchases at three of our manufacturing companies.

HEALTH SERVICES

The following table summarizes the results of operations for our health services segment for the years ended December 31:


			%				%
(in thousands)	2005		change		2004		change		2003

Operating revenues	$	123,991		8	$	114,318		13	$	100,912
Cost of goods sold		90,327		5		85,731		14		75,117
Operating expenses		21,989		25		17,593		14		15,410
Depreciation and amortization		4,038		(20)		5,047		(2)		5,137

Operating income	$	7,637		28	$	5,947		13	$	5,248

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 have contributed to improved results in the health services segment.

The $13.4 million increase in health services operating revenues for 2004 compared with 2003 reflects $6.9 million in additional imaging revenues and $6.5 million from sales and servicing of equipment. The number of scans performed on a fee-per-scan basis decreased 14.1% while the average fee per scan increased 17.7%. The increase in revenue from equipment sales includes $1.8 million in increased revenue related to the acquisitions of Topline Medical and North Star Medical Systems in May and July of 2003. The $10.6 million increase in cost of goods sold in 2004 compared with 2003 includes $4.5 million related to equipment sales and $6.1 million related to imaging and other services. The $2.2 million increase in operating expenses reflects increases in compensation and benefits expenses and increases in travel expenses related to the 2003 medical equipment company acquisitions and an expansion of imaging services.

FOOD INGREDIENT PROCESSING

The following table summarizes the results of operations for our food ingredient processing segment for the periods ended December 31:


	2005		2004
(in thousands)	(full year)		(19 weeks)

Operating revenues	$	38,501	$	14,023
Cost of goods sold		30,930		11,379
Operating expenses		2,533		876
Depreciation and amortization		3,399		1,118

Operating income	$	1,639	$	650

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 Idaho Pacific Holdings, Inc. (IPH) in August 2004. Disclosure of pro forma information related to the results of operations of IPH for the periods presented in this report is not required due to immateriality.

Consistent with trends in the industry, operating income for 2005 was less than expected as a result of lower sales volume and prices, high energy costs, increasing raw material costs and the increasing value of the Canadian dollar relative to the U.S. dollar.

OTHER BUSINESS OPERATIONS

The following table summarizes the results of operations for our other business operations segment for the years ended December 31:


				%					%
(in thousands)	2005			change		2004			change		2003

Operating revenues	$	171,939			16	$	148,328			29	$	114,726
Cost of goods sold		131,951			17		113,054			37		82,378
Operating expenses		52,468			22		42,907			17		36,646
Goodwill impairment loss		1,003			—		—			—		—
Depreciation and amortization		2,666			(9)		2,945			4		2,841

Operating (loss)	$	(16,149	)		(53)	$	(10,578	)		(48)	$	(7,139	)

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 OTESCO, our energy services company, increased $20.4 million (45.8%), which includes $20.9 million in increased revenue from natural gas sales mainly as a result of increases in natural gas prices between the periods. The increase in revenue from natural gas sales was almost entirely offset by a $20.6 million increase in natural gas costs between the years. OTESCO also recorded a net increase in technical services revenue of $0.2 million between the years and a net loss on natural gas forward swap transactions of $0.5 million in 2005 compared to a net gain of $0.2 million recorded in 2004.

	•		Revenues at Midwest Construction Services, Inc. (MCS), our electrical design and construction services company, 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 E.W. Wylie Corporation (Wylie), our flatbed trucking company, 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, a mechanical and prime contractor on industrial projects, 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.

The $1.0 million goodwill impairment loss in 2005 relates to the write-off of goodwill at OTESCO 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.

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.

The increases in operating revenues and cost of goods sold in our other business operations in 2004 compared with 2003 are due to the following:

	•		Revenues at Foley Company, acquired in November 2003, increased $40.6 million and Foley’s cost of goods sold increased $36.7 million between the years, reflecting a full year of operations in 2004.

	•		Revenues at OTESCO increased $8.6 million (23.9%) and its cost of goods sold increased $8.5 million between the years mainly due to increases in natural gas prices.

	•		Wylie’s revenues increased $1.9 million (7.8%) reflecting increased brokerage activity and the pass through of increased diesel fuel prices to customers. Brokered miles increased 5.5% between the years while the combined miles driven by company-owned trucks and owner-operated trucks decreased 7.4%.

	•		MCS revenues decreased $17.7 million (39.5%) and cost of goods sold decreased $14.6 million between the periods due to a lower volume of available work in combination with excess capacity in MCS’s construction market.

The increase in operating expenses in our other business operations segment in 2004 compared with 2003 relates to the following:

	•		Foley’s operating expenses were $3.2 million for 2004 compared with $0.5 million for two months of operations in 2003.

	•		Wylie’s operating expenses increased $1.9 million mainly as a result of higher fuel prices and increased brokerage activity between the periods.

	•		Operating expenses in 2004 reflect $1.3 million in increased unallocated corporate overhead costs mainly due to increases in employee benefit costs and increased expenses for professional services related to compliance with Sarbanes-Oxley Section 404 requirements.

	•		MCS reported increased expenses of $0.7 million, mostly due to increases in payroll and advertising and promotional expenses in 2004 compared with 2003.

	•		OTESCO’s general and administrative expenses decreased $0.3 million between the years.

CONSOLIDATED INTEREST CHARGES

Interest expense increased $0.4 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.

Interest expense increased $0.5 million in 2004 compared to 2003 primarily as a result of interest expense on the bridge loan used to finance the acquisition of IPH.

CONSOLIDATED INCOME TAXES

The 60% increase in income tax expense from continuing operations in 2005 compared to 2004 is due, in part, to a 39% increase in income from continuing operations before income taxes. Our effective tax rate on income from continuing operations was 34.6% 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 14 to consolidated financial statements.

Our effective tax rate on income from continuing operations was 30.0% for 2004 compared with 27.0% for 2003. Approximately 1.0% of the difference in the effective tax rate for 2004 compared to 2003 reflects the impact of R&D tax credits claimed in 2003. The remaining 2.0% difference in the effective tax rate for 2004 compared to 2003 is a function of the level of fixed deductions and credits in proportion to higher net income before tax in 2004 compared to 2003.

DISCONTINUED OPERATIONS

Discontinued operations includes the operating results of Midwest Information Systems (MIS), a telecommunications company located in Parkers Prairie, Minnesota, St. George Steel Fabrication, Inc. (SGS), a structural steel fabricator located in St. George, Utah, and Chassis Liner Corporation (CLC) a manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota. The sales of MIS and SGS were completed in the second quarter of 2005. The sale of CLC was completed in the fourth

quarter of 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 2005, 2004 and 2003 consolidated statements of income.


				%				%
(in thousands)	2005			change		2004		change		2003

Operating revenues	$	16,449			(51)	$	33,701		16	$	28,951
Expenses		16,978			(45)		31,098		16		26,752
Income tax (benefit) expense		(221	)		—		1,040		35		768

(Loss) income from discontinued operations	$	(308	)		—	$	1,563		9	$	1,431

The following table presents the pre-tax and net-of-tax gains and losses recorded on the sales of the three companies in 2005.


(in thousands)	MIS			SGS			CLC			Total

Gain (loss) on sale	$	19,025		$	(2,919	)	$	(271	)	$	15,835
Income tax (expense) benefit		(7,107	)		1,168			108			(5,831	)

Net gain (loss) on sale	$	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.

2006 EXPECTATIONS

We anticipate 2006 diluted earnings per share from continuing operations will be in a range from $1.60 to $1.80. Contributing to the earnings expectations for 2006 are the following items:

•

We expect solid performance in the electric segment in 2006 although net income is anticipated to be lower than 2005 levels. This is primarily because margins on wholesale electric sales are expected to be tighter as the MISO market becomes more efficient, anticipated increases in transmission service and wage and benefit costs, and uncertainty related to the recoverability of certain MISO-related costs through the fuel clause adjustments in Minnesota and North Dakota retail rates. We expect earnings for the electric segment in 2006 to return to more historical levels.

	•		We expect the plastics segment performance to return to more historical levels in 2006 following the 2005 record year.

	•		The improving economy, continued enhancements in productivity and capacity utilization, expanded markets, expansion of production capacity with the opening of a new wind tower production facility in Fort Erie, Ontario, Canada, and continued availability of production tax credits are expected to result in increased net income in our manufacturing segment.

	•		Our health services segment is expected to have moderate growth in net income in 2006.

	•		We expect our food ingredient processing business to generate net income in the range of $2 million to $4 million for the year ending December 31, 2006.

	•		Our other business operations segment is expected to show improved results over 2005 due to an improving economy and an increase in its backlog of construction contracts. An increase in wind energy projects activity is expected to have a positive impact on our electrical contracting business.

	•		We anticipate investing approximately $57 million in capital expenditures during 2006 in addition to funding possible future acquisitions.

	•		Our outlook for 2006 reflects the impact of Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, which is anticipated to lower diluted earnings per share results by $0.015 per share in 2006. This standard requires all share-based compensation awards be measured at fair value at the date of grant and expensed over their vesting or service periods. This standard is effective beginning in January 2006.

Our outlook for 2006 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. However, 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 $95.8 million in 2005 compared with $56.3 million in 2004. The $39.5 million increase in cash from operations reflects a $13.3 million increase in net income (net of the $3.0 million increase in noncash depreciation and amortization expense and excluding the $10.0 million gain on the sale of discontinued operations) and a $34.3 million increase in payables

and other current liabilities offset by a $7.8 million increase in receivables, inventories and other current assets between the years. The increase in payables and other current liabilities includes: $11.5 million related to PVC resin purchased in the fourth quarter of 2005 under extended payment terms related to a normal slowdown in business in the fourth quarter, $6.5 million in incentive compensation accrual increases related to improved results in the electric and plastics business segments in 2005 and increased production activity at DMI, $5.4 million in billings in excess of costs at DMI and Shoremaster related to an increase in jobs in progress at year-end 2005 compared with year-end 2004, a $4.7 million increase in accounts payable at DMI related to a large steel shipment received in December 2005, a $1.9 million refund payable related to a MPUC order in December 2005, and an increase of $3.4 million in deposits, deferred revenues and business insurance reserves at year-end 2005 compared to year-end 2004. The increase in receivables and inventories reflects increases in receivables, mainly at MCS and the plastic pipe companies and increases in inventories primarily at the manufacturing companies. While consolidated accounts receivables are higher at December 31, 2005 compared with December 31, 2004, the average days outstanding for accounts receivable decreased between the years.

The $91.1 million decrease in net cash used in investing activities in 2005 compared with 2004 reflects a $57.8 million decrease in cash used to complete acquisitions and $34.2 million in proceeds from the sales of MIS, SGS and CLC in 2005. The decrease in cash used for acquisitions and other investments is mostly related to the 2004 acquisition of IPH, in which $68.2 million in cash was paid and $6.0 million 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 in escrow was returned to the Company in August 2005, contributing to cash flows from other investments in 2005. A breakdown of capital expenditures by segment is provided below under Capital Requirements.

