Exhibit 13-A

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands, except number of shareholders and per-share data)	2004			2003			2002			2001			2000 (1)			1999 (1) (2)			1994
Revenues
Electric (7)	$	266,385		$	267,494		$	244,005		$	232,720		$	219,718		$	203,393		$	186,495
Plastics		115,426			86,009			82,931			63,216			82,667			31,504			—
Manufacturing		226,577			177,805			142,390			123,436			97,506			87,086			13,083
Health services		114,318			100,912			93,420			79,129			66,319			68,805			45,555
Other business operations (6)		162,351			114,726			75,947			72,191			70,145			59,327			25,615
Intersegment eliminations		(2,733	)		(2,254	)		(1,036	)		—			—			—			—
Total operating revenues	$	882,324		$	744,692		$	637,657		$	570,692		$	536,355		$	450,115		$	270,748
Income from continuing operations (6)		39,980			37,614			44,176			41,794			39,210			42,808			27,831
Income from discontinued operations		2,215			2,042			1,952			1,809			1,832			2,487			644
Net income		42,195			39,656			46,128			43,603			41,042			45,295			28,475
Cash flow from continuing operations (6)		56,127			72,644			72,360			73,808			58,007			78,635			50,245
Capital expenditures — continuing operations (6)		49,792			49,094			74,074			51,994			44,956			33,733			29,804
Total assets (5)		1,134,148			986,423			914,112			817,778			772,562			729,118			612,749
Long-term debt (6)		261,810			262,363			254,279			222,291			188,939			172,850			153,183
Redeemable preferred		—			—			—			—			18,000			18,000			18,000
Basic earnings per share from continuing operations (3) (6)		1.51			1.44			1.72			1.62			1.52			1.65			1.14
Diluted earnings per share from continuing operations (3) (6)		1.50			1.43			1.71			1.61			1.52			1.65			1.14
Return on average common equity		12.0	%		12.2	%		15.3	%		15.5	%		15.4	%		18.4	%		15.1	%
Dividends per common share		1.10			1.08			1.06			1.04			1.02			0.99			0.86
Dividend payout ratio		70	%		72	%		59	%		62	%		64	%		57	%		74	%
Common shares outstanding — year end		28,977			25,724			25,592			24,653			24,574			24,571			22,360
Number of common shareholders (4)		14,889			14,723			14,503			14,358			14,103			13,438			14,115

Notes: (1)	Restated to reflect the effects of two 2001 acquisitions accounted for under the pooling-of-interests method. The impact of the poolings on years prior to 1999 is not material.
(2)	1999 results include the sale of radio station assets for a net gain of $8.1 million or 34 cents per share.
(3)	Based on average number of shares outstanding.
(4)	Holders of record at year end.
(5)	2002 and prior years are restated to reflect reclassification of estimated removal costs from accumulated depreciation to a regulatory liability.
(6)	Prior years are restated to exclude the operations of Midwest Information Systems, Inc., which is classified as discontinued operations. See note 15 to consolidated financial statements.
(7)	2002 and prior years are restated to reflect implementation of accounting standard, EITF Issue 03-11.

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 five segments: electric, plastics, manufacturing, health services 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 optimal 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 the acquisition, long-term ownership and decentralized operation of diverse businesses. Our strategy is straightforward: It is designed to produce steady and predictable growth. 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 along with long-term growth potential. Owning well-run, profitable companies across different industries brings more growth opportunities and more balance to results. In doing this, we 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 2004:

•   In August 2004 we acquired Idaho Pacific Holdings, Inc. (IPH) of Ririe, Idaho, a leading processor of dehydrated potato products in North America, for approximately $69.0 million plus an earn-out of up to an additional $6.0 million if IPH achieves certain financial targets for the period from August 1, 2004 through July 31, 2005.

•   We issued 2.9 million of our common shares in a public offering generating $70.8 million in cash proceeds net of expenses, which was used to pay down the bridge loan that financed the acquisition of IPH.

•   In October 2004, we amended the terms of two of our credit agreements solely to remove the ratings triggers that would require accelerated repayment of debt under these agreements in the event our senior unsecured debt is rated below Baa3 (Moody’s) or BBB-(Standard & Poor’s). The removal of the ratings triggers resulted in no changes to the interest rate charged on line borrowings and no material changes to other terms of the agreements.

•   We announced our intention to sell Midwest Information Systems, Inc. (MIS) and exit the telecommunications business. Therefore, the results of operations of MIS are classified and reported under discontinued operations on our consolidated financial statements.

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

•   Planned capital budget expenditures of $211 million for the years 2005-2009.

•   The continued investigation and evaluation of acquisition opportunities.

•   Completion of a feasibility study on building and being a joint owner in a proposed 600-megawatt electric generating station at our Big Stone Plant site. Our intent is to be the operator of the proposed facility with an ownership interest of approximately 18%, if it is built. This project has not yet been included in our five-year capital budget pending the outcome of the feasibility study. A decision on whether to move forward with the project is expected in 2005.

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

(in thousands)	2004		2003
Operating revenues:
Electric	$	266,385	$	267,494
Nonelectric		615,939		477,198
Total operating revenues	$	882,324	$	744,692
Net income from continuing operations:
Electric	$	31,535	$	34,146
Nonelectric		8,445		3,468
		39,980		37,614
Net income from discontinued operations		2,215		2,042
Total net income	$	42,195	$	39,656

The 18.5% increase in consolidated revenues in 2004 compared with 2003 was due to revenue growth in our nonelectric businesses. Revenues grew $48.8 million in our manufacturing segment and $29.4 million in our plastics segment in 2004, mainly as a result of increased unit sales and price increases related to increases in raw material costs. Revenues in our other business operations segment grew $47.6 million in 2004, mainly due to the acquisitions of Foley Company in November 2003 and IPH in August 2004. Increased sales of medical equipment and increased imaging revenues contributed to a $13.4 million increase in health services revenues in 2004.

The increases in nonelectric revenues along with productivity improvements, better capacity utilization and improved operations in our health services segment resulted in an increase in net income from nonelectric operations of $5.0 million in 2004 compared with 2003. Net income from our electric segment declined in 2004 compared with 2003 primarily due to lower wholesale revenues related to the one-time recognition of $1.2 million in unrealized after-tax gains on forward energy contracts as a result of the initial application of mark-to-market accounting in 2003 and a $1.0 million reduction in net income from contracted construction work in 2004 compared with 2003.

Following is a more detailed analysis of our operating results by business segment for the three years ended

December 31, 2004, 2003 and 2002, followed by a discussion of our financial position at the end of 2004, our outlook for 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 below for 2004, 2003 and 2002 operating revenues, electric operation and maintenance expenses, cost of goods sold and nonelectric segment operating expenses will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intercompany eliminations by income statement line item are listed below:

(in thousands)	2004		2003		2002
Operating revenues	$	2,733	$	2,254	$	1,036
Electric operating and maintenance expenses		—		—		222
Cost of goods sold		210		343		446
Operating expenses		2,523		1,911		368

ELECTRIC

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

			%					%
(in thousands)	2004		change			2003		change		2002
Retail sales revenues	$	224,502		3		$	217,611		5	$	207,039
Wholesale revenues		23,825		(6	)		25,472		39		18,295
Net marked-to-market gains		3,228		(20	)		4,058		—		—
Other revenues		14,830		(27	)		20,353		9		18,671
Total operating revenues	$	266,385		—		$	267,494		10	$	244,005
Production fuel		52,056		2			51,163		16		44,122
Purchased power – retail use		40,098		11			36,002		16		30,915
Other operation and maintenance expenses		85,361		(2	)		87,186		8		80,756
Depreciation and amortization		24,236		(7	)		26,008		4		24,910
Property taxes		10,411		8			9,598		2		9,423
Operating income	$	54,223		(6	)	$	57,537		7	$	53,879

The $6.9 million increase in retail revenues from 2003 to 2004 is mainly due to a $4.0 million increase in cost-of-energy (COE) revenues. The remaining increase in retail revenues was due to a 1.5% increase in retail kilowatt-hour (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 77.8% decrease in cooling degree-days in the summer of 2004 compared with the summer of 2003. The increase in COE 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 increased as a result of the increase in retail kwh sales.

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 marked-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 Minnesota Public Utilities Commission. 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.

The $10.6 million increase in retail revenues in 2003 compared with 2002 is mainly due to a $9.4 million increase in COE revenues. The remaining increase in retail revenues was due to a 0.7% increase in retail kwh sales. The increase in retail sales reflects minor increases (less than 1%) in residential, commercial and industrial kwh sales. Heating-degree-days totaling 9,071 in 2003 compared with 9,033 in 2002 were not a discernable factor contributing to 2003 sales variances. The increase in COE revenues reflects a 13.2% increase in fuel and purchased power costs per kwh for retail use in 2003 compared with 2002.

Wholesale revenues from sales of company-owned generation increased $6.5 million in 2003 compared with 2002 due to a 19.6% increase in kwh sales combined with a 29.0% increase in revenue per kwh of generation sold. Net margins on resales of purchased power increased 10.9% between 2003 and 2002 as a result of a 25.1% increase in kwh sales combined with a 14.1% increase in the margin per kwh resold. A 36.1% increase in overall wholesale electric prices reflects increased demand for electricity in the Mid-Continent Area Power Pool (MAPP) region. Higher prices in the wholesale power markets also reflect generally increasing generation costs, reduced generation from regional hydro facilities due to lower spring runoff and the lack of summer rainfall and high-cost generation

from natural gas-fired peaking units. The higher prices, combined with increased availability of electric utility-owned generation and well-timed energy purchases in 2003 compared to 2002, put the electric utility in a favorable position to respond to the increased demand for electricity resulting in the increase in wholesale electric sales. Net marked-to-market gains include $2.1 million in net unrealized gains on forward energy contracts at December 31, 2003 and $2.0 million in net gains realized during 2003.

Other electric operating revenues increased $1.7 million in 2003 compared with 2002. The increase reflects $2.5 million in increased transmission-related revenues from control area services, transmission tariffs and shared use deficiency payments, and a $1.3 million increase in revenue from the sale of steam to an ethanol plant that began operations in the third quarter of 2002, offset by a $2.1 million reduction in revenues from contract work. Revenues from major projects included $7.6 million from regional wind generation projects in 2003 compared to $9.9 million from work on a North Dakota transmission line for another area utility that was completed in the fourth quarter of 2002.

The $7.0 million increase in production fuel expense in 2003 compared with 2002 is due to an increase in fuel costs and generation at the electric utility’s coal-fired generating stations, and an increase in fuel costs from combustion turbine generation. A 12.0% increase in the fuel cost per kwh generated reflects increases in fuel cost per kwh at all of the electric utility’s generating units including fuel costs for the electric utility’s new combustion turbine brought online in June 2003. The $5.1 million increase in purchased power costs for retail use in 2003 compared with 2002 was the result of a 21.3% increase in the cost per kwh purchased offset by a 4.0% decrease in kwh purchases for retail use.

The $6.4 million increase in other operation and maintenance expenses in 2003 compared with 2002 includes increased labor related expenses of $2.7 million as a result of annual wage increases of about 3.5% and increases in employee benefit costs. Pole maintenance and tree-trimming costs increased $1.0 million and transportation and travel-related expenses increased $1.0 million between the years. Insurance costs including provisions for damages were up $0.8 million. Fuel procurement costs increased $0.5 million, mainly related to litigation before the Surface Transportation Board. Uncollectible accounts expense increased $0.4 million.

The $1.1 million increase in depreciation and amortization expense for 2003 compared to 2002 is due to an increase in depreciable plant base as a result of 2002 and 2003 capital expenditures.

PLASTICS

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

			%				%
(in thousands)	2004		change		2003		change			2002
Operating revenues	$	115,426		34	$	86,009		4		$	82,931
Cost of goods sold		96,834		28		75,894		16			65,628
Operating expenses		6,010		51		3,976		(15	)		4,702
Depreciation and amortization		2,297		8		2,126		21			1,760
Operating income	$	10,285		156	$	4,013		(63	)	$	10,841

The $29.4 million increase in plastics operating revenues in 2004 compared with 2003 reflects a 10.8% increase in the pounds of polyvinyl chloride (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 $20.9 million increase in cost of goods sold reflecting an 11.5% 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 19.0% between the periods. The gross margin per pound of pipe sold increased 68.0% in 2004 compared with 2003. The $2.0 million increase in operating expenses between the periods primarily is due to increases in compensation, sales commissions, travel and advertising 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.

The $3.1 million increase in plastics operating revenues in 2003 compared with 2002 was due to an 8.2% increase in the average sales price per pound of pipe sold. The increase was partially offset by a 4.2% decrease in pounds sold between the years. The increased revenue was more than offset by the $10.3 million increase in cost of goods sold resulting from a 20.9% 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 26.3% between the periods. Operating expenses decreased $0.7 million between the periods primarily due to decreased compensation directly related to the decrease in gross margins. The $0.4 million increase in depreciation and amortization expense is related to a $4.4 million increase in depreciable plant in 2002 and a $3.5 million increase in depreciable plant in 2003.