Cash paid for acquisitions in 2005 net of cash acquired included the following:


Company	(thousands)
Performance Tool	$	4,116
Shoreline Industries		2,328
Southeast Floating Docks		3,968
Contingency payments—prior years’ acquisitions		811

Total	$	11,223

Net cash used in financing activities was $62.0 million in 2005 compared with net cash provided by financing activities of $55.9 million in 2004. Major uses of cash for financing activities in 2005 were:

	•		$32.7 million for the payment of dividends on common shares outstanding

	•		$24.0 million for repayment of short-term debt

	•		$7.2 million for the retirement of long-term debt

The $9.7 million in net proceeds from the issuance of common stock in 2005 included $5.8 million from the exercise of stock options and $4.3 million from the issuance of 175,000 common shares in January 2005 as a result of the underwriters exercising a portion of their over-allotment option in connection with our December 2004 public offering.

CAPITAL REQUIREMENTS

We have a capital expenditure program for the expansion, upgrade and improvement of 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 2005, 2004 and 2003 were $60.0 million, $49.5 million and $48.8 million, respectively. The estimated capital expenditures for 2006 are $57.4 million and the total capital expenditures for the five-year period 2006 through 2010 are estimated to be approximately $477 million, which includes $247 million for our share of expected expenditures for construction of the planned BSP II electric generating plant and related transmission assets if all necessary permits and approvals are granted on a timely basis.

The breakdown of 2003, 2004 and 2005 actual and 2006 through 2010 estimated capital expenditures by segment is as follows:


(in millions)	2003		2004		2005		2006		2006-2010

Electric	$	28	$	25	$	30	$	29	$	381
Plastics		4		3		4		8		18
Manufacturing		10		13		16		13		55
Health services		6		4		3		1		3
Food ingredient processing		—		4		3		4		15
Other business operations		1		1		4		2		5

Total	$	49	$	50	$	60	$	57	$	477

The following table summarizes our contractual obligations at December 31, 2005 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.


			Less than		1-3		3-5		More than
(in millions)	Total		1 year		years		years		5 years

Long-term debt obligations	$	262	$	3	$	58	$	5	$	196
Interest on long-term debt obligations		141		16		27		24		74
Operating lease obligations		136		37		59		37		3
Capacity and energy requirements		110		17		33		24		36
Coal contracts (required minimums)		84		16		22		12		34
Postretirement benefit obligations		47		4		7		8		28
Other purchase obligations		42		42		—		—		—

Total contractual cash obligations	$	822	$	135	$	206	$	110	$	371

Interest on $22.0 million of variable-rate debt outstanding on December 31, 2005 was projected based on the interest rates applicable to those debt instruments on December 31, 2005.

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 may be required in the period 2006 through 2010 in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to retire the $50 million 6.375% senior debentures due December 1, 2007, to complete acquisitions, to fund the construction of the new BSP II generating station at the Big Stone Plant site 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.

Our $100 million line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., expires on April 26, 2006. The terms of the current line of credit are essentially the same as those in place in the prior agreement. However, outstanding letters of credit issued by the company can reduce the amount available for borrowing under the line by up to $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of our senior unsecured debt. We do not anticipate any difficulties in renewing this line of credit.

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 to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements will be provided for by cash flows from electric utility operations. Our obligations under this line of credit are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. As of December 31, 2005, $16.0 million of the $100 million line of credit was in use and $12.0 million was restricted from use to cover outstanding letters of credit.

Our line 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, 2005.

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 require that we grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, 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).

On August 26, 2005 Moody’s Investor Service lowered its ratings of our senior unsecured debt from A2 to A3 and our preferred stock from Baa1 to Baa2 and changed its outlook from negative to stable. On December 22, 2005 Standard & Poor’s Rating Services affirmed our corporate credit rating and senior unsecured debt rating of BBB+. At the same time the outlook was revised from negative to stable.

Our securities ratings at December 31, 2005 are:


	Moody’s
	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 4.3x for 2005 compared to 3.4x for 2004 and our long-term debt interest coverage ratio before taxes was 6.3x for 2005 compared to 4.9x for 2004. During 2006, we expect these coverage ratios to decrease from 2005 levels assuming 2006 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

Our plans to grow and diversify through capital expenditures and 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.

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.

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 could be reduced as the MISO market becomes more efficient. Electric wholesale trading margins could be reduced or eliminated 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, 2005 we had capitalized $1.8 million in costs related to the planned construction of a second electric generating unit at our Big Stone Plant site. If approvals of permits are not received on a timely basis, the project could be at risk. If the project is abandoned, any costs capitalized prior to abandonment would be subject to expense.

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

The corporation is subject to government regulations and regulatory actions that may have a negative impact on its 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 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.

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.

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 97% of our total purchases of PVC resin in 2005 and approximately 98% of our total purchases of PVC resin in 2004. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. 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.

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 off-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 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 25% 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 recorded on our balance sheet related to the acquisition of IPH in 2004. If current conditions of low sales volumes and prices, high energy costs, increasing raw material costs and the increasing 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 a corresponding charge against earnings.

OTHER BUSINESS OPERATIONS

Our transportation company may be unable to maintain profitable operations if economic conditions restrict its ability to recover the increasing costs of fuel, insurance and labor supplies.

We currently have $6.7 million of goodwill recorded on our balance sheet related to the acquisition of E.W. Wylie Corporation (Wylie), our flatbed trucking company. Reductions in anticipated cash flows from transportation operations may indicate that the fair value of Wylie is less than its book value resulting in an impairment of goodwill and a corresponding charge against earnings.

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, 2005 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 25% 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, 2005 we had $22.0 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, 2005, interest expense and pretax earnings would change by approximately $220,000.

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.

Our energy services subsidiary markets natural gas to approximately 160 retail customers. Some of these customers are served under fixed-price contracts. There is price risk associated with a limited number of these fixed-price contracts since the corresponding cost of natural gas is not immediately locked in. However, any price risk associated with these contracts is within the acceptable risk parameters established in our risk management policy. We do not consider this price risk to be material. These contracts call for the physical delivery of natural gas and are considered executory contracts for accounting purposes. Current accounting guidance requires losses on firmly committed executory contracts to be recognized when realized.

Our energy services subsidiary has entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although our energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on our consolidated statement of income for the year ended December 31, 2005 in accordance with the guidance provided in EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

The following tables show the effect of marking-to-market our energy services subsidiary’s forward natural gas swap transactions on our consolidated balance sheet as of December 31, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to December 31, 2005:


(in thousands)	December 31, 2005

Current asset — marked-to-market gain	$	825
Current liability — marked-to-market loss		(851	)

Net fair value of marked-to-market gas contracts	$	(26	)


	Year ended
(in thousands)	December 31, 2005

Fair value at beginning of year	$	134
Amount realized on contracts entered into in 2004 and settled in 2005		(134	)
Changes in fair value of contracts entered into in 2004		—

Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		(26	)

Net fair value at end of year	$	(26	)

The $26,000 in recognized but unrealized net loss on these forward natural gas swap transactions marked-to-market on December 31, 2005 is expected to be realized on settlement in the first quarter of 2006.

We have minimal credit risk associated with the nonperformance or nonpayment by counterparties to these forward gas swap transactions as we have only one major counterparty to these transactions and this counterparty has a high investment grade credit rating.

The electric utility has market and credit risk associated with forward contracts for the purchase and sale of electricity. As of December 31, 2005 the electric utility had recognized, on a pretax basis, $2.9 million 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 by the electric utility’s power services’ personnel responsible for contract pricing and are benchmarked to regional hub prices as published in Megawatt Daily and as observed in the Intercontinental Exchange trading system. Of the forward energy contracts that are marked-to-market as of December 31, 2005, 91% of the forward purchases of electricity had offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward purchases of electricity not offset by forward sales of electricity as of December 31, 2005 was $269,000.

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, several changes were made to the 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, a Value at Risk (VaR) limit was also implemented to further manage market price risk. Exposure to price risk on any open positions as of December 31, 2005 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, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to December 31, 2005:


	December 31,
(in thousands)	2005

Current asset — marked-to-market gain	$	8,603
Regulatory asset — deferred marked-to-market loss		1,423

Total assets		10,026


Current liability — marked-to-market loss		(4,185	)
Regulatory liability — deferred marked-to-market gain		(2,925	)

Total liabilities		(7,110	)


Net fair value of marked-to-market energy contracts	$	2,916


	Year ended
(in thousands)	December 31, 2005

Fair value at beginning of year	$	301
Amount realized on contracts entered into in 2004 and settled in 2005		(322	)
Changes in fair value of contracts entered into in 2004		21

Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		2,916

Net fair value at end of year	$	2,916

The $2.9 million in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market on December 31, 2005 is expected to be realized on settlement as scheduled over the following quarters in the amounts listed:


	1st Quarter		2nd Quarter		3rd Quarter
(in thousands)	2006		2006		2006		Total

Net gain	$	2,281	$	527	$	108	$	2,916

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, 2005 was $2.3 million. As of December 31, 2005 we had a net credit risk exposure of $7.1 million from 13 counterparties with investment grade credit ratings.

The $7.1 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, 2005. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). There is no exposure at December 31, 2005 to counterparties with credit ratings below investment grade

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. 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 11 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.

Effective July 1, 2005 we remeasured our 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) used to measure obligations and determine 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.

The pension benefit cost for 2006 for our noncontributory funded pension plan is expected to be $5.0 million compared to $4.4 million in 2005. The estimated discount rate used to determine annual benefit cost accruals will increase to 5.75% in 2006 from a composite rate of 5.625% used in 2005. 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 2005, all other factors being held constant: a 0.25 increase (or decrease) in the discount rate would have decreased (or increased) our 2005 pension benefit cost by $550,000; a 0.25 increase (or decrease) in the assumed rate of increase in future compensation levels would have increased (or decreased) our 2005 pension benefit cost by $520,000; a 0.25 increase (or decrease) in the expected long-term rate of return on plan assets would have decreased (or increased) our 2005 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 2005 postretirement medical benefit costs by $105,000. See note 11 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, 2005 were $204 million.

Expected losses on jobs in progress at year-end 2005 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 energy services 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 by the electric utility’s power services’ personnel responsible for contract pricing and are benchmarked to regional hub prices as published in Megawatt Daily and as observed in the Intercontinental Exchange trading system and, as such, are estimates. Of the forward electric energy contracts that are marked-to-market as of December 31, 2005, 91% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward energy purchases that are not offset by forward energy sales as of December 31, 2005 was $269,000. All of the forward energy contracts for the purchase and sale of electricity marked-to-market as of December 31, 2005 are scheduled for settlement prior to September 1, 2006.

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 2005, $2.0 million of bad debt expense from continuing operations (0.19% of total 2005 revenue of $1.05 billion) was recorded and the allowance for doubtful accounts was $3.5 million (2.6% of trade accounts receivable) as of December 31, 2005. 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 receivables at December 31, 2005 would result in a $1.3 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 due largely 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 2.74% in 2005, 2.77% in 2004 and 3.07% in 2003. 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 that 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 tax positions that we have taken. While we believe the resulting tax reserve balances as of December 31, 2005 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, 2005 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, 2005 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. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, was issued in November 2004 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current-period charges. This statement also requires that allocation of fixed production overheads to the costs of converting materials into finished products be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. The early application of this standard did not have a material effect on our consolidated net income, financial position or cash flows.

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 APB Opinion No. 25, Accounting for Stock Issued to Employees. We currently report our stock-based compensation under the requirements of APB Opinion No. 25 and furnish related pro forma footnote information required under SFAS No. 123. Under SFAS No. 123(R), we will be required to record our 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. SFAS No.123(R) becomes effective, and was adopted by the company on a modified prospective basis, on January 1, 2006. The application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $160,000, net-of-tax, in 2006 for our currently outstanding non-vested stock options. Additionally, the application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $240,000, net-of-tax, in 2006 for the 15% discount offered under our Employee Stock Purchase Program (ESPP), if our shareholders approve the Board of Directors’ authorization of additional shares for the ESPP.

FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, is an interpretation of SFAS No. 143 on accounting for obligations associated with the retirement of tangible, long-lived assets. The revised guidance on conditional obligations is effective for fiscal years ending after December 15, 2005. The interpretation provides clarification and further guidance about when sufficient information exists to reasonably estimate the fair value of legal obligations in circumstances where uncertainty exists about the timing and (or) methods of settlement of a conditional asset retirement obligation. We evaluated our legal obligations in light of the additional guidance provided by this interpretation and determined that our previously recognized obligations did not change under this interpretation. However, we did determine that our transmission and distribution lines rights-of-way, including those with indeterminate lives, are not subject to the provisions of SFAS No. 143 because they are intangible assets. We also determined that there are no legal retirement obligations associated with structures using those rights-of-way.

SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, was issued in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement shall be effective and applied prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier application permitted. The early application of this standard did not have a material effect on our consolidated net income, financial position or cash flows.

SFAS No. 154, Accounting for Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in May 2005. This statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. We do not expect the application of the requirements of SFAS No. 154 to have a material effect on our consolidated net income, financial position or cash flows.

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, 2005. 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.

Management included Idaho Pacific Holdings, Inc. (IPH), acquired in August 2004, in its assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2005. IPH was not included in management’s assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2004 based on guidelines established by the Securities and Exchange Commission that allow newly acquired companies to be excluded from assessment in the year they are acquired. In connection with the implementation of MISO Day 2 markets in 2005, the Company implemented new processes and modified existing processes to facilitate participation in, and resultant settlements within the MISO market. Apart from these changes, there have not been any other changes in our 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, our internal control over financial reporting.

Based on this assessment, we believe that, as of December 31, 2005 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 our 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 20, 2006

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, 2005 and 2004, 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, 2005. 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, 2005, 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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, 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, 2005, 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, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 20, 2006

Otter Tail Corporation

Consolidated Statements of Income—For the Years Ended December 31


( in thousands, except per-share amounts)	2005			2004		2003
Operating revenues	$	1,046,408		$	857,362	$	724,288

Operating expenses
Production fuel		55,927			52,056		51,163
Purchased power — system use		58,828			40,098		36,002
Electric operation and maintenance expenses		99,904			85,361		87,186
Cost of goods sold (excludes depreciation; included below)		566,647			464,009		355,777
Other nonelectric expenses		110,004			86,542		72,624
Goodwill impairment loss		1,003			—		—
Depreciation and amortization		46,458			43,471		42,994
Property taxes — electric operations		10,043			10,411		9,598

Total operating expenses		948,814			781,948		655,344

Operating income		97,594			75,414		68,944

Other income		1,786			793		1,111
Interest charges		18,558			18,128		17,668

Income from continuing operations before income taxes		80,822			58,079		52,387
Income taxes — continuing operations		27,967			17,447		14,162

Net income from continuing operations		52,855			40,632		38,225
Discontinued operations
Income (loss) from discontinued operations net of taxes of $(221) in 2005, $1,040 in 2004 and $768 in 2003		(308	)		1,563		1,431
Net gain on disposition of discontinued operations net of taxes of $5,831 in 2005		10,004			—		—

Net income from discontinued operations		9,696			1,563		1,431


Net Income		62,551			42,195		39,656
Preferred dividend requirements		735			736		735

Earnings available for common shares	$	61,816		$	41,459	$	38,921

Average number of common shares outstanding—basic		29,223			26,089		25,673
Average number of common shares outstanding—diluted		29,348			26,207		25,826

Basic earnings per share:
Continuing operations (net of preferred dividend requirements)	$	1.79		$	1.53	$	1.46
Discontinued operations		0.33			0.06		0.06

	$	2.12		$	1.59	$	1.52

Diluted earnings per share:
Continuing operations (net of preferred dividend requirements)	$	1.78		$	1.52	$	1.45
Discontinued operations		0.33			0.06		0.06

	$	2.11		$	1.58	$	1.51

Dividends per common share	$	1.12		$	1.10	$	1.08

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets, December 31


(in thousands)	2005		2004
Assets

Current assets
Cash and cash equivalents	$	5,430	$	—
Accounts receivable:
Trade (less allowance for doubtful accounts of $3,493 for 2005 and $2,730 for 2004)		128,355		116,141
Other		11,790		9,872
Inventories		88,677		72,504
Deferred income taxes		6,871		4,852
Accrued utility revenues		22,892		15,344
Costs and estimated earnings in excess of billings		21,542		18,145
Other		17,301		7,800
Assets of discontinued operations		2,317		30,937

Total current assets		305,175		275,595


Investments and other assets		33,824		42,650
Goodwill—net		98,110		92,196
Other intangibles—net		21,160		19,600

Deferred debits
Unamortized debt expense and reacquisition premiums		6,520		7,291
Regulatory assets and other deferred debits		19,616		16,692

Total deferred debits		26,136		23,983

Plant
Electric plant in service		910,766		890,200
Nonelectric operations		228,548		208,311

Total		1,139,314		1,098,511
Less accumulated depreciation and amortization		459,438		436,856

Plant—net of accumulated depreciation and amortization		679,876		661,655
Construction work in progress		17,215		18,469

Net plant		697,091		680,124


Total	$	1,181,496	$	1,134,148

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets, December 31


(in thousands, except share data)	2005			2004
Liabilities and Equity

Current liabilities
Short-term debt	$	16,000		$	39,950
Current maturities of long-term debt		3,340			6,016
Accounts payable		106,570			84,433
Accrued salaries and wages		24,326			17,330
Accrued federal and state income taxes		8,776			3,700
Other accrued taxes		12,620			11,391
Other accrued liabilities		14,975			10,417
Liabilities of discontinued operations		372			8,585

Total current liabilities		186,979			181,822


Pension benefit liability		23,216			16,703
Other postretirement benefits liability		26,982			25,053
Other noncurrent liabilities		18,683			11,874

Commitments (note 8)

Deferred credits
Deferred income taxes		113,737			121,301
Deferred investment tax credit		9,327			10,477
Regulatory liabilities		61,624			56,909
Other		1,500			1,662

Total deferred credits		186,188			190,349


Capitalization (page 40)
Long-term debt, net of current maturities		258,260			261,805

Class B stock options of subsidiary		1,258			1,832

Cumulative preferred shares		15,500			15,500

Common shares, par value $5 per share—authorized, 50,000,000 shares; outstanding, 2005—29,401,223 shares; 2004—28,976,919 shares		147,006			144,885
Premium on common shares		96,768			87,865
Unearned compensation		(1,720	)		(2,577	)
Retained earnings		228,515			199,427
Accumulated other comprehensive loss		(6,139	)		(390	)

Total common equity		464,430			429,210

Total capitalization		739,448			708,347


Total	$	1,181,496		$	1,134,148

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, 2002		25,592,160		$	127,961		$	24,135		$	(1,946	)	$	175,304		$	(11,989	)	$	313,465

Common stock issuances		140,621			703			2,793			(2,477	)								1,019
Common stock retirements		(8,967	)		(45	)		(225	)											(270	)
Amortization of unearned compensation—stock awards											1,110									1,110
Comprehensive income:
Net income														39,656						39,656
Minimum pension liability adjustment																	7,560			7,560

Total comprehensive income																				47,216
Tax benefit for exercise of stock options								111												111
Purchase stock for employee purchase plan								(299	)											(299	)
Cumulative preferred dividends														(735	)					(735	)
Common dividends														(27,730	)					(27,730	)

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
Purchase 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)	(a)	$	464,430

(a) Accumulated other comprehensive loss on December 31, 2005 is comprised of the following:



(in thousands)	Before Tax			Tax Effect			Net-of-tax

Minimum pension liability adjustment	$	(12,588	)	$	5,035		$	(7,553	)
Foreign currency exchange translation		2,420			(968	)		1,452
Unrealized loss on marketable equity securities		(63	)		25			(38	)

Net accumulated other comprehensive loss	$	(10,231	)	$	4,092		$	(6,139	)

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows—For the Years Ended December 31


(in thousands)	2005			2004			2003
Cash flows from operating activities
Net income	$	62,551		$	42,195		$	39,656
Adjustments to reconcile net income to net cash provided by operating activities:
Net gain on sale of discontinued operations		(10,004	)		—			—
Loss (income) from discontinued operations		308			(1,563	)		(1,431	)
Depreciation and amortization		46,458			43,471			42,994
Deferred investment tax credit		(1,150	)		(1,152	)		(1,152	)
Deferred income taxes		(9,223	)		3,950			3,125
Change in deferred debits and other assets		9,868			(1,641	)		(3,173	)
Discretionary contribution to pension plan		(4,000	)		(4,000	)		—
Change in noncurrent liabilities and deferred credits		1,321			2,110			8,026
Allowance for equity (other) funds used during construction		(723	)		(716	)		(1,355	)
Change in derivatives net of regulatory deferral		(2,455	)		1,621			(2,057	)
Other—net		3,506			1,430			1,643
Cash (used for) provided by current assets and current liabilities:
Change in receivables		(13,482	)		(9,808	)		(19,137	)
Change in inventories		(12,500	)		(6,894	)		(12,619	)
Change in other current assets		(13,882	)		(15,386	)		(2,012	)
Change in payables and other current liabilities		36,021			1,679			18,624
Change in interest and income taxes payable		(2,256	)		(966	)		5,182

Net cash provided by continuing operations		90,358			54,330			76,314
Net cash provided by discontinued operations		5,442			1,971			641