MANUFACTURING

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

			%				%
(in thousands)	2004		change		2003		change			2002
Operating revenues	$	226,577		27	$	177,805		25		$	142,390
Cost of goods sold		178,822		28		139,720		29			107,977
Operating expenses		25,145		13		22,244		21			18,411
Depreciation and amortization		8,701		13		7,708		18			6,525
Operating income	$	13,909		71	$	8,133		(14	)	$	9,477

The manufacturing segment’s improved performance in 2004 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 our metal parts stamping and fabrication company and our wind tower manufacturer 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 $0.7 million in 2004 compared with 2003.

The $48.8 million increase in manufacturing operating revenues in 2004 compared with 2003 includes increases of $18.5 million from our metal parts stamping and fabrication company, $10.7 million from our manufacturer of wind towers, $8.6 million from our waterfront equipment company, $5.8 million from our manufacturer of thermoformed plastic and horticultural products and $5.7 million from our manufacturer of structural steel products. The revenue increase at our metal parts stamping and fabrication company is not only related to an increase in raw material costs, especially steel, but also reflects a 12.7% increase in the number of units produced and sold at this company’s expanded manufacturing facilities in 2004 compared with 2003. The revenue increase at our manufacturer of wind towers reflects increased steel prices and increased productivity and plant utilization in 2004. Unit sales at our manufacturer of thermoformed plastic and horticultural products increased 14.2% in 2004 compared with 2003. The revenue increases at our waterfront equipment company and our manufacturer of structural steel products reflect increases in sales of residential waterfront equipment, and increases in jobs in progress and product price increases related to higher raw material costs.

The $39.1 million increase in cost of goods sold in 2004 compared with 2003 includes increases of $13.3 million from our metal parts stamping and fabrication company, $8.4 million from our waterfront equipment company, $7.7 million from our manufacturer of wind towers, $5.2 million from our manufacturer of thermoformed plastic and horticultural products and $4.8 million from our manufacturer of structural steel products. The increases in costs of goods sold at these companies reflect production increases and higher raw material costs. The $2.9 million increase in manufacturing segment operating expenses includes $1.9 million in increased expenses at our metal parts stamping and fabrication company and $1.0 million in increased sales commissions at our waterfront equipment company. The increase in operating expenses at our metal parts stamping and fabrication company reflects increases in compensation expenses and increased promotional expenses related to increased sales and losses related to the disposal of equipment no longer used in production. The $1.0 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.

The $35.4 million increase in manufacturing operating revenues for 2003 compared with 2002 includes a $25.7 million increase in revenue from the waterfront equipment companies acquired in 2002. Revenues from our manufacturer of thermoformed plastic and horticultural products increased $8.0 million on an increase in the volume of products sold. Revenue at our metal parts stamping and fabrication company increased $3.0 million and our manufacturer of wind towers recorded $1.5 million in increased revenue. These increases were offset by decreases in revenue of $2.5 million from the manufacturer of structural steel products and $0.3 million from our manufacturer of automobile frame-straightening equipment.

The $31.7 million increase in cost of goods sold in 2003 compared with 2002 primarily reflects a $19.1 million increase in costs of goods sold at our waterfront equipment companies combined with increased costs of $6.0 million at our manufacturer of wind towers mostly in material costs, $5.3 million from our manufacturer of thermoformed plastic and horticultural products related to increased sales, and $2.5 million from our metal parts stamping and fabrication company primarily related to material costs. These increases were offset by a reduction in cost of goods sold of $0.4 million at our manufacturer of structural steel products, mainly related to reduced labor expenses, and $0.1 million from our manufacturer of automobile frame-straightening equipment. The $1.2 million increase in depreciation and amortization expense in 2003 compared with 2002 is due to 2002 and 2003 plant expansions and equipment purchases at all 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)	2004		change			2003		change			2002
Operating revenues	$	114,318		13		$	100,912		8		$	93,420
Cost of goods sold		85,662		14			75,085		13			66,680
Operating expenses		17,662		14			15,442		13			13,676
Depreciation and amortization		5,047		(2	)		5,137		16			4,410
Operating income	$	5,947		13		$	5,248		(39	)	$	8,654

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 costs 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.

The $7.5 million increase in health services operating revenues for 2003 compared with 2002 reflects $6.7 million in additional scan and other services revenue, mostly from the acquisitions that occurred in 2002. Revenues from the sale of diagnostic imaging equipment increased $0.8 million between the periods in part due to recent acquisitions in 2003. The number of scans performed increased 12.6% mainly due to the 2002 acquisitions, while the average fee per scan decreased 1.8%.

Although revenues from imaging services increased by $6.7 million in 2003 compared with 2002, the increase was more than offset by increases in equipment and infrastructure costs incurred to support expected revenue growth. While operating income for 2003 was significantly less than operating income in 2002, the segment’s 2003 results improved significantly from early 2003 in part due to steps taken by management to address increases in operating expenses of the diagnostic imaging operations. The company that sells and services medical diagnostic and monitoring equipment had a good year financially in 2003, but the results from imaging services were disappointing, primarily due to aggressive growth combined with subsequent integration challenges.

OTHER BUSINESS OPERATIONS

The following table summarizes the results of operations for our other business operations segment, which no longer includes our telecommunications business now being reported in discontinued operations, for the years ended December 31:

				%						%
(in thousands)	2004			change			2003			change			2002
Operating revenues	$	162,351			42		$	114,726			51		$	75,947
Cost of goods sold		124,433			51			82,378			77			46,414
Operating expenses		43,783			19			36,646			19			30,679
Depreciation and amortization		4,063			43			2,841			(3	)		2,921
Operating (loss)	$	(9,928	)		(39	)	$	(7,139	)		(76	)	$	(4,067	)

The $47.6 million increase in operating revenues in 2004 compared with 2003 includes $40.6 million from Foley acquired in November 2003 and $14.0 million from IPH acquired in August 2004. Revenues at the energy services company increased $8.6 million in 2004 compared with 2003 mainly due to increases in natural gas prices. Transportation company revenues increased $1.9 million, reflecting increased brokerage activity and the pass through of increased diesel prices to customers. Transportation company brokered miles increased 5.5% between the years while the combined miles driven by the company-owned fleet and contracted owner-operators decreased 7.4%. Revenues from our electrical contracting company decreased $17.7 million in 2004 compared with 2003 due to a lower volume of available work in combination with excess capacity in its construction market.

The $42.1 million increase in cost of goods sold in 2004 compared with 2003 includes $36.7 million from Foley and $11.4 million from IPH. Cost of goods sold at our energy services company increased $8.5 million in 2004 compared with 2003 due to increases in natural gas prices. Cost of goods sold from our electrical contracting company decreased $14.6 million as a result of a lower volume of available work in 2004 compared with 2003.

The $7.1 million increase in operating expenses in 2004 compared with 2003 includes $2.7 million from Foley and $0.9 million from IPH. Transportation company operating expenses increased $1.9 million mainly related to increased fuel costs and increased brokerage activity. Operating expenses also 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. The $1.2 million increase in depreciation and amortization expense is attributable to the acquisitions of Foley and IPH.

The $2.8 million increase in operating losses in 2004 compared with 2003 includes $3.5 million in increased operating losses at the corporation’s electrical contracting company as a result of losses incurred on certain jobs in 2004 and $1.3 million in increased costs related to the increases in unallocated corporate overhead. These operating loss increases were partially offset by operating income increases of $1.3 million related to the acquisitions of Foley and IPH, $0.4 million from our energy services company and $0.3 million from our transportation company.

The $38.8 million increase in operating revenue in 2003 compared with 2002 was mostly due to a $13.8 million increase in revenues from natural gas sales at our energy services company related to an increase in natural gas prices. In addition, construction revenues increased by $21.4 million, of which $7.9 million came from Foley. Transportation revenues increased by $2.3 million between the periods as a result of an 85.6% increase in brokered miles. The $36.0 million increase in cost of goods sold reflects a $14.4 million increase in the cost of natural gas sold by our energy services company and a $21.6 million increase in construction costs at our construction companies, of which $6.5 million is attributable to Foley.

The $6.0 million increase in operating expenses between the periods reflects a $2.4 million increase in transportation operating expenses mainly related to increased brokerage activity. The construction companies reported $1.0 million in increased operating expenses with $0.5 million of the increase related to Foley. Operating expenses also reflect a $3.3 million increase in unallocated corporate overhead costs mainly due to increased employee benefit costs and increases in self-insurance costs. Operating expense at the energy services company decreased $1.9 million from 2002 to 2003 as a result of decreased activity. We had recorded $250,000 in goodwill related to the acquisition of an energy management firm in 2002. Based on an offer to purchase this entity in the fourth quarter of 2003, we determined that the goodwill related to this entity was impaired and, accordingly, recorded a $250,000 charge to operating income in the fourth quarter of 2003.

DISCONTINUED OPERATIONS

As a result of our intention to sell MIS and exit the telecommunications business, MIS is reported as discontinued operations in our consolidated financial statements. The following table presents MIS 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 2004, 2003 and 2002 consolidated statements of income.

			%					%
(in thousands)	2004		change			2003		change			2002
Operating revenues	$	8,739		2		$	8,547		(2	)	$	8,680
Expenses		5,041		(2	)		5,138		(5	)		5,422
Income taxes		1,483		8			1,367		5			1,306
Income from discontinued operations	$	2,215		8		$	2,042		5		$	1,952

CONSOLIDATED INTEREST CHARGES

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.

Interest expense increased $0.3 million in 2003 compared to 2002 as a result of lower variable interest rates. The average interest rate paid on short-term debt decreased from 2.2% in 2002 to 1.7% in 2003.

CONSOLIDATED INCOME TAXES

Our effective tax rate on income from continuing operations was 29.8% for 2004 compared with 26.5% for 2003. The increase reflects the impact of R&D tax credits claimed in 2003. Without these credits, the 2003 effective tax rate would have been 27.5%. The remaining 2.3% 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. See note 14 to consolidated financial statements.

Our effective tax rate on income from continuing operations was 26.5% for 2003 compared with 29.8% for 2002. The reduction reflects the impact of prior-year R&D tax credits claimed in 2003. Without these credits, the 2003 effective tax rate would have been 27.5%. The remaining 2.3% difference in the effective tax rate for 2003 compared to 2002 is a function of the level of fixed deductions and credits in proportion to lower net income before tax in 2003 compared to 2002.

IMPACT OF INFLATION

The electric utility operates under regulatory provisions that allow price changes in the cost of fuel and purchased power to be passed to most customers through automatic adjustments to its rate schedules under the cost-of-energy adjustment clause. Other increases in the cost of electric service must be recovered through timely filings for electric rate increases with the appropriate regulatory agency.

Our plastics, manufacturing, health services, 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. The impact of inflation on these segments has not been significant during the past few years because of the relatively low rates of inflation experienced in the United States. Raw material costs, labor costs and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation 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 and health care costs, which have been partially mitigated by pricing adjustments.

2005 EXPECTATIONS

We anticipate diluted earnings per share from continuing operations to be in a range from $1.50 to $1.70. Total diluted earnings per share are expected to be in a range from $1.70 to $1.90 which includes earnings from discontinued operations.

Contributing to the earnings expectations for 2005 are the following items:

•   We expect solid performance in the electric segment in 2005 although net income is anticipated to be lower than 2004 levels. This is primarily because of uncertainty in the wholesale electric markets due to the expected implementation of Midwest Independent Transmission System Operator electric markets on April 1, 2005 and anticipated increases in transmission service costs. Regulated returns in 2005 for the electric segment are expected to be consistent with authorized levels.

•   We expect the plastics segment to perform well in 2005 due to continuing strong demand in the southwestern region of the country. Net income for this segment is expected to be in a range between 2003 and 2004 net earnings levels.

•   The improving economy, continued enhancements in productivity and capacity utilization and the extension of the federal Production Tax Credit are expected to result in increased net income in our manufacturing segment.

•   Our health services segment is expected to grow net income in 2005 as we continue to realize earnings improvement from our imaging business.

•   We expect our food ingredient processing business, which we anticipate will be a new reporting segment in 2005, to generate net income in the range of $4.2 million to $5 million for the year ending December 31, 2005.

•   Our other business operations segment is expected to show improved results over 2004 due to the improving economy. The extension of the Production Tax Credit is expected to have a positive impact on our electrical contracting business.

•   We anticipate investing approximately $50 million in capital expenditures during 2005 in addition to funding possible future acquisitions.

•   Our outlook for 2005 reflects the anticipated impact of Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, which could lower earnings per share results by as much as $0.02 per share in 2005. 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 the third quarter 2005; however, it can be adopted earlier.

•   Contributing to our overall earnings expectation for 2005 is our telecommunications business which is being held for sale and is accounted for as discontinued operations. We expect to realize a gain on the sale of this business in 2005. We also are exploring the divestiture of certain other businesses in 2005 as part of an ongoing evaluation of the prospects and growth opportunities of our business operations.

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 $59.9 million in 2004 compared with $77.0 million in 2003. The $17.1 million decrease in cash from operations reflects an $8.6 million increase in income tax payments between the years, $4.0 million in discretionary pension plan contributions in 2004 and a net increase in other components of working capital mainly influenced by a $15.8 million increase in Costs and estimated earnings in excess of billings resulting from an increase in the value of jobs in progress under percentage of completion accounting. The reduction in income tax payments in 2003 and the subsequent increase in 2004 is partially due to an increase in income before income taxes in 2004 compared to 2003, but also reflects a change in the methodology used for determining estimated tax payment requirements that resulted in a change in the timing of 2002, 2003 and 2004 estimated tax payments. This change in methodology had the effect of reducing estimated tax payments made in 2003 and deferring the payment of a portion of 2003 income taxes into 2004.

The $58.7 million increase in net cash used in investing activities in 2004 compared with 2003 reflects a $56.2 million increase in cash used to complete acquisitions and a $6.8 million increase in cash used for other investments, offset by a $4.3 million increase in cash proceeds from the sale of assets. The increase in cash used for acquisitions and other investments is mostly related to the 2004 acquisition of IPH, in which $69.0 million in cash was paid and $6.0 million was placed in escrow to pay off earn-out contingencies if IPH achieves certain financial targets for the period from August 1, 2004 through July 31, 2005. In 2004, proceeds from the sale of assets included cash from the sale of used equipment, the sale of our investment in Fargo Baseball LLC and the sale of a building.

Net cash provided by financing activities was $52.7 million in 2004 compared with $19.1 million in net cash used in financing activities in 2003. The $71.8 million increase between the years was mainly due to the following items:

•   Net proceeds of $70.8 million from the public offering of 2.9 million common shares in December 2004.

•   Proceeds of $7.3 million from the issuance of common stock for our automatic dividend reinvestment and share purchase plan and our employee stock purchase plan in 2004.

•   Net short-term borrowings increased $10.0 million in 2004.

•   Proceeds from the issuance of long-term debt decreased $14.5 million in 2004. Proceeds in 2003 included $16.3 million borrowed under a loan agreement with Lombard US Equipment Finance Corporation.

On August 16, 2004 we borrowed $76.0 million of unsecured and unsubordinated debt from UBS Loan Finance LLC to finance the acquisition of IPH. We repaid $71.1 million of the loan balance in December 2004 with proceeds from the public offering of 2.9 million shares of common stock. The remaining unpaid balance of $4.9 million outstanding on December 31, 2004, was repaid in January 2005 from proceeds received for 175,000 of our common shares upon the partial exercise of the over-allotment option granted to the underwriters of the December 2004 public offering and by borrowing from our line of credit. The common stock was issued under a universal shelf registration statement filed with the Securities and Exchange Commission that gives us the ability to issue up to an additional $256 million of common stock, preferred stock, debt and certain other securities from time to time.

CASH REALIZATION RATIOS— CONTINUING OPERATIONS - Cash flows from operations - Net income The cash realization ratio represents cash flows from continuing operations expressed as a percent of net incoem form continuing operations.	INTEREST-BEARING DEBT AS A PERCENT OF TOTAL CAPITAL(millions - Total capital - Interest-bearing debt (includes short-term debt) Otter Tail has maintained a 40-50% interest-bearing debt to total capital ratio for the past three years. The decrease from 2003 to 2004 reflects the issuance of $71 million in common equity in 2004.

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 improvements are investments in electric generation facilities, transmission and distribution lines, equipment used in the manufacturing process, acquisitions 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, the costs of labor, materials and equipment, and our consolidated financial condition.

Consolidated capital expenditures for the years 2004, 2003 and 2002 were $49.8 million, $49.1 million and $74.1 million, respectively. The estimated capital expenditures for 2005 are $50.3 million and the total capital expenditures for the five-year period 2005 through 2009 are estimated to be approximately $211 million.

The breakdown of 2002, 2003 and 2004 actual and 2005 through 2009 estimated capital expenditures by segment is as follows:

(in millions)	2002		2003		2004		2005		2005-2009
Electric	$	46	$	28	$	25	$	28	$	135
Plastics		6		4		3		2		10
Manufacturing		15		10		13		9		47
Health services		4		6		4		2		5
Other business operations		3		1		5		9		14
Total	$	74	$	49	$	50	$	50	$	211

The following table summarizes our contractual obligations at December 31, 2004 and the effect these obligations are expected to have on its 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	$	268	$	6	$	59	$	6	$	197
Interest on long-term debt obligations		152		15		30		23		84
Capacity and energy requirements		146		20		35		39		52
Operating lease obligations		111		30		47		25		9
Coal contracts (required minimums)		100		16		32		12		40
Other purchase obligations		6		6		—		—		—
Total contractual cash obligations	$	783	$	93	$	203	$	105	$	382

Interest on $24.4 million of variable-rate debt outstanding on December 31, 2004 was projected based on the interest rates applicable to those debt instruments on December 31, 2004.

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 short-term or long-term financing may be required in the period 2005 through 2009 in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to complete acquisitions, to fund the construction of a new generating station at the Big Stone Plant site if we decide to move forward with the project or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations, and financial condition could be adversely affected.

On April 28, 2004 we renewed our $70 million line of credit. The renewed agreement expires on April 27, 2005. The terms of the renewed line of credit at the time of renewal were essentially the same as those in place prior to the renewal. In October 2004, we amended the terms of our $70 million line of credit agreement to remove the ratings trigger that would require accelerated repayment of any outstanding balance on the line of credit in the event our senior unsecured debt is rated below Baa3 (Moody’s) or BBB- (Standard & Poor’s). The removal of the ratings trigger resulted in no changes to the interest rate charged on line borrowings and no material changes to other terms of the agreement. 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 up to LIBOR plus 0.8% if the ratings on our senior

unsecured debt fall to BBB+ or below (Standard & Poor’s) or Baa1 or below (Moody’s). 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 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. As of December 31, 2004, $35.0 million of our $70 million line of credit was in use. Our obligations under this line of credit are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies.

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, 2004.

Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. In October 2004, we also amended the terms of our $90 million 6.63% senior notes to remove a ratings trigger that would require repayment of the notes with a make-whole premium if our senior unsecured debt is rated below Baa3 (Moody’s) or BBB- (Standard & Poor’s). 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).

In December 2004 Standard & Poor’s Rating Services lowered our corporate credit rating and senior unsecured debt rating from A-/negative to BBB+/negative. Moody’s rating remains at A2/negative

Our securities ratings at December 31, 2004 are:

	Moody’s
	Investors	Standard
	Service	& Poor’s
Senior unsecured debt	A2	BBB+
Preferred stock	Baa1	BBB-
Outlook	Negative	Negative

Disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities. Downgrades in these securities ratings could adversely affect our company. Further downgrades could increase borrowing costs resulting in possible reductions to net income in future periods and increase the risk of default on our debt obligations.

Our ratio of earnings to fixed charges from continuing operations, which includes imputed finance costs on operating leases, was 3.3x for 2004 and 2003 and our long-term debt interest coverage ratio before taxes was 4.8x for 2004 compared to 4.2x for 2003. During 2005, we expect these coverage ratios to increase over 2004 levels assuming 2005 net income meets our expectations.

LONG-TERM DEBT INTEREST
COVERAGE
Otter Tail has maintained coverage ratios in excess of its debt covenant requirements.

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
THAT MAY AFFECT FUTURE RESULTS

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. Our expectations, beliefs and projections are expressed in good faith and are believed by us to have a reasonable basis. Nonetheless, our expectations, beliefs or projections may not be accomplished.

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 seeking to protect the environment 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 (returns) 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 we would be unable to recognize gains from the pension plan assets as income and, instead, we may need 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 the formation and operation of regional transmission organizations), changes in the manner in which wholesale power is sold and purchased (such as standard market design when adopted by the Midwest Independent Transmission System Operator), unplanned interruptions at our generating plants, the effects of regulation and deregulation, demographic changes in our customer base and changes in our customer demand or load growth. 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.

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 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 competition. These regulatory initiatives may include deregulation of the electric utility industry in some 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 and fuel transportation as existing contracts expire or in the event of unanticipated interruptions in fuel supply. 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 98% of our total purchases of PVC resin in 2004 and approximately 96% of our total purchases of PVC resin in 2003. 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.

We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

The plastic pipe industry is highly fragmented and competitive, due to the large number of producers and the fungible nature of the product. We compete not only against other PVC pipe manufacturers, but also against ductile iron steel, concrete and clay pipe manufacturers. Due to shipping costs, competition is usually regional, instead of national, in scope, and the principal areas of competition are a combination of price, service, warranty and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics business.

MANUFACTURING

Competition from foreign and domestic manufacturers, the price and availability of raw materials, the availability of production tax credits and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Our manufacturing businesses are subject to risks associated with competition from foreign and domestic manufacturers that have excess capacity, labor advantages and other capabilities that may place downward pressure on margins and profitability. Raw material costs for items such as steel, lumber, concrete, aluminum and resin have recently increased significantly and may continue to increase. Our manufacturers may not be able to pass on the cost of such increases to their respective customers. Each of our manufacturing companies has significant customers and concentrated sales to such customers. If our relationships with significant customers should change materially, it would be difficult to immediately and profitably replace lost sales. We believe the demand for wind towers that we manufacture will depend primarily on the existence of either renewable portfolio standards or a federal production tax credit for wind energy.

HEALTH SERVICES

Changes in the rates or methods of third-party reimbursements for our diagnostic imaging services could result in reduced demand for those services or create downward pricing pressure, which would decrease our revenues and earnings.

Our health services businesses derive significant revenue from direct billings to customers and third-party payors such as Medicare, Medicaid, managed care and private health insurance companies for our diagnostic imaging services. Moreover, customers who use our diagnostic imaging services generally rely on reimbursement from third-party payors. Adverse changes in the rates or methods of third-party reimbursements could reduce the number of procedures for which we or our customers can obtain reimbursement or the amounts reimbursed to us or our customers.

Our health services operations has a dealership and other agreements with Philips Medical from which it derives significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.

This agreement can be terminated on 180 days written notice by either party for any reason. It also includes other compliance requirements. If this agreement were terminated within the notice provisions or we were not able to renew such agreements or comply with the agreements, the financial results of our health services operations would be adversely affected.

Technological change in the diagnostic imaging industry could reduce the demand for diagnostic imaging services and require our health services operations to incur significant costs to upgrade its equipment.

Although we believe substantially all of our diagnostic imaging systems can be upgraded to maintain their state-of-the-art character, the development of new technologies or refinements of existing technologies might make our existing systems technologically or economically obsolete, or cause a reduction in the value of, or reduce the need for, our systems.

Actions by regulators of our health services operations could result in monetary penalties or restrictions in our health services operations.

Our health services operations are subject to federal and state regulations relating to licensure, conduct of operations, ownership of facilities, addition of facilities and services and payment of services. Our failure to comply with these regulations, or our inability to obtain and maintain necessary regulatory approvals, may result

in adverse actions by regulators with respect to our health services operations, which may include civil and criminal penalties, damages, fines, injunctions, operating restrictions or suspension of operations. Any such action could adversely affect our financial results. Courts and regulatory authorities have not fully interpreted a significant number of these laws and regulations, and this uncertainty in interpretation increases the risk that we may be found to be in violation. Any action brought against us for violation of these laws or regulations, even if successfully defended, may result in significant legal expenses and divert management’s attention from the operation of our businesses.

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.

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.

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, acquired in August 2004, is dependent on superior product quality, competitive product pricing, strong customer relationships, raw material costs 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 could adversely affect the financial performance of this company.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

At December 31, 2004 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 because the Canadian operations of IPH transact all sales in U.S. 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, 2004 we had $24.4 million of long-term debt subject to variable interest rates excluding $2.8 million in long-term debt

included in Liabilities of discontinued operations on our December 31, 2004 consolidated balance sheet. 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, 2004, interest expense and pretax earnings would change by approximately $244,000.

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.

In 2004, our energy services subsidiary entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133. 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, 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 following table shows 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, 2004:

	December 31,
(in thousands)	2004
Current asset – marked-to-market gain	$	1,834
Current liability – marked-to-market loss		(1,700	)
Net fair value of marked-to-market gas contracts	$	134

The $134,000 in recognized but unrealized net gain on these forward natural gas swap transactions marked-to-market on December 31, 2004 is expected to be realized on settlement as scheduled over the following quarters in the amounts listed:

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
(in thousands)	2005		2005		2005		2005		Total
Net gain	$	8	$	54	$	54	$	18	$	134

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, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of December 31, 2004 the electric utility had recognized, on a pretax basis, $301,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can result in transmission constraints and the cancellation of scheduled transactions by the independent transmission system operator. In these situations, the counterparties to the cancelled transaction are generally not made whole for the difference in the contract price and the market price of the electricity at the time of cancellation. In some instances the electric utility may deliver on a sale where its offsetting purchase has been cancelled or is undeliverable, or take delivery on a purchase where its offsetting sale has been cancelled or is undeliverable. All forward energy transactions are subject to a small, and likely unquantifiable, risk of cancellation by the independent transmission system operator due to unanticipated physical constraints on the transmission system. At the time of cancellation, the electric utility could be in a gain or loss position depending on the market price of electricity relative to the contract price and the electric utility’s position in the transaction.