Net cash provided by operating activities		95,800			56,301			76,955


Cash flows from investing activities
Capital expenditures		(59,969	)		(49,484	)		(48,783	)
Proceeds from disposal of noncurrent assets		4,193			5,844			1,563
Acquisitions—net of cash acquired		(11,223	)		(69,069	)		(12,896	)
Decreases (increases) in other investments		4,171			(5,099	)		1,071

Net cash used in investing activities – continuing operations		(62,828	)		(117,808	)		(59,045	)
Net proceeds from sale of discontinued operations		34,185			—			—
Net cash provided by (used in) investing activities – discontinued operations		602			(1,310	)		(1,363	)

Net cash used in investing activities		(28,041	)		(119,118	)		(60,408	)


Cash flows from financing activities
Change in checks written in excess of cash		(3,329	)		3,458			—
Net short-term (repayments) borrowings		(23,950	)		9,950			—
Proceeds from issuance of common stock, net of issuance expenses		9,690			78,780			1,072
Payments for retirement of common stock and Class B stock of subsidiary		(939	)		(349	)		—
Proceeds from issuance of long-term debt, net of issuance expenses		228			4,065			18,442
Payments for retirement of long-term debt		(7,232	)		(9,061	)		(8,189	)
Dividends paid		(33,463	)		(29,263	)		(28,937	)

Net cash (used in) provided by financing activities – continuing operations		(58,995	)		57,580			(17,612	)
Net cash used in financing activities – discontinued operations		(2,996	)		(1,679	)		(1,239	)

Net cash (used in) provided by financing activities		(61,991	)		55,901			(18,851	)

Effect of foreign exchange rate fluctuations on cash		(338	)		(794	)		—


Net change in cash and cash equivalents		5,430			(7,710	)		(2,304	)
Cash and cash equivalents at beginning of year – continuing operations		—			7,710			10,014

Cash and cash equivalents at end of year – continuing operations	$	5,430		$	—		$	7,710


Supplemental disclosures of cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)	$	17,670		$	16,443		$	16,563
Income taxes	$	39,212		$	16,204		$	7,956

Cash paid during the year from discontinued operations for:
Interest	$	86		$	111		$	218
Income taxes	$	659		$	840		$	481

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Capitalization, December 31


(in thousands, except share data)	2005		2004
Long-term debt
Lombard US Equipment Finance note, variable, 5.484% at December 31, 2005, due October 2, 2010	$	11,643	$	13,971
Senior debentures 6.375%, due December 1, 2007		50,000		50,000
Senior notes 6.63%, due December 1, 2011		90,000		90,000
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
Pollution control refunding revenue bonds, variable, 3.91% at December 31, 2005, due December 1, 2012		10,400		10,400
Grant County, South Dakota pollution control refunding revenue bonds 4.65%, due September 1, 2017		5,185		5,185
Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022		20,735		20,735
Obligations of Varistar Corporation:
8.15% five-year term note, retired in April 2005		—		540
7.80% ten-year term note, retired in July 2005		—		1,483
Various up to 9.65% at December 31, 2005		9,235		11,191


Total		262,198		268,505
Less:
Current maturities		3,340		6,016
Unamortized debt discount		598		684

Total long-term debt—continuing operations		258,260		261,805


Class B stock options of subsidiary		1,258		1,832


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		464,430		429,210


Total capitalization	$	739,448	$	708,347

See accompanying notes to consolidated financial statements.

Otter Tail Corporation
Notes to Consolidated Financial Statements
For the years ended December 31, 2005, 2004 and 2003

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 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 (AFC). AFC, a noncash item, is included in utility construction work in progress. The amount of AFC capitalized was $913,000 for 2005, $949,000 for 2004 and $1,970,000 for 2003. 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 2.74% in 2005, 2.77% in 2004 and 3.07% in 2003. Gains or losses on 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, 2005 and 2004 consolidated balance sheets:


	Big Stone			Coyote
(in thousands)	Plant			Station

December 31, 2005
Electric plant in service	$	124,852		$	146,405
Accumulated depreciation		(71,824	)		(77,909	)

Net plant	$	53,028		$	68,496


December 31, 2004
Electric plant in service	$	116,405		$	146,343
Accumulated depreciation		(70,904	)		(75,431	)

Net plant	$	45,501		$	70,912

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 and Emerging Issues Task Force (EITF) Issues 02-3 and 03-11. Gains and losses on forward energy contracts subject to regulatory treatment are deferred and recognized on a net basis in revenue in the period realized.

For those operating businesses recognizing revenue when shipped, the operating businesses 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. 149, 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.

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 related to dehydrated potato products 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)	2005			2004

Costs incurred on uncompleted contracts	$	194,076		$	99,213
Less billings to date		(203,862	)		(96,413	)
Plus estimated earnings recognized		22,834			12,469

	$	13,048		$	15,269

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)	2005			2004

Costs and estimated earnings in excess of billings on uncompleted contracts	$	21,542		$	18,145
Billings in excess of costs and estimated earnings on uncompleted contracts		(8,494	)		(2,876	)

	$	13,048		$	15,269

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. All sales of the Canadian operations are in U.S. dollars so there are no foreign currency transaction gains or losses on receivables to be reported in the Company’s consolidated statements of income. The functional currency for the Canadian subsidiary of DMI Industries, Inc., formed in November 2005, is the U.S. dollar. Therefore, 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 $2,074,000 as of December 31, 2005 and $1,632,000 as of December 31, 2004. 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.

Stock-Based Compensation—As described in note 6, the Company has elected to follow the accounting provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, for stock-based compensation and to furnish the pro forma disclosures required under SFAS No. 123, Accounting for Stock-Based Compensation.

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 2003 through 2005 would have decreased as presented in the table below. On January 1, 2006 the Company adopted SFAS No. 123(R), Share-Based Payment, which supersedes APB No. 25, on a modified prospective basis. Under SFAS No. 123(R), the estimated fair value of the options and other share-based payment plans, as determined on the award dates under SFAS No. 123, will be included in operating expense, net income and earnings per share beginning in 2006.


	2005			2004			2003
	(in thousands, except per share amounts)
Net income
As reported	$	62,551		$	42,195		$	39,656
Total stock-based employee compensation expense determined under fair value-based method for all awards net of related tax effects		(640	)		(1,087	)		(984	)

Pro forma	$	61,911		$	41,108		$	38,672

Basic earnings per share
As reported	$	2.12		$	1.59		$	1.52
Pro forma	$	2.09		$	1.55		$	1.48
Diluted earnings per share
As reported	$	2.11		$	1.58		$	1.51
Pro forma	$	2.08		$	1.54		$	1.47

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 benefit costs. 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—Certain prior year amounts reported on the Company’s consolidated balance sheet have been reclassified to conform to 2005 presentation. On the Company’s consolidated balance sheets, regulatory assets and other deferred debits, previously disclosed on separate lines, have been combined on a single line. The December 31, 2004 consolidated balance sheet and consolidated income statements for 2004 and 2003 reflect the reclassification of certain assets, liabilities and operations of both St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC) from continuing operations to discontinued operations as a result of the sales of these businesses in 2005. Such reclassifications had no impact on total consolidated assets, net income or shareholders’ equity.

On the Company’s consolidated statement of cash flows for the year ended December 31, 2004 the change in the amount of checks issued in excess of cash, included in accounts payable on the Company’s consolidated balance sheet, was reclassified from change in payables and other current liabilities under cash flows from operating activities to change in checks written in excess of cash under cash flows from financing activities. This reclassification decreased cash flows from operating activities of continuing operations and increased cash flows from financing activities of continuing operations by $3,458,000 for the year ended December 31, 2004.

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, 2005 and 2004:


	December 31,		December 31,
(in thousands)	2005		2004

Cost method:
Acquisition escrow account	$	—	$	6,017
Economic development loan pools		742		879
Other		1,913		1,743
Equity method:
Affordable housing partnerships		2,980		3,802
Marketable securities classified as available-for-sale		3,067		2,009

Total investments	$	8,702	$	14,450

The Company has investments in eleven limited partnerships that invest in tax-credit-qualifying affordable-housing projects that provided tax credits of $1,324,000 in 2005, $1,418,000 in 2004 and $1,412,000 in 2003. The Company owns a majority interest in eight of the eleven limited partnerships with a total investment of $2,400,000. FASB Interpretation 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 0.5% of the total assets of the Company.

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, 2005, with $38,000 in unrealized losses included in Accumulated other comprehensive loss in the equity section of the Company’s December 31, 2005 consolidated balance sheet. See further discussion under note 12.

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)	2005		2004

Finished goods	$	38,928	$	34,081
Work in process		7,146		3,733
Raw material, fuel and supplies		42,603		34,690

Total inventories	$	88,677	$	72,504

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, which eliminates the requirement to amortize goodwill and indefinite-lived intangible assets, requiring instead those assets 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.

The changes in the carrying amount of goodwill by segment are as follows:


			Adjustment to
	Balance		goodwill			Goodwill			Goodwill		Balance
	December 31,		acquired in			impairment			acquired		December 31,
(in thousands)	2004		2004			in 2005			in 2005		2005

Plastics	$	19,302	$	—		$	—		$	—	$	19,302
Manufacturing		9,680								6,018		15,698
Health services		24,582		(254	)							24,328
Food ingredient processing		23,087		1,153								24,240
Other business operations		15,545					(1,003	)				14,542

Total	$	92,196	$	899		$	(1,003	)	$	6,018	$	98,110

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 $1,077,000 for 2005, $701,000 for 2004 and $478,000 for 2003. The estimated annual amortization expense for these intangible assets for the next five years is: $1,022,000 for 2006, $901,000 for 2007, $758,000 for 2008, $636,000 for 2009 and $507,000 for 2010.

In light of rising natural gas prices and greater volatility in natural gas futures prices, the Company reassessed the value of recorded goodwill of its energy services subsidiary as of September 30, 2005, in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. As a result of this assessment, the Company determined the entire amount of goodwill related to this business was impaired and recorded a goodwill impairment loss of $1,003,000 in September 2005.

Total other intangibles as of December 31 are as follows:


	Gross carrying		Accumulated		Net carrying
	amount		amortization		amount
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


2004 (in thousands)
Amortized intangible assets:
Covenants not to compete	$	1,966	$	1,334	$	632
Customer relationships		10,045		148		9,897
Other intangible assets including contracts		2,523		1,387		1,136

Total	$	14,534	$	2,869	$	11,665

Nonamortized intangible assets:
Brand/trade name	$	7,935	$	—	$	7,935

The Company periodically evaluates the recovery of intangible assets based on an analysis of undiscounted future cash flows. Evaluations of intangible assets, including goodwill, completed in December 2005 indicated none of the intangible assets reported on the Company’s consolidated balance sheet as of December 31, 2005 is impaired.