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. Of the forward energy contracts that are marked-to-market as of December 31, 2004, 45% of the forward purchases of electricity have offsetting sales in terms of volumes and delivery periods. The amount of unrealized marked-to-market gains recognized on forward purchases of electricity that are not offset by forward sales of electricity is $144,000.

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. These policies require that most forward sales of electricity in wholesale markets be covered by offsetting forward purchases of electricity with matching terms and delivery dates or by the portion of company-owned generation projected to be in excess of retail load requirements. Currently, a portion of marked-to-market gains or losses on a sales contract will be offset by a marked-to-market loss or gain on the offsetting purchase contract.

Our energy risk management policy allows for open long positions with limitations on the aggregate marked-to-market value of open positions. These positions are closely monitored and covered with offsetting sales when the risk of loss exceeds predefined limits. The exposure to price risk of these open positions as of December 31, 2004 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, 2004 and the change in our consolidated balance sheet position from December 31, 2003 to December 31, 2004:

	December 31,
(in thousands)	2004
Current asset – marked-to-market gain	$	711
Regulatory asset – deferred marked-to-market loss		331
Total assets		1,042
Current liability – marked-to-market loss		(544	)
Regulatory liability – deferred marked-to-market gain		(197	)
Total liabilities		(741	)
Net fair value of marked-to-market energy contracts	$	301

	Year ended
(in thousands)	December 31, 2004
Fair value at beginning of year	$	2,057
Amount realized on contracts entered into in 2003 and settled in 2004		(1,967	)
Changes in fair value of contracts entered into in 2003		(90	)
Net fair value of contracts entered into in 2003 at year-end 2004		—
Changes in fair value of contracts entered into in 2004		301
Net fair value end of year	$	301

The $301,000 in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market on December 31, 2004 is expected to be realized on physical settlement as scheduled over the following quarters in the amounts listed:

	1st Quarter		2nd Quarter
(in thousands)	2005		2005		Total
Net gain	$	276	$	25	$	301

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, 2004 was $10.6 million. As of December 31, 2004 we had a net credit risk exposure of $3.2 million from thirty-nine counterparties with investment grade credit ratings.

The $3.2 million credit risk exposure includes net amounts due to the electric utility on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after December 31, 2004. 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).

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. 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, 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 the 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.

The pension benefit cost for 2005 for our noncontributory funded pension plan is expected to be $2.9 million compared to $2.0 million in 2004. The estimated discount rate used to determine annual benefit cost accruals will decrease to 6.00% in 2005 from 6.25% used in 2004. 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 2004, all other factors being held constant: a 0.25 increase (or decrease) in the discount rate would have decreased (or increased) the 2004 pension benefit cost by $150,000; a 0.25 increase (or decrease) in the assumed rate of increase in future compensation levels would have increased (or decreased) the 2004 pension

benefit cost by $325,000; a 0.25 increase (or decrease) in the expected long-term rate of return on plan assets would have decreased (or increased) the 2004 pension benefit cost by $365,000.

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) the 2004 postretirement medical benefit costs by $140,000. 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 the 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. We continue to use current methodologies to determine plan costs.

REVENUE RECOGNITION

Our construction companies and three 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 costs incurred to total estimated costs. The duration of the majority of these contracts is less than a year. Revenues recognized on jobs in progress as of December 31, 2004 were $106 million. Expected losses on jobs in progress at year-end 2004 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, as such, are estimates. Of the forward electric energy contracts that are marked-to-market as of December 31, 2004, 45% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of unrealized marked-to-market gains recognized on forward energy purchases that are not offset by forward energy sales is $144,000. All of the forward energy contracts for the purchase and sale of electricity marked-to-market as of December 31, 2004 are scheduled for settlement prior to June 1, 2005.

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 2004, $1.6 million of bad debt expense (0.18% of total 2004 revenue of $882 million) was recorded and the allowance for doubtful accounts was $2.8 million (2.2% of trade accounts receivable) as of December 31, 2004. 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, 2004 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 2.77% in 2004, 3.07% in 2003 and 3.08% in 2002. 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, 2004 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, 2004 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.

As of December 31, 2004 an assessment of the carrying values of our goodwill indicated no impairment.

We currently have $1.0 million of goodwill recorded on our balance sheet related to our energy services subsidiary that markets natural gas to approximately 160 retail customers. An evaluation of projected cash flows from this operation in December 2004 indicated that the related goodwill was not impaired. However, actual and projected cash flows from this operation are subject to fluctuations due to low profit margins on natural gas sales combined with high volatility of natural gas prices. Reductions in profit margins or the volume of natural gas sales could result in an impairment of all or a portion of its related goodwill. We will continue to evaluate this reporting unit for impairment on an annual basis and as conditions warrant.

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. Highly competitive pricing in the trucking industry in

recent years had resulted in decreased operating margins and lower returns on invested capital for Wylie. Wylie’s performance improved in 2004 and current projections are for operating margins to increase from current levels over the next three to five years as demand for shipping continues to increase relative to available shipping capacity and additional revenues are generated from added terminal locations and increased brokerage activity. If current trends reverse and operating margins do not increase according to our projections, the 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. At December 31, 2004, assessment of Wylie indicated that its goodwill was not impaired. We will continue to evaluate this reporting unit for impairment on an annual basis and as conditions warrant.

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 judgements.

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. 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

FASB Interpretation (FIN) No. 46 (revised December 2003), Consolidation of Variable Interest Entities, is an interpretation of Accounting Research Bulletin No. 51, that addresses consolidation by business enterprises of variable interest entities which have certain characteristics related to equity at risk and rights and obligations to profits and losses. The effective date for application of certain provisions of FIN 46 was the first quarter of 2004 for interests in variable interest entities created before February 1, 2003 and held by a public entity that has not previously applied the provisions of FIN 46. We have determined that we do not have any arrangements with unconsolidated entities under FIN 46 except for majority interests in eight limited partnerships that invest in tax-credit-qualifying, affordable-housing projects. The net investment in these entities, which are currently accounted for on an equity-method basis, totaled $2.7 million as of December 31, 2004. Full consolidation of these entities would not have a material effect on our consolidated financial statements and would have no effect on our consolidated net income. We include these entities in our consolidated financial statements on an equity method basis due to immateriality. Consolidating these entities would have represented less than 0.5% of total assets of the Company.

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 (the Act) – FSP 106-2 provides guidance on accounting for the effect of the federal subsidy for prescription drug plans when the plan’s sponsor determines that the prescription drug benefits it offers to its retirees are actuarially equivalent to those offered under Medicare Part D and will qualify for the federal subsidy offered under the Act. The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors to coordinate with the Medicare benefit. We elected the one-time deferral of accounting for the effects of the Act in the quarter ended March 31, 2004, the first period in which accounting for the effects of the Act normally would have been reflected in our financial statements.

Our postretirement medical plan provides prescription drug coverage for all electric utility company retirees. We have determined that the prescription drug benefits we offer to our retirees who retired prior to 2003 are actuarially equivalent to those offered under Medicare Part D and will qualify for the federal subsidy offered under the Act. We expect that our share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based will be reduced by the expected subsidy.

During the third quarter of 2004, we adopted FSP 106-2 retroactive to the beginning of the year. With the assistance of our actuarial advisors, we determined that the expected federal subsidy reduced our accumulated postretirement benefit obligation (APBO) at January 1, 2004 by approximately $4.9 million and reduced our net periodic benefit cost for 2004 by $757,000 of which approximately 13.1% was credited to capital additions as a reduction of capitalized labor. The APBO reduction will be accounted for as an actuarial experience gain in accordance with the guidance in FAS 106 and, accordingly, was not included as a reduction to our net periodic benefit cost in 2004. The adoption of FSP 106-2 had the effect of reducing 2004 operating expenses by $658,000. Retroactive application will result in the restatement of first and second quarter 2004 operating expenses and net income when these periods are presented in subsequent financial reports, reducing operating expenses and increasing net income by $164,000 in each quarter. In accordance with the provisions of the Act, the expected subsidy will have no effect on income tax expense.

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 shall be effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. We do not expect the application of the requirements of SFAS No. 151 to have an effect on our consolidated net income, financial position or cash flows.

SFAS No. 123 (revised 2004), Share-Based Payment (SFAS No. 123(R)), 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 in July 2005 with early adoption allowed and, when adopted, can be applied under a modified prospective basis or on a modified retrospective basis back to January 1, 2005. We will adopt SFAS No. 123(R) in July 2005 but have not determined whether we will apply the requirements prospectively or retrospectively. In either event, we have determined that the application of SFAS No. 123(R) reporting requirements will have the effect of reducing our 2005 net income by $300,000 to $600,000.

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, 2004. 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.

As a part of this assessment, management excluded its acquisition of Idaho Pacific Holdings, Inc. from its report on internal control over financial reporting due to the fact this acquisition was completed in August 2004. Companies are allowed to exclude acquisitions from its assessment of internal control during the first year of an acquisition under guidelines established by the Securities and Exchange Commission. Idaho Pacific Holdings, Inc. represents 8.1% of consolidated assets and 1.6% of consolidated revenues as of and for the year ended December 31, 2004.

Based on this assessment, we believe that, as of December 31, 2004 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 18, 2005

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, 2004 and 2003, 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, 2004. 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, 2004, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. 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, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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, 2004, 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, 2004 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in notes 5 and 16 to the consolidated financial statements, effective in 2003 the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations and SFAS No. 149, Amendment of Financial Accounting Standards Board Statement No. 133 on Derivative and Hedging Activities.

DELOITTE & TOUCHE LLP

/s/ Deloitte & Touche LLP

Minneapolis, Minnesota
February 18, 2005

OTTER TAIL CORPORATION

CONSOLIDATED BALANCE SHEETS, DECEMBER 31
(in thousands)	2004		2003
ASSETS
Current assets
Cash and cash equivalents	$	—	$	7,311
Accounts receivable:
Trade (less allowance for doubtful accounts of $2,822 for 2004 and $2,424 for 2003)		124,537		107,463
Other		6,677		7,830
Inventories		77,296		56,915
Deferred income taxes		5,014		3,498
Accrued utility revenues		15,344		14,866
Costs and estimated earnings in excess of billings		20,398		4,591
Other		7,828		10,385
Assets held for sale from discontinued operations		16,430		17,265
Total current assets		273,524		230,124
Investments and other assets		42,655		33,452
Goodwill—net		92,196		66,631
Other intangibles—net		19,692		7,096
Deferred debits
Unamortized debt expense and reacquisition premiums		7,291		8,081
Regulatory assets		14,971		14,669
Other		1,721		1,600
Total deferred debits		23,983		24,350
Plant
Electric plant in service		890,200		875,364
Nonelectric operations		214,079		169,005
Total		1,104,279		1,044,369
Less accumulated depreciation and amortization		440,650		437,493
Plant—net of accumulated depreciation and amortization		663,629		606,876
Construction work in progress		18,469		17,894
Net plant		682,098		624,770
Total	$	1,134,148	$	986,423

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

CONSOLIDATED BALANCE SHEETS, DECEMBER 31
(in thousands, except share data)	2004			2003
LIABILITIES AND EQUITY
Current liabilities
Short-term debt	$	39,950		$	30,000
Current maturities of long-term debt		6,055			8,598
Accounts payable		86,631			81,994
Accrued salaries and wages		17,817			14,521
Accrued federal and state income taxes		3,947			3,731
Other accrued taxes		11,485			10,448
Other accrued liabilities		10,417			9,888
Liabilities from discontinued operations		5,211			6,622
Total current liabilities		181,513			165,802
Pension benefit liability		16,703			16,919
Other postretirement benefits liability		25,053			23,230
Other noncurrent liabilities		11,874			11,102
Commitments (note 8)
Deferred credits
Deferred income taxes		121,605			101,016
Deferred investment tax credit		10,477			11,630
Regulatory liabilities		56,909			42,926
Other		1,662			2,048
Total deferred credits		190,653			157,620
Capitalization (page 39)
Long-term debt, net of current maturities		261,810			262,363
Class B stock options of subsidiary		1,832			—
Cumulative preferred shares		15,500			15,500
Common shares, par value $5 per share—authorized, 50,000,000 shares; outstanding, 2004—28,976,919 shares; 2003—25,723,814 shares		144,885			128,619
Premium on common shares		87,865			26,515
Unearned compensation		(2,577	)		(3,313	)
Retained earnings		199,427			186,495
Accumulated other comprehensive loss		(390	)		(4,429	)
Total common equity		429,210			333,887
Total capitalization		708,352			611,750
Total	$	1,134,148		$	986,423

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME — FOR THE YEARS ENDED DECEMBER 31
( in thousands, except per-share amounts)	2004		2003		2002
Operating revenues	$	882,324	$	744,692	$	637,657
Operating expenses
Production fuel		52,056		51,163		44,122
Purchased power		40,098		36,002		30,915
Electric operation and maintenance expenses		85,361		87,186		80,534
Cost of goods sold		485,541		372,734		286,253
Other nonelectric expenses		90,077		76,397		67,100
Depreciation and amortization		44,344		43,820		40,526
Property taxes		10,411		9,598		9,423
Total operating expenses		807,888		676,900		558,873
Operating income		74,436		67,792		78,784
Other income — net		820		1,145		1,654
Interest charges		18,272		17,760		17,507
Income from continuing operations before income taxes		56,984		51,177		62,931
Income taxes - continuing operations		17,004		13,563		18,755
Income from continuing operations		39,980		37,614		44,176
Income from discontinued operations
net of income taxes of $1,483, $1,367 and $1,306, respectively		2,215		2,042		1,952
Net Income		42,195		39,656		46,128
Preferred dividend requirements		736		735		736
Earnings available for common shares	$	41,459	$	38,921	$	45,392
Average number of common shares outstanding—basic		26,089		25,673		25,176
Average number of common shares outstanding—diluted		26,207		25,826		25,397
Basic earnings per share:
Continuing operations (net of preferred dividend requirement)	$	1.51	$	1.44	$	1.72
Discontinued operations		0.08		0.08		0.08
	$	1.59	$	1.52	$	1.80
Diluted earnings per share:
Continuing operations (net of preferred dividend requirement)	$	1.50	$	1.43	$	1.71
Discontinued operations		0.08		0.08		0.08
	$	1.58	$	1.51	$	1.79
Dividends per common share	$	1.10	$	1.08	$	1.06

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, 2001		24,653,490		$	123,267		$	1,526		$	(151	)	$	156,641		$	(1,975	)	$	279,308
Common stock issuances		938,670			4,694			22,094			(2,674	)								24,114
Amortization of unearned compensation—stock awards											879									879
Comprehensive income:
Net income														46,128						46,128
Minimum pension liability adjustment																	(10,014	)		(10,014	)
Total comprehensive income																				36,114
Tax benefit for exercise of stock options								720												720
Purchase stock for employee purchase plan								(205	)											(205	)
Cumulative preferred dividends														(736	)					(736	)
Common dividends														(26,729	)					(26,729	)
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	) (a)	$	429,210

(a) Accumulated other comprehensive loss on December 31, 2004 is comprised of the following:

(in thousands)	Before Tax			Tax Effect			Net-of-tax
Minimum supplemental pension liability adjustment	$	(2,317	)	$	927		$	(1,390	)
Foreign currency exchange translation		1,690			(676	)		1,014
Unrealized loss on marketable equity securities		(23	)		9			(14	)
Net accumulated other comprehensive loss	$	(650	)	$	260		$	(390	)

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS — FOR THE YEARS ENDED DECEMBER 31
(in thousands)	2004			2003			2002
Cash flows from operating activities
Net income	$	42,195		$	39,656		$	46,128
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(2,215	)		(2,042	)		(1,952	)
Depreciation and amortization		44,344			43,820			40,526
Deferred investment tax credit—net		(1,152	)		(1,152	)		(1,153	)
Deferred income taxes		3,854			3,134			2,823
Change in deferred debits and other assets		(1,640	)		(3,324	)		(5,178	)
Discretionary contribution to pension plan		(4,000	)		—			—
Change in noncurrent liabilities and deferred credits		2,110			8,026			1,049
Allowance for equity (other) funds used during construction		(716	)		(1,355	)		(1,742	)
Unrealized losses/(gains) on derivatives net of regulatory deferral		1,621			(2,057	)		—
Other—net		1,457			1,629			1,399
Cash provided by (used for) current assets and current liabilities:
Change in receivables and inventories		(18,707	)		(35,402	)		(4,292	)
Change in other current assets		(16,453	)		(2,520	)		(2,498	)
Change in payables and other current liabilities		6,395			19,049			1,822
Change in interest and income taxes payable		(966	)		5,182			(4,572	)
Net cash provided by continuing operations		56,127			72,644			72,360
Net cash provided by discontinued operations		3,797			4,311			4,437
Net cash provided by operating activities		59,924			76,955			76,797
Cash flows from investing activities
Capital expenditures		(49,792	)		(49,094	)		(74,074	)
Proceeds from disposal of noncurrent assets		5,875			1,607			2,482
Acquisitions—net of cash acquired		(69,069	)		(12,896	)		(6,591	)
(Increases)/Decreases in other investments		(5,099	)		1,671			(84	)
Net cash used in investing activities—continuing operations		(118,085	)		(58,712	)		(78,267	)
Net cash used in investing activities—discontinued operations		(1,033	)		(1,696	)		(1,390	)
Net cash used in investing activities		(119,118	)		(60,408	)		(79,657	)
Cash flows from financing activities
Net short-term borrowings		9,950			—			25,507
Proceeds from issuance of common stock, net of issuance expenses		78,780			1,072			3,091
Payments for retirement of common stock		(349	)		—			—
Proceeds from issuance of long-term debt, net of issuance expenses		4,065			18,592			62,447
Payments for retirement of long-term debt		(9,380	)		(8,786	)		(61,041	)
Dividends paid and other distributions		(29,263	)		(28,937	)		(27,465	)
Net cash provided by (used in) financing activities—continuing operations		53,803			(18,059	)		2,539
Net cash provided by (used in) financing activities—discontinued operations		(1,126	)		(1,092	)		(1,120	)
Net cash provided by (used in) financing activities		52,677			(19,151	)		1,419
Effect of foreign exchange rate fluctuations on cash		(794	)		—			—
Net change in cash and cash equivalents		(7,311	)		(2,604	)		(1,441	)
Cash and cash equivalents at beginning of year - continuing operations		7,311			9,915			11,356
Cash and cash equivalents at end of year - continuing operations	$	—		$	7,311		$	9,915
Supplemental disclosures of cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)	$	16,447		$	16,583		$	16,432
Income taxes	$	15,657		$	6,963		$	21,301
Cash paid during the year from discontinued operations for:
Interest (net of amount capitalized)	$	107		$	198		$	399
Income taxes	$	1,387		$	1,474		$	1,534

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31
(in thousands, except share data)	2004		2003
Long-term debt
Lombard US Equipment Finance note, variable, 3.44% at December 31, 2004, due October 2, 2006	$	13,971	$	16,300
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, 2.24% at December 31, 2004, 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		20,765
Obligations of Varistar Corporation:
8.15% five-year term note, due October 31, 2005		540		1,957
7.80% ten-year term note, due October 31, 2007		1,483		3,960
Various up to 11.83% at December 31, 2004		11,235		7,678
Total		268,549		271,245
Less:
Current maturities		6,055		8,598
Unamortized debt discount		684		284
Total long-term debt		261,810		262,363
Class B stock options of subsidiary		1,832		—
Cumulative preferred shares—without par value (stated and liquidating value $100 a share)—authorized 1,500,000 shares; Series outstanding: (a)
$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		429,210		333,887
Total capitalization	$	708,352	$	611,750

(a) All four series of preferred stock are redeemable at the option of the Company. As of December 31, 2004 the call price by series is:

Series	Call price
$3.60	$	102.25
4.40		102.00
4.65		101.50
6.75		103.0375

See accompanying notes to consolidated financial statements.

OTTER TAIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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 and other business operations. The electric segment is regulated while the other segments are not. 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 $949,000 for 2004, $1,970,000 for 2003 and $2,636,000 for 2002. 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 2.77% in 2004, 3.07% in 2003 and 3.08% in 2002. 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 financial statements include the Company’s 53.9% (Big Stone Plant) and 35% (Coyote Station) ownership interests in the assets, liabilities, revenue and expenses of Big Stone Plant and Coyote Station. Amounts at December 31, 2004 and 2003 included in the consolidated balance sheet are as follows:

	Big Stone			Coyote
(in thousands)	Plant			Station
December 31, 2004
Electric plant in service	$	116,405		$	146,343
Accumulated depreciation		(70,904	)		(75,431	)
Net plant	$	45,501		$	70,912
December 31, 2003
Electric plant in service	$	116,240		$	146,431
Accumulated depreciation		(68,387	)		(72,946	)
Net plant	$	47,853		$	73,485

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. Should the sum of the expected future net cash flows be less than the carrying values, the Company would determine whether an impairment loss should be recognized. An impairment loss would be quantified by comparing the amount by which the carrying value exceeds the fair value of the asset where fair value is based on the discounted cash flows expected to be generated by the asset.

INCOME TAXES

Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. The Company amortizes the investment tax credit over the estimated lives of the related property.

REVENUE RECOGNITION

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold. 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 natural gas marketing 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 cost-of-energy adjustment clause—under which the rates are adjusted to reflect changes in average cost of fuels and

purchased power—and a surcharge for recovery of conservation-related expenses. Revenue is accrued for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the cost-of-energy adjustment clause.

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.

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.

Manufacturing operating revenues are recorded when products are shipped and on a percentage-of-completion basis for construction type contracts.

Other business operations operating revenues are recorded when services are rendered or products are shipped. In the case of construction contracts, the percentage-of-completion method is used.

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 costs incurred to total estimated costs. 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)	2004			2003
Costs incurred on uncompleted contracts	$	109,906		$	124,839
Less billings to date		(105,974	)		(137,881	)
Plus estimated earnings recognized		13,172			13,611
	$	17,104		$	569

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)	2004			2003
Costs and estimated earnings in excess of billings on uncompleted contracts	$	20,398		$	4,591
Billings in excess of costs and estimated earnings on uncompleted contracts		(3,294	)		(4,022	)
	$	17,104		$	569

FOREIGN CURRENCY TRANSLATION

The functional currency for the operations of the Canadian subsidiary of Idaho Pacific Holdings, Inc. (IPH), acquired in August 2004, 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, 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.

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 $1,632,000 as of December 31, 2004 and $1,489,000 as of December 31, 2003. These costs are amortized over a three-year period and evaluated annually for impairment.

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 2002 through 2004 would have decreased as presented in the table below. This may not be representative of the pro forma effects for future years if additional options are granted.

(in thousands, except per share amounts)	2004			2003			2002
Net income
As reported	$	42,195		$	39,656		$	46,128
Total stock-based employee compensation expense determined under fair value-based method for all awards net of related tax effects		(1,087	)		(984	)		(1,038	)
Pro forma	$	41,108		$	38,672		$	45,090
Basic earnings per share
As reported	$	1.59		$	1.52		$	1.80
Pro forma	$	1.55		$	1.48		$	1.76
Diluted earnings per share
As reported	$	1.58		$	1.51		$	1.79
Pro forma	$	1.54		$	1.47		$	1.75

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, 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.

RECLASSIFICATIONS

Certain prior year amounts have been reclassified to conform to 2004 presentation. Such reclassifications had no impact on net income, shareholders’ equity or cash flows provided from operations.

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, 2004 and 2003:

	December 31,		December 31,
(in thousands)	2004		2003
Cost method:
Acquisition escrow account	$	6,017	$	—
Economic development loan pools		879		811
Other		1,743		1,518
Equity method:
Affordable housing partnerships		3,802		4,616
Other		—		1,662
Marketable securities classified as available-for-sale		2,009		—
Total investments	$	14,450	$	8,607

The Company’s investments in limited partnerships that invest in tax-credit-qualifying affordable-housing projects provided tax credits of $1,418,000 in 2004, $1,412,000 in 2003 and $1,418,000 in 2002. The reduction in other equity investments relates to the sale of the Company’s investment in Fargo Baseball, LLC. 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, 2004, with $14,000 in unrealized losses included in other comprehensive losses in the equity section of the Company’s December 31, 2004 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)	2004		2003
Finished goods	$	36,639	$	20,349
Work in process		4,531		6,234
Raw material, fuel and supplies		36,126		30,332
Total inventories	$	77,296	$	56,915

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		Balance
	December 31,		acquired in		acquired		December 31,
(in thousands)	2003		2003		in 2004		2004
Plastics	$	19,302	$	—	$	—	$	19,302
Manufacturing		8,232		1,448		—		9,680
Health services		24,333		249		—		24,582
Other business operations		14,764		617		23,251		38,632
Total	$	66,631	$	2,314	$	23,251	$	92,196

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 $905,000 for 2004, $630,000 for 2003 and $535,000 for 2002. The estimated annual amortization expense for these intangible assets for the next five years is: $947,000 for 2005, $815,000 for 2006, $693,000 for 2007, $642,000 for 2008 and $518,000 for 2009.

Total other intangibles as of December 31 are as follows:

	Gross carrying		Accumulated		Net carrying
2004 (in thousands)	amount		amortization		amount
Amortized intangible assets:
Covenants not to compete	$	2,609	$	1,925	$	684
Customer relationships		10,045		148		9,897
Other intangible assets including contracts		2,599		1,423		1,176
Total	$	15,253	$	3,496	$	11,757
Nonamortized intangible assets:
Brand/trade name	$	7,935	$	—	$	7,935
2003 (in thousands)
Amortized intangible assets:
Covenants not to compete	$	2,610	$	1,483	$	1,127
Other intangible assets including contracts		2,367		1,118		1,249
Total	$	4,977	$	2,601	$	2,376
Nonamortized intangible assets:
Brand/trade name	$	4,720	$	—	$	4,720

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 January 2005 indicated none of the intangible assets reported on the Company’s consolidated balance sheet as of December 31, 2004 is impaired.