New Accounting Pronouncements

SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, was issued in November 2004 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current-period charges. This statement also requires that allocation of fixed production overheads to the costs of converting materials into finished products be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. The early application of this standard by the Company did not have a material effect on its consolidated net income, financial position or cash flows.

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 APB Opinion No. 25, Accounting for Stock Issued to Employees. The Company currently reports stock-based compensation under the requirements of APB Opinion No. 25 and furnishes related pro forma footnote information required under SFAS No. 123. Under SFAS No. 123(R), the Company will be required to record its 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. SFAS No.123(R) becomes effective, and was adopted by the Company on a modified prospective basis, on January 1, 2006. The application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $160,000, net-of-tax, in 2006 for its currently outstanding non-vested stock options. Additionally, the application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $240,000, net-of-tax, in 2006 for the 15% discount offered under the Company’s Employee Stock Purchase Program (ESPP), if shareholders approve the Board of Directors’ authorization of additional shares for the ESPP. See note 6 for additional information.

FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, is an interpretation of SFAS No. 143 on accounting for obligations associated with the retirement of tangible, long-lived assets. The revised guidance on conditional obligations is effective for fiscal years ending after

December 15, 2005. The interpretation provides clarification and further guidance about when sufficient information exists to reasonably estimate the fair value of legal obligations in circumstances where uncertainty exists about the timing and (or) methods of settlement of a conditional asset retirement obligation. The Company evaluated its legal obligations in light of the additional guidance provided by this interpretation and determined that its previously recognized obligations did not change under this interpretation. However, the Company did determine that its transmission and distribution lines rights-of-way, including those with indeterminate lives, are not subject to the provisions of SFAS No. 143 because they are intangible assets. The Company also determined that it has no legal retirement obligations associated with structures using those rights-of-way.

SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, was issued in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement shall be effective and applied prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier application permitted. The early application of this standard by the Company did not have a material effect on its consolidated net income, financial position or cash flows.

SFAS No. 154, Accounting for Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in May 2005. This statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company does not expect the application of the requirements of SFAS No. 154 to have a material effect on the Company’s consolidated net income, financial position or cash flows.

2. Business Combinations, Dispositions and Segment Information

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. The Company expects this acquisition to provide 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 $1,000,000 for a nonamortizable brand name.

On August 18, 2004 the Company acquired all of the outstanding common stock of Idaho Pacific Holdings, Inc., (IPH) of 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 include $10.0 million for customer relationships being amortized over 25 years and a $3.2 million nonamortizable trade name.

On November 1, 2003 the Company acquired the assets and operations of Foley Company (Foley) for $12.3 million in cash. Foley is a mechanical and prime contracting firm based in Kansas City, Missouri, that provides a range of specialty contracting including design-and-build services for new construction, retrofitting, process piping, equipment settings, and instrumentation and control systems. Major clients include water and wastewater treatment plants, hospital and pharmaceutical facilities, power generation plants, and other industrial and manufacturing projects across a multi-state service area. This acquisition expanded the Company’s construction services to a broader geographic region. Foley is included in the other business operations segment.

In 2003, the Company also acquired Topline Medical, Inc., and North Star Medical Systems, Inc. The aggregate price paid for these companies was $1.9 million in cash. These acquisitions allowed the health services segment to increase sales opportunities with an expanded line of products.

Below is a condensed balance sheet disclosing the final allocation of the purchase price assigned to each major asset and liability category for the companies acquired in 2003.


(in thousands)	Foley		Others

Assets
Current assets	$	9,847	$	675
Plant		3,793		45
Goodwill		7,319		1,924
Other intangible assets		1,653		102

Total assets	$	22,612	$	2,746


Liabilities
Current liabilities	$	8,618	$	669
Long-term debt		—		136
Other long-term liabilities		1,712		—

Total liabilities	$	10,330	$	805

Cash paid	$	12,282	$	1,941

Goodwill related to the Foley acquisition is not deductible for income tax purposes. The goodwill related to the other 2003 acquisitions is deductible for income tax purposes over 15 years. Other intangible assets related to the Foley acquisition include a $1.1 million nonamortizable trade name and $553,000 in intangible assets being amortized over five years. Other intangible assets

related to the other acquisitions are being amortized over four years.

All of the acquisitions described above were accounted for using the purchase method of accounting. The pro forma effect of these acquisitions on 2005, 2004 and 2003 revenues, net income or earnings per share was not significant.

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. Electric utility operations have been the Company’s primary business since incorporation.

Plastics consist 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 are located primarily in the Upper Midwest and Missouri.

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 service maintenance, diagnostic imaging, positron emission tomography and nuclear medicine imaging, portable X-ray imaging 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, producing 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 involved in residential, commercial and industrial electric contracting industries; fiber optic and electric distribution systems; waste-water, water and HVAC systems construction; transportation; energy services and natural gas marketing; and 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 six Canadian provinces.

The Company’s electric operations, including wholesale power sales, are operated as a division of Otter Tail Corporation, and the Company’s energy services and natural gas marketing operations are operated as a subsidiary of Otter Tail Corporation. Substantially all of the other businesses are owned by a wholly-owned subsidiary of the Company.

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 2005, 2004 and 2003 is presented in the following table.


	2005			2004			2003
	(in thousands)
Operating revenue
Electric	$	312,985		$	266,385		$	267,494
Plastics		158,548			115,426			86,009
Manufacturing		244,311			201,615			157,401
Health services		123,991			114,318			100,912
Food ingredient processing		38,501			14,023			—
Other business operations		171,939			148,328			114,726
Intersegment eliminations		(3,867	)		(2,733	)		(2,254	)

Total	$	1,046,408		$	857,362		$	724,288


Depreciation and amortization
Electric	$	24,397		$	24,236		$	26,008
Plastics		2,511			2,297			2,126
Manufacturing		9,447			7,828			6,882
Health services		4,038			5,047			5,137
Food ingredient processing		3,399			1,118			—
Other business operations		2,666			2,945			2,841

Total	$	46,458		$	43,471		$	42,994


Income before income taxes
Electric	$	55,984		$	45,234		$	48,689
Plastics		22,803			9,453			3,341
Manufacturing		12,242			12,543			6,904
Health services		6,875			5,075			4,197
Food ingredient processing		1,482			618			—
Other business operations		(18,564	)		(14,844	)		(10,744	)

Total	$	80,822		$	58,079		$	52,387


Earnings available for common shares
Electric	$	36,566		$	30,799		$	33,411
Plastics		13,936			5,657			2,019
Manufacturing		7,589			7,563			4,495
Health services		4,007			2,951			2,464
Food ingredient processing		329			351			—
Other business operations		(10,307	)		(7,425	)		(4,899	)

Total	$	52,120		$	39,896		$	37,490


Capital expenditures
Electric	$	30,479		$	25,368		$	28,177
Plastics		3,636			2,544			3,984
Manufacturing		16,112			13,163			9,592
Health services		3,095			3,919			5,427
Food ingredient processing		2,952			3,528			—
Other business operations		3,695			962			1,603

Total	$	59,969		$	49,484		$	48,783


Identifiable assets
Electric	$	654,175		$	634,433		$	609,190
Plastics		76,573			67,574			58,538
Manufacturing		177,969			150,800			125,877
Health services		67,066			66,506			67,587
Food ingredient processing		96,023			92,392			—
Other business operations		107,373			91,506			95,350
Discontinued operations		2,317			30,937			29,881

Total	$	1,181,496		$	1,134,148		$	986,423

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:


	2005			2004			2003

United States of America		97.9	%		97.1	%		100.0	%
Canada		1.0	%		2.1	%		—
All other countries		1.1	%		0.8	%		—

3. Rate Matters

On December 29, 2000 the North Dakota Public Service Commission (NDPSC) approved a performance-based ratemaking plan that links allowed earnings in North Dakota to seven defined performance standards in the areas of price, electric service reliability, customer satisfaction and employee safety. The plan was in place through 2005. This plan provided the opportunity for the electric utility to raise its allowed rate of return and share income with customers when earnings exceed the allowed return. The electric utility’s 2005 rate of return is expected to be within the allowable range defined in the plan. The electric utility’s 2004 and 2003 rates of return were within the allowable range defined in the plan. The performance-based ratemaking plan expired on December 31, 2005. While the electric utility has applied to the NDPSC for a three year extension with certain modifications, the NDPSC has taken no action on the application.

The Energy Policy Act of 2005 (the 2005 Energy Act) was signed into law in August 2005. The 2005 Energy Act is comprehensive legislation that will substantially affect the regulation of energy companies. 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.

	•		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.

	•		The Price Anderson Amendments Act of 1988, which provides the framework for nuclear liability protection, will be extended by 20 years to 2025.

	•		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.

In a letter from the FERC Office of Market Oversight and Investigations (OMOI) dated September 27, 2005 Otter Tail Power Company was informed that the Division of Operation Audits of the OMOI would be commencing an audit of Otter Tail Power Company. The purpose of the audit is to determine whether and how the Company’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 Company’s waivers from the requirements of Order No. 889 and Order No. 2004 restricts access to transmission information that would benefit the Company’s off-system sales. The audit will cover the period from January 1, 2003 through August 31, 2005. This is a routine audit to which all FERC jurisdictional utilities are subject. FERC has been conducting audits of this nature since Order No. 889 was issued and more since the implementation of Order No. 2004 (FERC’s Standards of Conduct Order). The audit is expected to take approximately six months to complete. The Company believes it is in compliance with applicable FERC rules, regulations and tariff requirements related to the audit. Given the preliminary nature of this audit, the Company is not able to determine whether the audit will result in any material changes to the Company’s operations or have any material effect on the Company’s consolidated net income, financial position or cash flows.

On November 30, 2004, Otter Tail Power Company filed a report with the Minnesota Public Utilities Commission (MPUC) responding to claims of allegedly improper regulatory filings brought to the attention of the Company by certain

individuals. In 2005, the Energy Division of the Minnesota Department of Commerce, 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 is expected to be scheduled in March 2006. The Company cannot predict whether the results of the hearing will have any impact on the Company’s consolidated net income, financial position or cash flows.

In December 2005, the MPUC issued an order denying the 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 electric utility to reflect the refund obligation. On February 9, 2006 the MPUC reconsidered its December 2005 order. On reconsideration, the MPUC 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 possible recovery through base rates in the electric utility’s next general rate case. The MPUC’s final written order of this action is pending. When the final order is issued, the electric utility will recognize the $1.9 million in revenue and reverse the refund payable.