NEW ACCOUNTING PRONOUNCEMENTS

FASB Interpretation (FIN) No. 46 (revised December 2003), Consolidation of Variable Interest Entities is an interpretation of Accounting Research Bulletin No. 51, that addresses consolidation by business enterprises of variable interest entities which have certain characteristics related to equity at risk and rights and obligations to profits and losses. The effective date for application of certain provisions of FIN 46 was the first quarter of 2004 for interests in variable interest entities created before February 1, 2003 and held by a public entity that has not previously applied the provisions of FIN 46. The Company has determined that it does not have any arrangements with unconsolidated entities under FIN 46 except for majority interests in eight limited partnerships that invest in tax-credit-qualifying, affordable-housing projects. The net investment in these entities, which are currently accounted for on an equity method basis, totaled $2.7 million as of December 31, 2004. Full consolidation of these entities would not have a material effect on the Company’s consolidated financial

statements and would have no effect on its consolidated net income. The Company includes these entities in its consolidated financial statements on an equity method basis due to immateriality. Consolidating these entities would have represented less than 0.5% of total assets of the Company.

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 (the Act) – FSP 106-2 provides guidance on accounting for the effect of the federal subsidy for prescription drug plans when the plan’s sponsor determines that the prescription drug benefits it offers to its retirees are actuarially equivalent to those offered under Medicare Part D and will qualify for the federal subsidy offered under the Act. The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors to coordinate with the Medicare benefit. The Company elected the one-time deferral of accounting for the effects of the Act in the quarter ended March 31, 2004, the first period in which accounting for the effects of the Act normally would have been reflected in the Company’s consolidated financial statements.

The Company’s postretirement medical plan provides prescription drug coverage for all electric utility company retirees. The Company has determined that the prescription drug benefits it offers to its retirees who retired prior to 2003 are actuarially equivalent to those offered under Medicare Part D and will qualify for the federal subsidy offered under the Act. The Company expects that its share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based will be reduced by the expected subsidy.

During the third quarter of 2004, the Company adopted FSP 106-2 retroactive to the beginning of the year. 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 approximately $4.9 million and reduced its net periodic benefit cost for 2004 by $757,000 of which approximately 13.1% was credited to capital additions as a reduction of capitalized labor. The APBO reduction will be accounted for as an actuarial experience gain in accordance with the guidance in FAS 106 and was not included as a reduction to the net periodic benefit cost in 2004. The adoption of FSP 106-2 had the effect of reducing 2004 operating expenses by $658,000. Retroactive application resulted in the restatement of first and second quarter 2004 operating expenses and net income, reducing operating expenses and increasing net income by $164,000 in each quarter. In accordance with the provisions of the Act, the expected subsidy will have no effect on income tax expense.

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 Company does not expect the application of the requirements of SFAS No. 151 to have an effect on the Company’s 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 its 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 in July 2005 with early adoption allowed and, when adopted, can be applied under a modified prospective basis or on a modified retrospective basis back to January 1, 2005. The Company will adopt SFAS No. 123(R) in July 2005 but has not determined whether it will apply the requirements prospectively or retrospectively. In either event, the Company has determined that the application of SFAS No. 123(R) reporting requirements will have the effect of reducing its 2005 net income by $300,000 to $600,000.

2.   BUSINESS COMBINATIONS, DISPOSITIONS AND SEGMENT INFORMATION

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 approximately $69.0 million in cash. An additional $6.0 million in cash was placed in escrow to pay off earn-out contingencies if IPH achieves certain financial targets for the period from August 1, 2004 through July 31, 2005. See notes 6 and 9 for information related to the financing of this acquisition. The results of operations of IPH have been included in the Company’s consolidated results of operations since the date of acquisition. Pro forma results have not been presented for the acquisition since the effect of the acquisition on 2004 and previous years’ revenues, net income or earnings per share was not significant. This acquisition adds 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. For 2004 IPH was included in the other business operations segment. The Company expects that for 2005 IPH will be a separate segment.

Below is a condensed balance sheet at the date of the business combination disclosing the preliminary allocation of the purchase price assigned to each major asset and liability category for IPH.

(in thousands)
Assets
Current assets	$	17,766
Plant		35,296
Goodwill		23,087
Other intangible assets		13,200
Total assets	$	89,349
Liabilities and equity
Current liabilities	$	5,485
Deferred income taxes		12,408
Long-term debt		1,987
Class B common stock options		1,832
Equity		67,637
Total liabilities and equity	$	89,349

The above allocations are preliminary, subject to adjustment. 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. Foley Company had gross revenues of $44.8 million in 2002. 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 the companies in 2003 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 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 and equity
Current liabilities	$	8,618	$	669
Long-term debt		—		136
Other long-term liabilities		1,712		—
Equity		12,282		1,941
Total liabilities and equity	$	22,612	$	2,746

Goodwill related to the Foley acquisition is not deductible for income tax purposes. The goodwill related to the other 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.

On May 1, 2002 the Company acquired 100% of the outstanding stock of Computed Imaging Service, Inc. (CIS), of Houston, Texas, for 158,257 shares of Otter Tail Corporation common stock and approximately $1.2 million in cash. CIS provides computed tomography and magnetic resonance imaging mobile services, interim rental, and sales and service of new, used and refurbished diagnostic imaging equipment. CIS serves hospitals and other healthcare facilities in the south-central United States. The acquisition of CIS allowed the Company to expand its existing health services operations into another region of the country. CIS annual revenues were approximately $5.9 million in 2001.

On May 28, 2002 the Company acquired 100% of the outstanding stock of ShoreMaster, Inc. (ShoreMaster), of Fergus Falls, Minnesota, for 303,124 shares of Otter Tail Corporation common stock and $2.3 million in cash. ShoreMaster is a leading manufacturer of waterfront equipment ranging from residential-use boatlifts and docks to commercial marina systems. The acquisition of ShoreMaster provides diversification and growth opportunities for the Company’s manufacturing segment. ShoreMaster’s annual revenues were approximately $20 million in 2001.

On October 1, 2002 the Company acquired 100% of the outstanding stock of Galva Foam Marine Industries, Inc. (Galva Foam), of Camdenton, Missouri, for 256,940 shares of Otter Tail Corporation common stock and approximately $1.0 million in cash. Galva Foam is a leading manufacturer of waterfront equipment ranging from residential boatlifts and docks to commercial marina systems. The acquisition of Galva Foam in combination with the May 2002 acquisition of ShoreMaster expands the market reach of the Company’s waterfront manufacturing product line nationwide with both saltwater and freshwater products. Galva Foam had annual revenues of approximately $13 million in 2001.

In 2002, the Company also acquired two other businesses - one in energy management services and the other in health services. The total purchase price for these businesses was approximately $2 million in cash.

Below is a condensed balance sheet disclosing the fair value assigned to each major asset and liability category for the companies acquired in 2002.

(in thousands)	CIS		ShoreMaster		Galva Foam		Others
Assets
Current assets	$	1,439	$	9,510	$	4,953	$	131
Plant		3,975		4,599		1,713		298
Goodwill		5,847		4,292		2,650		1,616
Other intangible assets		30		4,461		41		60
Total assets	$	11,291	$	22,862	$	9,357	$	2,105
Liabilities and equity
Current liabilities	$	1,747	$	9,642	$	2,304	$	32
Long-term debt		2,584		2,723		—		—
Other long-term liabilities		707		797		372		—
Equity		6,253		9,700		6,681		2,073
Total liabilities and equity	$	11,291	$	22,862	$	9,357	$	2,105

All of the acquisitions were accounted for using the purchase method of accounting. The pro forma effect of these acquisitions on 2003 and 2002 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 five segments based on products and services and reach customers in all 50 states and international markets. The five segments are: Electric, Plastics, Manufacturing, Health Services 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 consists of businesses producing polyvinyl chloride and polyethylene pipe in the Upper Midwest and Southwest regions of the United States.

Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, frame-straightening equipment and accessories for the auto body shop industry, material and handling trays and horticultural containers, fabrication of steel products, contract machining, and metal parts stamping and fabrication. These businesses are located primarily in the Upper Midwest, Missouri and Utah.

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.

Other Business Operations consists of businesses involved in food ingredient processing; 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 and the food ingredient processing business that has sales to the United States, Canada, Europe, the Middle East, the Pacific Rim and Central America.

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 2004, 2003 and 2002 is presented in the following table.

(in thousands)	2004			2003			2002
Operating revenue
Electric	$	266,385		$	267,494		$	244,005
Plastics		115,426			86,009			82,931
Manufacturing		226,577			177,805			142,390
Health services		114,318			100,912			93,420
Other business operations		162,351			114,726			75,947
Intersegment eliminations		(2,733	)		(2,254	)		(1,036	)
Total	$	882,324		$	744,692		$	637,657
Depreciation and amortization
Electric	$	24,236		$	26,008		$	24,910
Plastics		2,297			2,126			1,760
Manufacturing		8,701			7,708			6,525
Health services		5,047			5,137			4,410
Other business operations		4,063			2,841			2,921
Total	$	44,344		$	43,820		$	40,526
Income before income taxes
Electric	$	45,234		$	48,689		$	45,643
Plastics		9,453			3,341			9,478
Manufacturing		11,448			5,695			7,510
Health services		5,075			4,197			7,691
Other business operations		(14,226	)		(10,745	)		(7,391	)
Total	$	56,984		$	51,177		$	62,931
Earnings available for common shares
Electric	$	30,799		$	33,411		$	31,244
Plastics		5,657			2,019			5,668
Manufacturing		6,911			3,885			4,524
Health services		2,951			2,464			4,555
Other business operations		(7,074	)		(4,900	)		(2,551	)
Total	$	39,244		$	36,879		$	43,440
Capital expenditures
Electric	$	25,368		$	28,177		$	45,842
Plastics		2,544			3,984			5,592
Manufacturing		13,471			9,903			15,049
Health services		3,919			5,427			3,874
Other business operations		4,490			1,603			3,717
Total	$	49,792		$	49,094		$	74,074
Identifiable assets
Electric	$	634,433		$	609,190		$	586,231
Plastics		67,574			58,538			54,926
Manufacturing		165,307			138,493			114,120
Health services		66,506			67,587			64,785
Other business operations		183,898			95,350			76,334
Discontinued operations		16,430			17,265			17,716
Total	$	1,134,148		$	986,423		$	914,112

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. For the year ended December 31, 2004, 97.1% of the Company’s consolidated revenue came from sales within the United States and 2.0% came from sales in Canada, with the remaining 0.9% coming from various foreign countries in Europe, the Middle East, the Pacific Rim and Asia. For the year ended December 31, 2003, substantially all of the Company’s consolidated revenue came from sales within the United States.

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 is in place through 2005, unless suspended or terminated by the NDPSC or the Company. This plan provides the opportunity for the electric utility to raise its allowed rate of return and share income with customers when earnings exceed the allowed return. Because the electric utility’s 2002 and 2003 rates of return were within the allowable range defined in the plan, no sharing occurred in 2003 or 2004. The electric utility’s 2004 rate of return is expected to be within the allowable range defined in the plan.

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)	2004		2003
Regulatory assets:
Deferred income taxes	$	14,526	$	12,750
Debt expenses and reacquisition premiums		3,424		3,863
Deferred conservation program costs		1,203		882
Plant acquisition costs		240		285
Deferred marked-to-market losses		331		1,802
Accrued cost-of-energy revenue		3,348		3,693
Accumulated ARO accretion/depreciation adjustment		114		117
Total regulatory assets	$	23,186	$	23,392
Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	49,823	$	33,579
Deferred income taxes		6,727		7,496
Deferred marked-to-market gains		197		1,684
Gain on sale of division office building		162		167
Total regulatory liabilities	$	56,909	$	42,926
Net regulatory liability position	$	33,723	$	19,534

The regulatory assets and liabilities related to deferred income taxes are the result of the adoption of SFAS No. 109, Accounting for Income Taxes. Debt expenses 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 17.6 years. Deferred conservation program costs included in Deferred debits – Other represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. Plant acquisition costs included in Deferred debits – Other will be amortized over the next 5.4 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 June 2005. 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 these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. Although these contracts are classified as derivatives, the electric utility does not use them for hedging and does not presently hold these contracts for trading purposes.