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)	2005		2004

Regulatory assets:
Deferred income taxes	$	16,724	$	14,526
Reacquisition premiums		2,995		3,424
Deferred conservation program costs		1,064		1,203
Plant acquisition costs		196		240
Deferred marked-to-market losses		1,423		331
Accrued cost-of-energy revenue		10,400		3,348
Accumulated ARO accretion/depreciation adjustment		209		114

Total regulatory assets	$	33,011	$	23,186

Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	52,582	$	49,823
Deferred income taxes		5,961		6,727
Deferred marked-to-market gains		2,925		197
Gain on sale of division office building		156		162

Total regulatory liabilities	$	61,624	$	56,909

Net regulatory liability position	$	28,613	$	33,723

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. 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 16.6 years. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. Plant acquisition costs will be amortized over the next 4.4 years. Accrued cost-of-energy revenue included in Accrued utility revenues will be recovered over the next nine months. All deferred marked-to-market gains and losses are related to forward purchases and sales of energy scheduled for delivery prior to September 2006. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. 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

With the issuance of SFAS No. 149 in 2003, 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 $46,397,000 in 2005, $27,228,000 in 2004 and $29,702,000 in 2003 related to wholesale electric sales and net unrealized derivative gains on forward energy contracts and, in 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)	2005			2004			2003
Wholesale sales — company–owned generation	$	24,799		$	17,970		$	18,600


Revenue from settled contracts at market prices		474,882			134,715			121,303
Market cost of settled contracts		(457,728	)		(128,685	)		(114,259	)

Net margins on settled contracts at market		17,154			6,030			7,044


Marked-to-market gains on settled contracts		11,118			12,663			2,978
Marked-to-market losses on settled contracts		(9,590	)		(9,736	)		(977	)

Net marked-to-market gain on settled contracts		1,528			2,927			2,001


Unrealized marked-to-market gains on open contracts		5,678			514			6,338
Unrealized marked-to-market losses on open contracts		(2,762	)		(213	)		(4,281	)

Net unrealized marked-to-market gain on open contracts		2,916			301			2,057

Wholesale electric revenue	$	46,397		$	27,228		$	29,702

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)	2005			2004

Current asset – marked-to-market gain	$	8,603		$	711
Regulatory asset – deferred marked-to-market loss		1,423			331

Total assets		10,026			1,042


Current liability – marked-to-market loss		(4,185	)		(544	)
Regulatory liability – deferred marked-to-market gain		(2,925	)		(197	)

Total liabilities		(7,110	)		(741	)


Net fair value of marked-to-market energy contracts	$	2,916		$	301


	Year ended
	December 31,
(in thousands)	2005

Fair value at beginning of year	$	301
Amount realized on contracts entered into in 2004 and settled in 2005		(322	)
Changes in fair value of contracts entered into in 2004		21

Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		2,916

Net fair value at end of year	$	2,916

The $2,916,000 in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market as of December 31, 2005 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		3rd Quarter
(in thousands)	2006		2006		2006		Total

Net gain	$	2,281	$	527	$	108	$	2,916

Of the forward energy contracts that are marked-to-market as of December 31 2005, 91% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward energy purchases that are not offset by forward energy sales is $269,000.

Natural Gas Contracts

The Company’s energy services subsidiary markets natural gas to approximately 160 retail customers. Some of these customers are served under fixed-price contracts. These contracts call for the physical delivery of natural gas and are considered executory contracts for accounting purposes. Current accounting guidance requires losses on firmly committed executory contracts to be recognized when realized.

The Company’s energy services subsidiary first entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133 in 2004. Although the energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on the Company’s consolidated statements of income for the years ended December 31, 2005 and 2004 in accordance with the guidance provided in EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. The Company’s intent in entering into these forward natural gas swap transactions is to make a profit on the change in prices of natural gas contracted for future delivery.

The following table provides a breakdown of the energy services subsidiary’s natural gas swap transactions trading activity in 2005 and 2004:


(in thousands)	2005			2004

Gains on settled contracts	$	17,685		$	780
Losses on settled contracts		(18,161	)		(747	)

Net (loss) gain on settled contracts		(476	)		33

Unrealized gains on open contracts		825			1,834
Unrealized losses on open contracts		(851	)		(1,700	)

Net unrealized (loss) gain on open contracts		(26	)		134

Net revenue recognized	$	(502	)	$	167

The following tables show the effect of marking-to-market the energy services subsidiary’s forward natural gas swap transactions on the consolidated balance sheets:


	December 31,			December 31,
(in thousands)	2005			2004

Current asset — marked-to-market gain	$	825		$	1,834
Current liability — marked-to-market loss		(851	)		(1,700	)

Net fair value of marked-to-market gas contracts	$	(26	)	$	134


	Year ended
	December 31,
(in thousands)	2005

Fair value at beginning of year	$	134
Amount realized on contracts entered into in 2004 and settled in 2005		(134	)
Changes in fair value of contracts entered into in 2004		—

Net fair value of contracts entered into in 2004 at year end 2005		—
Changes in fair value of contracts entered into in 2005		(26	)

Net fair value at end of year	$	(26	)

6. Common Shares and Earnings Per Share

New Issuances— In January 2005, 175,000 common shares were issued as a result of the underwriters exercising a portion of their over-allotment option in connection with the Company’s December 2004 public offering. The proceeds to the Company of $24.50 per share were used to pay down debt borrowed to finance the acquisition of IPH. Also in 2005, the Company issued 258,096 common shares as a result of stock option exercises, 20,700 restricted common shares for officers’ and directors’ compensation and 2,415 common shares as directors’ compensation.

In 2005, the Company retired 14,547 common shares for tax withholding purposes in connection with the vesting of restricted common shares, 240 restricted common shares that were forfeited prior to vesting, and 17,120 common shares related to the return of stock to the Company that was held in escrow for performance contingencies that were not achieved in a health services acquisition.

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. The Company’s Board of Directors authorized an additional 1,000,000 common shares for the Incentive Plan and extended the term of the Incentive Plan from December 13, 2008 to December 13, 2013 subject to shareholder approval in April 2006.

The exercise price of the stock options is equal to the fair market value per share at the date of the grant. Options granted to non-employee directors are exercisable immediately and all other options granted prior to 2004 vest over a four-year period. Stock options granted in 2004 and 2005 vested six months from the grant date. Options expire ten years after the date of the grant. Restricted stock awards outstanding as of December 31, 2005 vest ratably over a four-year period. The Company accounted for the Incentive Plan under APB No. 25 through December 31, 2005, but adopted the accounting requirements of SFAS No. 123(R) for the Incentive Plan on a modified prospective basis on January 1, 2006. See New Accounting Pronouncements under note 1.

Presented below is a summary of the stock options activity:


Stock Option Activity	2005				2004				2003
			Average				Average				Average
			exercise				exercise				exercise
	Options		price		Options		price		Options		price
Outstanding, beginning of year		1,508,277	$	25.35		1,531,125	$	25.16		1,360,721	$	24.68
Granted		74,900		24.93		72,400		26.50		222,750		27.24
Exercised		257,948		22.90		51,468		19.83		47,700		20.21
Forfeited		88,065		28.79		43,780		27.37		4,646		23.09

Outstanding, year end		1,237,164		25.58		1,508,277		25.35		1,531,125		25.16

Exercisable, year end		1,095,272		25.16		1,111,681		24.27		791,661		22.97

Fair value of options granted during year	$	4.76			$	5.27			$	5.42

The fair values of the options granted were estimated using the Black-Scholes option-pricing model under the following assumptions:


	2005			2004			2003
Risk-free interest rate		4.3	%		3.9	%		3.7	%
Expected lives	7 years			7 years			7 years
Expected volatility		25.4	%		25.7	%		26.3	%
Dividend yield		4.4	%		4.0	%		4.0	%

The following table summarizes information about options outstanding as of December 31, 2005:


	Options outstanding						Options exercisable
			Weighted-
			average		Weighted-				Weighted-
	Outstanding		remaining		average		Exercisable		average
Range of	as of		contractual		exercise		as of		exercise
exercise prices	12/31/05		life (yrs)		price		12/31/05		price

$18.80-$21.94		308,890		3.7	$	19.48		308,890	$	19.48
$21.95-$25.07		66,400		9.3	$	24.93		66,400	$	24.93
$25.08-$28.21		624,250		6.1	$	26.54		536,750	$	26.42
$28.22-$31.34		237,624		6.1	$	31.21		183,232	$	31.17

See note 1 for pro forma stock option information.

In addition to the stock options granted, 20,700, 21,340 and 90,900 shares of restricted stock were granted during 2005, 2004 and 2003, respectively. The total compensation cost recognized in income for the restricted stock awards was $1,379,000 in 2005, $1,302,000 in 2004 and $1,110,000 in 2003.

The Company’s Board of Directors has approved performance award agreements under the Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded common shares 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. A summary of activity under the performance award agreements as of and for the years ended December 31, 2005 and 2004 is as follows:


	Maximum		Amount of shares		Amount of
	shares		expected to be awarded		expense during
Performance	subject		based on current		the years ended
Period	to award		stock performance		December 31,
					2005		2004

2005-2007		75,150		50,872	$	490,000		—
2004-2006		70,500		23,500	$	453,000		—

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 lower market price at either the beginning or the end of each six-month purchase period. Starting in 2006, the purchase price of common shares under the

Purchase Plan will be 85% of the market price at the end of each six-month purchase period. Of the 400,000 common shares authorized for purchase under the Purchase Plan, 2,961 were still available for purchase as of December 31, 2005. To provide shares for the Purchase Plan, 69,401 common shares were purchased in the open market in 2005, 66,958 common shares were issued in 2004 and 66,724 common shares were purchased in the open market in 2003. The Company’s Board of Directors authorized an additional 500,000 common shares for the Purchase Plan subject to shareholder approval in April 2006.

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, 2005, 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. Each Right entitles the holder to purchase from the Company one one-hundredth of a share of newly created Series A Junior Participating Preferred Stock at a price of $70, subject to certain adjustments. The Rights are exercisable when, and are not transferable apart from the Company’s common shares until, a person or group has acquired 15% or more, or commenced a tender or exchange offer for 15% or more, of the Company’s common shares. If the specified percentage of the Company’s common shares is acquired, each Right will entitle the holder (other than the acquiring person or group) to receive, on exercise, common shares of either the Company or the acquiring company having value equal to two times the exercise price of the Right. The Rights are redeemable by the Company’s Board of Directors in certain circumstances and expire on January 27, 2007.

Earnings Per Share—Basic earnings per common share are calculated by dividing earnings available for common shares by the 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.

7. 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, 2005.

8. Commitments and Contingencies

At December 31, 2005 the electric utility had commitments under contracts in connection with construction programs aggregating approximately $4,417,000. For capacity and energy requirements, the electric utility has agreements extending through 2010 at annual costs of approximately $16,957,000 in 2006, $16,359,000 in 2007, $16,339,000 in 2008, $16,358,000 in 2009 and $7,954,000 in 2010.

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 $83,981,000 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.

The Company’s wind tower manufacturer has commitments totaling $37,909,000 for the purchase of steel plates in 2006 to be used in the construction of towers that are scheduled for delivery in 2006 and 2007.