Electric revenues include $27,053,000 in 2004 and $29,530,000 in 2003 related to wholesale electric sales and net unrealized derivative gains on forward energy contracts broken down as follows for the years ended December 31:

(in thousands)	2004			2003
Wholesale sales—company-owned generation	$	17,795		$	18,428
Wholesale sales—purchased power at market prices		134,715			121,303
Market cost of purchased power resold		(128,685	)		(114,259	)
Net margins on wholesale sales of purchased power		6,030			7,044
Marked-to-market gains on settled contracts		12,663			2,978
Marked-to-market losses on settled contracts		(9,736	)		(977	)
Net marked-to-market gain on settled contracts		2,927			2,001
Unrealized marked-to-market gains on open contracts		514			6,338
Unrealized marked-to-market losses on open contracts		(213	)		(4,281	)
Net unrealized marked-to-market gain on open contracts		301			2,057
Wholesale electric revenue	$	27,053		$	29,530

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 as of December 31, 2004 and 2003 and the change in its consolidated balance sheet position from December 31, 2003 to December 31, 2004:

	December 31,			December 31,
(in thousands)	2004			2003
Current asset—marked-to-market gain	$	711		$	5,443
Regulatory asset—deferred marked-to-market loss		331			1,802
Total assets		1,042			7,245
Current liability—marked-to-market loss		(544	)		(3,504	)
Regulatory liability—deferred marked-to-market gain		(197	)		(1,684	)
Total liabilities		(741	)		(5,188	)
Net fair value of marked-to-market energy contracts	$	301		$	2,057

	Year ended
	December 31,
(in thousands)	2004
Fair value at beginning of year	$	2,057
Amount realized on contracts entered into in 2003 and settled in 2004		(1,967	)
Changes in fair value of contracts entered into in 2003		(90	)
Net fair value of contracts entered into in 2003 at year end 2004		—
Changes in fair value of contracts entered into in 2004		301
Net fair value at end of year	$	301

The $301,000 in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market as of December 31, 2004 is expected to be realized on physical settlement or settled by offsetting agreement with the counterparty to the original contract as scheduled over the following quarters in the amounts listed:

	1st		2nd
	Quarter		Quarter
(in thousands)	2005		2005		Total
Net gain	$	276	$	25	$	301

Of the forward energy contracts that are marked-to-market as of December 31 2004, 45% of the forward energy purchases have offsetting sales in terms of volumes and delivery periods. The amount of unrealized marked-to-market gains recognized on forward energy purchases that are not offset by forward energy sales is $144,000.

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.

In November and December 2004, the Company’s energy services subsidiary entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133. 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 statement of income for the year ended December 31, 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 2004:

(in thousands)	2004
Gains on settled contracts	$	780
Losses on settled contracts		(747	)
Net Gain on settled contracts	$	33
Unrealized gains on open contracts (derivative asset)		1,834
Unrealized losses on open contracts (derivative liability)		(1,700	)
Net unrealized gain on open contracts		134
Net revenue recognized	$	167

6.   COMMON SHARES AND EARNINGS PER SHARE

NEW ISSUANCES

During December 2004, the Company completed a public offering of 2,900,000 shares under its universal shelf registration statement filed with the Securities and Exchange Commission in June. The public offering price was $25.45 per share with proceeds after underwriting discounts and commissions of $24.50 per share. In addition during 2004, the Company issued 223,165 shares to meet the requirements of the Company’s dividend reinvestment program and share purchase plan, 66,958 shares to meet the requirements of the Company’s employee stock purchase plan, 51,542 shares as a result of stock options exercised, 8,179 shares of restricted stock for officers’ and directors’ compensation, net of shares withheld for taxes and 3,261 shares as directors’ compensation.

In January 2005, 175,000 shares of common stock were issued as a result of the underwriters exercising a portion of their over-allotment option in connection with the Company’s public offering. The proceeds to the Company were $24.50 per share.

STOCK INCENTIVE PLAN

Presented below is a summary of the stock options activity:

	2004				2003				2002
			Average				Average				Average
			exercise				exercise				exercise
Stock Option Activity	Options		price		Options		price		Options		price
Outstanding, beginning of year		1,531,125	$	25.16		1,360,721	$	24.68		1,265,042	$	22.62
Granted		72,400		26.50		222,750		27.24		278,750		31.34
Exercised		51,468		19.83		47,700		20.21		130,797		19.71
Forfeited		43,780		27.37		4,646		23.09		52,274		22.83
Outstanding, year-end		1,508,277	$	25.35		1,531,125		25.16		1,360,721		24.68
Exercisable, year-end		1,111,681	$	24.27		791,661	$	22.97		449,385	$	21.75
Fair value of options granted during year	$	5.27			$	5.42			$	7.07

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 options, performance awards, restricted stock, stock appreciation rights and other types of stock grants or stock-based awards. 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 outside directors are exercisable immediately and all other options granted prior to 2004 vest over a four-year period. Stock options granted during April 2004 vested six months from the grant date. Restricted stock granted as of December 31, 2004 vests ratably over a four-year period. The options expire ten years after the date of the grant. The Company accounts for the Incentive Plan under APB No. 25.

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

	2004			2003			2002
Risk-free interest rate		3.9	%		3.7	%		5.2	%
Expected lives	7 years			7 years			7 years
Expected volatility		25.7	%		26.3	%		26.0	%
Dividend yield		4.0	%		4.0	%		4.0	%

The following table summarizes information about options outstanding as of December 31, 2004:

	Options outstanding						Options exercisable
			Weighted-
			average		Weighted-				Weighted-
	Outstanding		remaining		average		Exercisable		average
Range of	as of		contractual		exercise		as of		exercise
exercise prices	12/31/04		life (yrs)		price		12/31/04		price
$18.80-$21.94		440,377		4.6	$	19.48		440,377	$	19.48
$21.95-$25.07		—		—		—		—		—
$25.08-$26.77		583,400		6.6	$	26.28		476,150	$	26.29
$26.78-$31.34		484,500		7.7	$	29.55		195,154	$	30.15

In addition to the stock options granted, 21,340, 90,900 and 85,800 shares of restricted stock were granted during 2004, 2003 and 2002, respectively. The total compensation cost recognized in income for stock-based employee compensation awards was $1,302,000 in 2004, $1,110,000 in 2003 and $879,000 in 2002. See note 1 for pro forma stock option information.

During 2004, the Company’s Board of Directors granted performance-based stock incentive awards to the Company’s executive officers under the Incentive Plan. Under these awards, the officers could earn up to an aggregate of 70,500 shares of common stock based on the Company’s stock performance relative to the stock performances of its peer group of companies in the Edison Electric Institute Index over a three-year period ending on December 31, 2006. The number of shares earned, if any, would be awarded and issued at the end of the three-year performance period. The officers have no voting or dividend rights related to the eligible shares until the shares are issued at the end of the performance period. Due to the performance of the stock price during 2004, no compensation expense was recognized during 2004 for this award.

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. Of the 400,000 common shares authorized for purchase under the Purchase Plan, 64,267 were still available for purchase as of December 31, 2004. To provide shares for the Purchase Plan, 66,958 common shares were issued in 2004 and prior to 2004, common shares were purchased in the open market totaling 66,724 shares in 2003 and 57,997 shares in 2002. Beginning in 2005, the Company will purchase shares on the open market for this plan.

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 the Company began purchasing common shares on the open market. Through December 31, 2004, 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 10, 1997. One Right was also issued with respect to each common share issued after February 10, 1997. Each Right entitles the holder to purchase from the Company one one-hundredth of a share of newly created Series A Junior Participating Preferred Stock at a price of $70, subject to certain adjustment. The Rights are exercisable when, and are not transferable apart from the Company’s common shares until, a person or group has acquired 15% 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, 2004.

8.   COMMITMENTS AND CONTINGENCIES

At December 31, 2004 the electric utility had commitments under contracts in connection with construction programs aggregating approximately $6,431,000. For capacity and energy requirements, the electric utility has agreements extending through 2009 at annual costs of approximately $19,850,000 in 2005, $17,165,000 in 2006, $18,140,000 in 2007, $18,963,000 in 2008 and $20,089,000 in 2009.

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 $99,812,000 or to make payments in lieu thereof, under these contracts. The cost-of-energy adjustment mechanism lessens the risk of loss from market price changes because it provides for recovery of most fuel costs.

The amounts of future operating lease payments are as follows:

(in thousands)	Electric		Nonelectric		Total
2005	$	1,818	$	28,294	$	30,112
2006		1,818		24,821		26,639
2007		1,590		19,019		20,609
2008		1,135		12,601		13,736
2009		1,135		9,850		10,985
Later years		1,035		8,122		9,157
Total	$	8,531	$	102,707	$	111,238

Rent expense from continuing operations was $28,343,000, $25,503,000 and $22,032,000, for 2004, 2003 and 2002, 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 probable liabilities on the eventual disposition of these matters. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all currently pending matters will not be material.

9.   SHORT-TERM AND LONG-TERM BORROWINGS

SHORT-TERM DEBT

There was $39,950,000 in short-term debt outstanding as of December 31, 2004, 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%. As of December 31, 2003 the Company had $30 million in short-term debt outstanding at a composite interest rate of 1.5%. The average interest rate paid on short-term debt was 2.2% in 2004 and 1.7% in 2003.

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 proceeds from the issuance of 2.9 million shares of common stock. 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 from the over-allotment related to the public offering and by borrowing from the Company’s line of credit. The interest rate paid on the outstanding balance on bridge loan was LIBOR plus 0.6%.

On April 28, 2004 the Company renewed its $70 million line of credit. The renewed agreement expires on April 27, 2005. The terms of the renewed line of credit at the time of renewal were essentially the same as those in place prior to the renewal. In October 2004, the Company amended the terms of its $70 million line of credit agreement solely to remove the ratings trigger that would require accelerated repayment of any outstanding balance on the line of credit in the event the Company’s senior unsecured debt is rated below Baa3 (Moody’s) or BBB- (Standard & Poor’s). The removal of the ratings trigger resulted in no changes to the interest rate charged on line borrowings and no material changes to other terms of the agreement. 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. 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). In December 2004 Standard & Poor’s Rating Services lowered the Company’s corporate credit rating and senior unsecured debt rating from A-/negative to BBB+/negative. Moody’s rating remains at A2/negative. As a result of this split rating, the Company’s interest rate on its line of credit increased to 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 stock, preferred stock, 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 2004. In 2004, $30,000 of Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022 were redeemed for estate settlement purposes and retired.

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 commencing on October 1, 2003 until the principal balance is repaid in full. The Company used proceeds from the note to pay down borrowings under the Company’s line of credit that were used to finance acquisitions and capital expenditures of its nonelectric subsidiaries. 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, 2004, excluding the long-term debt reported under Liabilities from discontinued operations, for each of the next five years are $6,055,000 for 2005, $4,331,000 for 2006, $54,628,000 for 2007, $2,888,000 for 2008 and $2,849,000 for 2009.

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.

As of December 31, 2004 the Company was in compliance with all of the covenants under its line of credit and its other debt obligations.

10.   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 combined exercise price of all the outstanding options is $487,000. The options are exercisable at any time and the option holder must deliver cash to convert the option into a Class B share. Once the options are converted to 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.

11.   PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

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, 2004 and a statement of the funded status as of December 31 of both years:

(in thousands)	2004			2003
Reconciliation of benefit obligation:
Obligation at January 1	$	154,159		$	145,262
Service cost		4,063			3,779
Interest cost		9,458			9,491
Benefit payments		(8,600	)		(8,190	)
Actuarial loss		7,110			3,817
Obligation at December 31	$	166,190		$	154,159
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1	$	132,811		$	113,803
Actual return on plan assets		13,474			27,198
Discretionary company contributions		4,000			—
Benefit payments		(8,600	)		(8,190	)
Fair value of plan assets at December 31	$	141,685		$	132,811
Funded status	$	(24,505	)	$	(21,348	)
Unrecognized net actuarial loss		28,607			22,533
Unrecognized prior service cost		6,127			7,025
Net amount recognized	$	10,229		$	8,210

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

(in thousands)	2004		2003
Prepaid pension cost	$	10,229	$	8,210

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

(in thousands)	2004		2003
Projected benefit obligation	$	166,190	$	154,159
Accumulated benefit obligation		137,682		130,072
Fair value of plan assets		141,685		132,811

Components of net periodic pension benefit cost:

(in thousands)	2004			2003			2002
Service cost—benefit earned during the period	$	4,063		$	3,779		$	3,120
Interest cost on projected benefit obligation		9,458			9,491			9,269
Expected return on assets		(12,438	)		(12,933	)		(14,957	)
Amortization of transition asset		—			—			(73	)
Amortization of prior-service cost		897			1,170			1,285
Amortization of net gain		—			—			(1,284	)
Net periodic pension cost/(income)	$	1,980		$	1,507		$	(2,640	)

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

	2004			2003
Discount rate		6.00	%		6.25	%
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:

	2004			2003
Discount rate		6.25	%		6.75	%
Long-term rate of return on plan assets		8.50	%		8.50	%
Rate of increase in future compensation level		3.75	%		4.25	%

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 2005 net periodic pension cost is 8.5%.

The Company’s pension plan weighted-average asset allocations at December 31, 2004 and 2003, by asset category are as follows:

Asset Category	2004			2003
Large capitalization equity securities		48.4	%		52.9	%
Small capitalization equity securities		11.2	%		10.4	%
International equity securities		14.7	%		12.9	%
Total equity securities		74.3	%		76.2	%
Cash and fixed-income securities		25.7	%		23.8	%
		100.0	%		100.0	%

The following objectives guide the decisions and investment strategy of the Company’s pension committee for the 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.