The amounts of future operating lease payments are as follows:


	Electric		Nonelectric		Total
			(in thousands)
2006	$	1,980	$	35,301	$	37,281
2007		1,699		30,172		31,871
2008		1,243		25,688		26,931
2009		1,243		22,374		23,617
2010		1,243		12,125		13,368
Later years		497		2,705		3,202

Total	$	7,905	$	128,365	$	136,270

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 $37,798,000, $28,061,000 and $25,205,000, for 2005, 2004 and 2003, 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, 2005 will not be material.

9. Short-Term and Long-Term Borrowings

Short-Term Debt— As of December 31, 2005 the Company had $16 million in short-term debt outstanding at an interest rate of 4.8%. As of December 31, 2004 the Company had $39,950,000 in short-term debt outstanding, of which $35,000,000 was borrowed against the Company’s line of credit and $4,950,000 was the remaining unpaid balance on a bridge loan used to finance the 2004 acquisition of IPH. As of December 31, 2004 the composite interest rate on the line borrowings was 2.8% and the interest rate on the bridge loan was 3.0%. The average interest rate paid on short-term debt was 3.7% in 2005 and 2.2% in 2004.

In August 2004, the Company borrowed $76.0 million of unsecured and unsubordinated debt from UBS Loan Finance LLC as a bridge loan to finance its acquisition of IPH. The Company repaid $71,050,000 of the $76.0 million loan in December 2004 with net proceeds from the issuance of 2.9 million shares of common stock in a public offering. The remaining unpaid balance of $4,950,000, outstanding on December 31, 2004, was repaid in January 2005 from the proceeds of 175,000 shares of common stock issued as a result of the underwriters exercising a portion of their over-allotment in connection with the public offering and by borrowing from the Company’s line of credit. The interest rate paid on the outstanding balance on the bridge loan was 3.0%.

On April 27, 2005 the Company renewed its line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., and increased the amount available under the line from $70 million to $100 million. The renewed agreement expires on April 26, 2006. 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 $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements through April 2006 will be provided for by cash flows from electric utility operations. As of December 31, 2005, $16.0 million of the $100 million line of credit in place at that date was in use and $12.0 million was restricted from use to cover outstanding letters of credit. The Company does not anticipate any difficulties in renewing this line of credit.

The interest rate under the line of credit is subject to adjustment in the event of a change in ratings on the Company’s senior unsecured debt, up to LIBOR plus 0.8% if the ratings on the Company’s senior unsecured debt fall to BBB+ or below (Standard & Poor’s) or Baa1 or below (Moody’s). On August 26, 2005 Moody’s Investors Service lowered its ratings of the Company’s senior unsecured debt from A2 to A3 and changed its outlook from negative to stable. On December 22, 2005 Standard & Poor’s Rating Services changed its outlook on the Company’s senior unsecured debt from negative to stable. No changes were made to its ratings of

the Company’s senior unsecured debt which has a rating of BBB+. These rating changes did not affect the interest rate on the line of credit which remained at LIBOR plus 0.6%.

The Company’s 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. The Company’s obligations under this line of credit are guaranteed by a 100%-owned subsidiary of the Company that owns substantially all of the Company’s nonelectric companies.

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 2005 or 2004.

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 2, 2006, the stated maturity date of the note. The term of the note can be extended for additional one-year periods following the stated maturity date through October 1, 2010. The note bears interest at a variable rate of three-month LIBOR plus 1.43% on the unpaid principal balance with interest payments due quarterly. The covenants associated with the note are consistent with existing credit facilities. There are no rating triggers associated with this note.

On November 3, 2004 a Second Amendment to the Note Purchase Agreement dated as of December 31, 2001 for the $90 million 6.63% senior notes due December 1, 2011 between Otter Tail Corporation and the holders of the notes was signed and made effective as of October 1, 2004. This amendment eliminated the provision that would require repayment of the $90 million senior notes with a make-whole premium if the Company’s senior unsecured debt is rated below Baa3 (Moody’s) or BBB- (Standard & Poor’s). The amendment resulted in no changes to interest rates and no material changes to other terms of the agreement. The Company’s obligations under the 6.63% senior notes are guaranteed by a 100%-owned subsidiary of the Company that owns substantially all of the Company’s nonelectric companies.

The Company’s Grant County and Mercer County pollution control refunding revenue bonds require the Company grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, 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).

The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2005 for each of the next five years are $3,340,000 for 2006, $54,896,000 for 2007, $3,006,000 for 2008, $2,904,000 for 2009 and $2,568,000 for 2010.

Covenants—The Company’s line of credit, its $90 million 6.63% senior notes due 2011 and Lombard US Equipment Finance note contain covenants that require the Company to maintain 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 these financing agreements as of December 31, 2005.

10. 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, 2005 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	$	102.70

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 non-voting, 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. Total cash paid to IPH on exercise of the options and issuance of the Class B common shares was $171,000. The Class B common shares were redeemed by IPH 181 days after issuance and prior to December 31, 2005 for $745,000, the value of the shares on the date of issuance. The combined exercise price of the remaining 755 options outstanding on December 31, 2005 was $316,000.

11. Pension Plan and Other Postretirement Benefits

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. 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.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations and fair value of assets over the two-year period ended December 31, 2005 and a statement of the funded status as of December 31 of both years:


	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	166,190		$	154,159
Service cost		4,695			4,063
Interest cost		9,721			9,458
Benefit payments		(8,567	)		(8,600	)
Plan amendments		222			—
Actuarial loss		9,326			7,110

Obligation at December 31	$	181,587		$	166,190


Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1	$	141,685		$	132,811
Actual return on plan assets		9,864			13,474
Discretionary company contributions		4,000			4,000
Benefit payments		(8,567	)		(8,600	)

Fair value of plan assets at December 31	$	146,982		$	141,685


Funded status	$	(34,605	)	$	(24,505	)
Unrecognized net actuarial loss		38,777			28,607
Unrecognized prior service cost		5,623			6,127

Net amount recognized	$	9,795		$	10,229

The following table provides the amounts recognized in the consolidated balance sheets as of December 31:


	2005			2004
	(in thousands)
Prepaid pension cost	$	9,795		$	10,229
Additional minimum liability		(13,380	)		—

Net pension asset/(liability)	$	(3,585	)	$	10,229
Intangible asset		5,623			—
Accumulated other comprehensive loss		7,757			—

Net amount recognized	$	9,795		$	10,229

Additional information on the status of the pension plan as of December 31:


	2005		2004
	(in thousands)
Projected benefit obligation	$	181,587	$	166,190
Accumulated benefit obligation		150,567		137,682
Fair value of plan assets		146,982		141,685

Components of net periodic pension benefit cost:


	2005			2004			2003
	(in thousands)
Service cost—benefit earned during the period	$	4,695		$	4,063		$	3,779
Interest cost on projected benefit obligation		9,721			9,458			9,491
Expected return on assets		(12,071	)		(12,438	)		(12,933	)
Amortization of prior-service cost		726			897			1,170
Amortization of net actuarial loss		1,364			—			—

Net periodic pension cost	$	4,435		$	1,980		$	1,507

The change in the additional minimum liability included in Accumulated other comprehensive loss was $7,757,000 in 2005 and $0 in 2004.

Weighted-average assumptions used to determine benefit obligations at December 31:


	2005			2004
Discount rate		5.75	%		6.00	%
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:


	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%
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.

The assumed rate of return on pension fund assets for the determination of 2006 net periodic pension cost is 8.5%.

The Company’s pension plan asset allocations at December 31, 2005 and 2004, by asset category are as follows:


Asset Allocation	2005			2004
Large capitalization equity securities		51.2	%		48.4	%
Small capitalization equity securities		11.4	%		11.2	%
International equity securities		9.8	%		14.7	%

Total equity securities		72.4	%		74.3	%
Cash and fixed-income securities		27.6	%		25.7	%

		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.


Asset Allocation	Strategic Target	Tactical 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%

Cash Flows

The Company is not required to make a contribution to the pension plan in 2006.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$8,601	$	8,687	$	8,834	$	9,013	$	9,183	$	52,747

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.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations over the two-year period ended December 31, 2005 and a statement of the funded status as of December 31 of both years:


	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	23,123		$	24,451
Service cost		406			820
Interest cost		1,267			1,489
Plan amendments		(663	)		—
Actuarial loss (gain)		232			(2,543	)
Benefit payments		(1,094	)		(1,094	)
Obligation at December 31	$	23,271		$	23,123

Funded status:
Funded status at December 31	$	(23,271	)	$	(23,123	)
Unrecognized prior-service cost		891			1,626
Unrecognized net actuarial loss		8,471			8,737
Net amount recognized	$	(13,909	)	$	(12,760	)

The following table provides the amounts recognized in the consolidated balance sheets as of December 31:


	2005			2004
	(in thousands)
Accrued benefit liability	$	(19,631	)	$	(16,703	)
Intangible asset		891			1,626
Accumulated other comprehensive loss		4,831			2,317

Net amount recognized	$	(13,909	)	$	(12,760	)

Additional information on the ESSRP defined benefit pension plan as of December 31:


	2005		2004
	(in thousands)
Projected benefit obligation	$	23,271	$	23,123
Accumulated benefit obligation		19,631		16,703
Fair value of plan assets		—		—

Components of net periodic pension benefit cost:


	2005		2004		2003
	(in thousands)
Service cost—benefit earned during the period	$	406	$	820	$	417
Interest cost on projected benefit obligation		1,267		1,489		1,426
Amortization of prior-service cost		71		147		147
Recognized net actuarial loss		498		680		573

Total	$	2,242	$	3,136	$	2,563

The change in the additional minimum liability included in Accumulated other comprehensive loss was $2,514,000 in 2005 and ($2,112,000) in 2004.


Weighted-average assumptions used to determine benefit obligations at December 31:	2005			2004
Discount rate		5.75	%		6.00	%
Rate of increase in future compensation level		4.69	%		4.69	%


Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%
Rate of increase in future compensation level		4.69	%		5.88	%

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:


(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$1,132	$	1,128	$	1,114	$	1,120	$	1,116	$	6,326

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.


	2005			2004
	(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1	$	39,639		$	42,008
Service cost		1,172			1,133
Interest cost		1,998			2,271
Benefit payments		(3,112	)		(3,449	)
Participant premium payments		1,320			1,134
Decrease due to Medicare Part D subsidy		—			(4,935	)
Actuarial (gain) loss		(4,260	)		1,477

Obligation at December 31	$	36,757		$	39,639


Funded status:
Funded status at December 31	$	(36,757	)	$	(39,639	)
Unrecognized transition obligation		5,237			5,985
Unrecognized prior-service cost		1,310			1,005
Unrecognized loss		3,228			7,596

Net amount recognized	$	(26,982	)	$	(25,053	)

The net amounts recognized are shown on the consolidated balance sheets as of December 31, 2005 and 2004 under Other postretirement benefits liability.

Components of net periodic postretirement benefit cost:


	2005			2004			2003
	(in thousands)
Service cost	$	1,307		$	1,170		$	1,009
Interest cost		2,480			2,580			2,619
Amortization of transition obligation		748			748			748
Amortization of prior-service cost		(305	)		(305	)		(305	)
Amortization of net loss		742			702			708
Expense decrease due to Medicare Part D subsidy		(1,251	)		(757	)		—

Net periodic postretirement benefit cost	$	3,721		$	4,138		$	4,779


Weighted-average assumptions used to determine benefit obligations at December 31:	2005			2004
Discount rate		5.75	%		6.00	%


Weighted-average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:	2005			2004
Discount rate (2005 is remeasurement composite rate)		5.625	%		6.25	%

Assumed healthcare cost-trend rates as of December 31:


	2005			2004
Healthcare cost-trend rate assumed for next year		9.0	%		10.0	%
Rate at which the cost-trend rate is assumed to decline		5.0	%		5.0	%
Year the rate reaches the ultimate trend rate		2010			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 2005 would have the following effects:


	1 point		1 point
	increase		decrease
	(in thousands)
Effect on total of service and interest cost	$	516	$	(415	)
Effect on the postretirement benefit obligation	$	4,574	$	(3,808	)

Cash Flows

The Company expects to contribute $2.4 million net of expected employee contributions for the payment of retiree medical benefits in 2006. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


(in thousands)									Years
2006	2007		2008		2009		2010		2011-2015
$2,380	$	2,488	$	2,549	$	2,610	$	2,593	$	14,127

The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $350,000 in 2006.

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 $830,000 for 2005, $930,000 for 2004 and $1,030,000 for 2003.

12. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Other Investments—The carrying amount approximates fair value. A portion of other investments is in financial instruments that have variable interest rates that reflect fair value. The remainder of other investments is accounted for by the equity method which, in the case of operating losses, results in a reduction of the carrying amount.

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 $22.0 million of the Company’s long-term debt, which is subject to variable interest rates, approximates fair value.


	December 31, 2005						December 31, 2004
	(in thousands)
	Carrying			Fair			Carrying			Fair
	amount			value			amount			value
Cash and short-term investments	$	5,430		$	5,430		$	—		$	—
Other investments		8,702			8,702			14,450			14,450
Long-term debt		(258,260	)		(273,456	)		(261,805	)		(294,020	)

13. Property, Plant and Equipment


	2005		2004
	(December 31, in thousands)
Electric plant:
Production	$	357,285	$	347,800
Transmission		182,502		180,150
Distribution		296,301		285,253
General		74,678		76,997

Electric plant		910,766		890,200
Less accumulated depreciation and amortization		374,786		363,696

Electric plant net of accumulated depreciation		535,980		526,504
Construction work in progress		12,449		12,212

Net electric plant	$	548,429	$	538,716


Nonelectric operations plant	$	228,548	$	208,311
Less accumulated depreciation and amortization		84,652		73,160

Nonelectric plant net of accumulated depreciation		143,896		135,151
Construction work in progress		4,766		6,257

Net nonelectric operations plant	$	148,662	$	141,408

Net plant	$	697,091	$	680,124

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

14. Income Taxes

The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2005, 2004 and 2003) to net income before total income tax expense for the following reasons:


	2005			2004			2003
	(in thousands)
Tax computed at federal statutory rate	$	28,288		$	20,327		$	18,335
Increases (decreases) in tax from:
State income taxes net of federal income tax		1,903			1,815			1,837
Investment tax credit amortization		(1,151	)		(1,152	)		(1,152	)
Differences reversing in excess of federal rates		(15	)		(136	)		(1,283	)
Dividend received/paid deduction		(703	)		(703	)		(707	)
Affordable housing tax credits		(1,324	)		(1,418	)		(1,412	)
Permanent and other differences		969			(1,286	)		(1,456	)

Total income tax expense	$	27,967		$	17,447		$	14,162


Income tax expense — discontinued operations	$	5,610		$	1,040		$	768

Overall effective federal and state income tax rate		34.9	%		30.5	%		27.4	%

Income tax expense includes the following:
Current federal income taxes	$	32,760		$	15,299		$	11,101
Current state income taxes		5,260			2,923			2,821
Deferred federal income taxes		(7,112	)		1,776			2,809
Deferred state income taxes		(899	)		194			(5	)
Affordable housing tax credits		(1,324	)		(1,418	)		(1,412	)
Investment tax credit amortization		(1,151	)		(1,152	)		(1,152	)
Foreign income taxes		433			(175	)		—

Total	$	27,967		$	17,447		$	14,162

The Company’s deferred tax assets and liabilities were composed of the following on December 31, 2005 and 2004:


	2005			2004
	(in thousands)
Deferred tax assets
Amortization of tax credits	$	5,964		$	6,698
Vacation accrual		2,432			2,191
Unearned revenue		2,803			2,095
Benefit liabilities		29,657			20,882
Cost of removal		20,507			19,431
Differences related to property		7,400			6,565
Transfer to regulatory liability		—			31
Other		3,689			2,853

Total deferred tax assets	$	72,452		$	60,746


Deferred tax liabilities
Differences related to property	$	(154,833	)	$	(155,175	)
Excess tax over book pension		(3,861	)		(4,041	)
Transfer to regulatory asset		(16,724	)		(14,528	)
Other		(3,900	)		(3,451	)

Total deferred tax liabilities	$	(179,318	)	$	(177,195	)

Deferred income taxes	$	(106,866	)	$	(116,449	)

15. Discontinued Operations

In 2005, the Company completed the sales of 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, 2004 and 2003. 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. 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, 2005, 2004 and 2003 are summarized as follows:


	2005
(in thousands)	MIS		SGS			CLC			Total

Operating revenues	$	3,773	$	6,564		$	6,112		$	16,449
Income (loss) before income taxes		2,167		(1,740	)		(956	)		(529	)
Gain (loss) on disposition — pretax		19,025		(2,919	)		(271	)		15,835
Income tax expense (benefit)		7,975		(1,863	)		(502	)		5,610


	2004
(in thousands)	MIS		SGS			CLC			Total

Operating revenues	$	8,739	$	17,209		$	7,753		$	33,701
Income (loss) before income taxes		3,698		(932	)		(163	)		2,603
Income tax expense (benefit)		1,483		(371	)		(72	)		1,040


	2003
(in thousands)	MIS		SGS			CLC			Total

Operating revenues	$	8,547	$	12,160		$	8,244		$	28,951
Income (loss) before income taxes		3,408		(938	)		(271	)		2,199
Income tax expense (benefit)		1,367		(383	)		(216	)		768

At December 31, 2005 and 2004 the major components of assets and liabilities of the discontinued operations were as follows:


	December 31, 2005						December 31, 2004
(in thousands)	SGS		CLC		Total		MIS		SGS		CLC		Total

Current assets	$	857	$	1,455	$	2,312	$	275	$	9,344	$	3,092	$	12,711
Investments and other assets		—		5		5		2,270		—		5		2,275
Goodwill—net		—		—		—		5,925		—		—		5,925
Other intangibles—net		—		—		—		—		18		74		92
Net plant		—		—		—		7,960		1,618		356		9,934

Assets of discontinued operations	$	857	$	1,460	$	2,317	$	16,430	$	10,980	$	3,527	$	30,937


Current liabilities	$	328	$	44	$	372	$	2,920	$	2,228	$	837	$	5,985
Deferred credits		—		—		—		581		271		33		885
Long-term debt		—		—		—		1,710		—		5		1,715

Liabilities of discontinued operations	$	328	$	44	$	372	$	5,211	$	2,499	$	875	$	8,585

The remaining assets and liabilities of SGS and CLC primarily consist of accounts receivable, inventory and accounts payable at estimated fair market values that were not settled or disposed of as of December 31, 2005.

16. Asset Retirement Obligations (AROs)

The Company’s AROs are related to coal-fired generation plants and include site restoration, the closure of ash pits and the removal of storage tanks and asbestos. The Company has legal obligations associated with the retirement of various other long-lived assets used in its electric operations where the estimated settlement costs are individually and collectively immaterial. There are no assets legally restricted for the settlement of any of the Company’s AROs.

The present value of the legal AROs as of December 31, 2005 of $1,524,000 is included in Other noncurrent liabilities on the Company’s December 31, 2005 consolidated balance sheet. The ARO liability includes the capitalized fair value of the obligations of $349,000; accumulated accretion as of December 31, 2004 of $1,088,000 plus the 2005 accretion provision of $87,000.

The present value of the legal AROs as of December 31, 2004 was $1,437,000, which includes the original obligation of $377,000 less a 2004 subsequent measurement adjustment of $28,000 plus accumulated accretion expense of $1,088,000.

17. 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
	2005			2004		2005		2004		2005			2004		2005			2004
	(in thousands, except per share data)
Operating revenues (a)	$	232,133		$	199,583	$	256,378	$	203,457	$	272,658		$	214,719	$	285,239		$	239,603
Operating income (a)		21,067			16,202		20,868		15,071		32,356			20,073		23,303			24,068

Net Income:
Continuing operations		11,050			8,258		10,967		7,808		18,080			10,669		12,758			13,897
Discontinued operations		(1,079	)		1		11,337		224		(477	)		357		(85	)		981

		9,971			8,259		22,304		8,032		17,603			11,026		12,673			14,878

Earnings available for common shares:
Continuing operations		10,866			8,074		10,784		7,624		17,895			10,485		12,575			13,713
Discontinued operations		(1,079	)		1		11,337		224		(477	)		357		(85	)		981

		9,787			8,075		22,121		7,848		17,418			10,842		12,490			14,694

Basic earnings per share:
Continuing operations	$	.37		$	.31	$	.37	$	.29	$	.61		$	.40	$	.43		$	.51
Discontinued operations		(.03	)		—		.39		.01		(.01	)		.02		—			.04

		.34			.31		.76		.30		.60			.42		.43			.55

Diluted earnings per share:
Continuing operations	$	.37		$	.31	$	.37	$	.29	$	.61		$	.40	$	.42		$	.51
Discontinued operations		(.04	)		—		.39		.01		(.02	)		.02		—			.04

		.33			.31		.76		.30		.59			.42		.42			.55

Dividends paid per common share		.28			.275		.28		.275		.28			.275		.28			.275

Price range:
High	$	25.87		$	27.50	$	27.77	$	27.19	$	31.95		$	26.96	$	31.95		$	27.36
Low		24.17			26.00		24.02		24.07		27.20			23.77		26.76			24.99
Average number of common shares outstanding—basic		29,126			25,793		29,158		25,891		29,246			26,010		29,361			26,663
Average number of common shares outstanding—diluted		29,230			25,936		29,264		26,014		29,441			26,122		29,555			26,780


(a)		From continuing operations.