The asset allocation strategy developed by the Company’s pension 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 below 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 pension committee and/or investment managers, and required cash flows to and from the Plan. The tactical range shown below provides flexibility for the investment managers’ portfolios to vary around the target allocation without the need for immediate rebalancing. The Company’s pension committee monitors actual asset allocations and

directs contributions and withdrawals toward maintaining the targeted allocation percentages listed in the table below.

Security class	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 2005. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

(in thousands)		Years
2005		2006		2007		2008		2009		2010-2014
$	8,422	$	8,453	$	8,594	$	8,743	$	8,919	$	50,136

EXECUTIVE SURVIVOR AND SUPPLEMENTAL RETIREMENT PLAN (ES&SRP)

The Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees. This plan provides defined benefit payments to these employees on their retirement for life or to their beneficiaries on their death 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.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations over the two-year period ended December 31, 2004 and a statement of the funded status as of December 31 of both years:

(in thousands)	2004			2003
Reconciliation of benefit obligation:
Obligation at January 1	$	24,451		$	20,309
Service cost		820			417
Interest cost		1,489			1,426
Plan amendments		—			1,083
Actuarial (gain) loss		(2,543	)		2,242
Benefit payments		(1,094	)		(1,026	)
Obligation at December 31	$	23,123		$	24,451
Funded status:
Funded status at December 31	$	(23,123	)	$	(24,451	)
Unrecognized prior-service cost		1,626			1,772
Unrecognized net actuarial loss		8,737			11,961
Net amount recognized	$	(12,760	)	$	(10,718	)

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

(in thousands)	2004			2003
Accrued benefit liability	$	(16,703	)	$	(16,919	)
Intangible asset		1,626			1,772
Accumulated other comprehensive loss		2,317			4,429
Net amount recognized	$	(12,760	)	$	(10,718	)

Additional information on the ES&SRP defined benefit pension plan as of December 31:

(in thousands)	2004		2003
Projected benefit obligation	$	23,123	$	24,451
Accumulated benefit obligation		16,703		16,919
Fair value of plan assets		—		—

Components of net periodic pension benefit cost:

(in thousands)	2004		2003		2002
Service cost—benefit earned during the period	$	820	$	417	$	(51	)
Interest cost on projected benefit obligation		1,489		1,426		1,175
Amortization of prior-service cost		147		147		86
Recognized net actuarial loss		680		573		398
Net periodic pension cost	$	3,136	$	2,563	$	1,608
Early retirement benefit		—		—		240
Total	$	3,136	$	2,563	$	1,848

The change in the additional minimum liability included in other comprehensive loss was ($2,112,000) in 2004 and ($606,000) in 2003.

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

	2004			2003
Discount rate		6.00	%		6.25	%
Rate of increase in future compensation level		4.74	%		5.88	%

Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:

	2004			2003
Discount rate		6.25	%		6.75	%
Rate of increase in future compensation level		5.88	%		5.63	%

Cash Flows

The ES&SRP 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
2005	2006		2007		2008		2009		2010-2014
$         1,152	$	1,151	$	1,147	$	1,132	$	1,131	$	6,016

On January 1, 2005, the Company amended this plan to reduce future benefits to plan participants and reduce costs to the Company.

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.

The following tables provide a reconciliation of the changes in the plan’s benefit obligations over the two-year period ended December 31, 2004 and a statement of the funded status as of December 31 of both years:

(in thousands)	2004			2003
Reconciliation of benefit obligation:
Obligation at January 1	$	42,008		$	39,318
Service cost		1,133			1,009
Interest cost		2,271			2,619
Benefit payments		(3,449	)		(2,981	)
Participant premium payments		1,134			1,051
Decrease due to Medicare Part D subsidy		(4,935	)		—
Actuarial loss		1,477			992
Obligation at December 31	$	39,639		$	42,008
Funded status:
Funded status at December 31	$	(39,639	)	$	(42,008	)
Unrecognized transition obligation		5,985			6,734
Unrecognized prior-service cost		1,005			700
Unrecognized loss		7,596			11,344
Net amount recognized	$	(25,053	)	$	(23,230	)

The net amounts recognized are shown on the consolidated balance sheets as of December 31, 2004 and 2003 under the title of Other postretirement benefits liability.

Components of net periodic postretirement benefit cost:

(in thousands)	2004			2003			2002
Service cost	$	1,170		$	1,009		$	615
Interest cost		2,580			2,619			2,166
Amortization of transition obligation		748			748			748
Amortization of prior-service cost		(305	)		(305	)		(305	)
Amortization of net loss		702			708			—
Expense decrease due to Medicare part D subsidy		(757	)		—			—
Net periodic postretirement benefit cost	$	4,138		$	4,779		$	3,224

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

	2004			2003
Discount rate		6.00	%		6.25	%

Weighted-average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:

	2004			2003
Discount rate		6.25	%		6.75	%

Assumed healthcare cost-trend rates as of December 31:

	2004			2003
Healthcare cost-trend rate assumed for next year		10.0	%		11.0	%
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 2004 would have the following effects:

	1 point		1 point
(in thousands)	increase		decrease
Effect on total of service and interest cost	$	547	$	(440	)
Effect on the postretirement benefit obligation	$	4,909	$	(4,086	)

Cash Flows

The Company expects to contribute $2.6 million net of expected employee contributions for the payment of retiree medical benefits in 2005. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

(in thousands)	Years
2005	2006		2007		2008		2009		2010-2014
$           2,581	$	2,267	$	2,395	$	2,457	$	2,519	$	13,026

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 $930,000 for 2004, $1,030,000 for 2003 and $1,100,000 for 2002.

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 $24.4 million of the Company’s long-term debt, which is subject to variable interest rates, approximates fair value.

	December 31, 2004						December 31, 2003
	Carrying			Fair			Carrying			Fair
(in thousands)	amount			value			amount			value
Cash and short-term investments	$	—		$	—		$	7,311		$	7,311
Other investments		14,450			14,450			8,607			8,607
Long-term debt		(261,810	)		(291,155	)		(262,363	)		(289,774	)

13.   PROPERTY, PLANT AND EQUIPMENT

(December 31, in thousands)	2004		2003
Electric plant:
Production	$	347,800	$	346,890
Transmission		180,150		175,953
Distribution		285,253		272,909
General		76,997		79,612
Electric plant		890,200		875,364
Less accumulated depreciation and amortization		363,696		368,899
Electric plant net of accumulated depreciation		526,504		506,465
Construction work in progress		12,212		13,938
Net electric plant	$	538,716	$	520,403
Nonelectric operations plant	$	214,079	$	169,005
Less accumulated depreciation and amortization		76,954		68,594
Nonelectric plant net of accumulated depreciation		137,125		100,411
Construction work in progress		6,257		3,956
Net nonelectric operations plant	$	143,382	$	104,367
Net plant	$	682,098	$	624,770

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 2004, 2003 and 2002) to net income before total income tax expense for the following reasons:

(in thousands)	2004			2003			2002
Tax computed at federal statutory rate	$	19,944		$	17,912		$	22,026
Increases (decreases) in tax from:
State income taxes net of federal income tax benefit		1,774			1,792			2,227
Investment tax credit amortization		(1,152	)		(1,152	)		(1,152	)
Differences reversing in excess of federal rates		(136	)		(1,283	)		(1,055	)
Dividend received/paid deduction		(703	)		(707	)		(699	)
Affordable housing tax credits		(1,418	)		(1,412	)		(1,418	)
Permanent and other differences		(1,305	)		(1,587	)		(1,174	)
Total income tax expense	$	17,004		$	13,563		$	18,755
Income tax expense - discontinued operations	$	1,483		$	1,367		$	1,306
Overall effective federal and state income tax rate		30.5	%		27.4	%		30.3	%
Income tax expense includes the following:
Current federal income taxes	$	15,006		$	10,666		$	17,863
Current state income taxes		2,894			2,813			3,492
Deferred federal income taxes		1,672			2,675			(162	)
Deferred state income taxes		177			(27	)		132
Affordable housing tax credits		(1,418	)		(1,412	)		(1,418	)
Investment tax credit amortization		(1,152	)		(1,152	)		(1,152	)
Foreign income taxes		(175	)		—			—
Total	$	17,004		$	13,563		$	18,755

The Company’s deferred tax assets and liabilities were composed of the following on December 31, 2004 and 2003:

(in thousands)	2004			2003
Deferred tax assets
Amortization of tax credits	$	6,698		$	7,437
Vacation accrual		2,219			1,926
Unearned revenue		2,095			1,592
Benefit liabilities		20,100			18,051
Cost of removal		19,431			13,096
Differences related to property		6,565			6,079
Transfer to regulatory liability		31			63
Other		2,853			2,068
Total deferred tax assets	$	59,992		$	50,312
Deferred tax liabilities
Differences related to property	$	(155,491	)	$	(128,568	)
Excess tax over book pension		(4,041	)		(3,260	)
Transfer to regulatory asset		(14,528	)		(12,751	)
Other		(2,523	)		(3,251	)
Total deferred tax liabilities	$	(176,583	)	$	(147,830	)
Deferred income taxes	$	(116,591	)	$	(97,518	)

15.   DISCONTINUED OPERATIONS

Midwest Information Systems, Inc. (MIS): As part of an ongoing evaluation of the prospects and growth opportunities of the Company’s business operations, the Company has decided to exit the telecommunications business. As of December 31, 2004 MIS met the requirements to be reported as discontinued operations in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The Company expects to complete the sale of this business prior to the end of 2005. For segment reporting purposes, the discontinued operations had been included in the other business operations segment.

The results of discontinued operations for the years ended December 31, 2004, 2003 and 2002 are summarized as follows:

(in thousands)	2004		2003		2002
Operating revenues	$	8,739	$	8,547	$	8,680
Income before income taxes		3,698		3,409		3,258
Income tax expense		1,483		1,367		1,306

At December 31, 2004 and 2003 the major components of assets and liabilities of the discontinued operations were as follows:

(in thousands)	2004		2003
Current assets	$	275	$	250
Investments and other assets		2,270		2,535
Goodwill–net		5,925		5,925
Net plant		7,960		8,555
Assets of discontinued operations	$	16,430	$	17,265
Current liabilities	$	2,920	$	3,199
Deferred credits		581		593
Long-term debt		1,710		2,830
Liabilities of discontinued operations	$	5,211	$	6,622

16.   ASSET RETIREMENT OBLIGATIONS (AROS)

The Company’s asset retirement obligations include site restoration, the closure of ash pits and the removal of storage tanks and asbestos at certain electric utility generating plants. The Company has legal obligations associated with retirement of other long-lived assets used in its electric operations that cannot be reasonably estimated because the useful lives of those assets are not determinable. There are no assets legally restricted for the settlement of any of the Company’s asset retirement obligations.

The present value of the legal asset retirement obligations as of December 31, 2004 of $1,437,000 is included in Other noncurrent liabilities on the Company’s December 31, 2004 consolidated balance sheet. The ARO liability includes the original obligation of $377,000 less a 2004 subsequent measurement adjustment of $28,000 plus accumulated accretion expense of $1,088,000. Accumulated accretion on the AROs as of December 31, 2003 was $1,218,000. The change in accumulated accretion in 2004 included accretion expense of $90,000 and an adjustment to accumulated accretion of ($220,000) as a result of approved extensions of the depreciable lives of Coyote Station and Big Stone Plant which pushed back the expected retirement date for these plants.

17.   SUBSEQUENT EVENTS

On January 3, 2005 the Company acquired the assets of Performance Tool & Die, Inc., a manufacturer of mid to large dies, of Lakeville, Minnesota, for $4.0 million. This company is a division of BTD Manufacturing, Inc. Also on January 3, 2005 the Company acquired the stock of Shoreline Industries, Inc., a manufacturer of boat lift motors located in Pine River, Minnesota, for $2.2 million. This company is a subsidiary of ShoreMaster, Inc.

On February 2, 2005, the Company entered into a nonbinding letter of intent to sell the stock of St. George Steel Fabrication, Inc., which had 2004 revenues of $17.2 million. The sale is not expected to have a material impact on the 2005 results of operations.

18.   QUARTERLY INFORMATION (UNAUDITED)

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
(in thousands, except per share data)	2004 (b)		2003		2004 (b)		2003		2004		2003		2004		2003
Operating revenues (a)	$	204,608	$	170,187	$	209,115	$	178,029	$	220,106	$	198,860	$	248,495	$	197,616
Operating income (a)		15,486		17,520		14,628		14,137		19,815		21,566		24,507		14,569
Net Income:
Continuing operations		7,817		9,415		7,532		7,960		10,497		11,527		14,134		8,712
Discontinued operations		442		447		500		474		529		434		744		687
		8,259		9,862		8,032		8,434		11,026		11,961		14,878		9,399
Earnings available for common shares:
Continuing operations		7,633		9,231		7,348		7,776		10,313		11,343		13,950		8,529
Discontinued operations		442		447		500		474		529		434		744		687
		8,075		9,678		7,848		8,250		10,842		11,777		14,694		9,216
Basic earnings per share:
Continuing operations	$	.29	$	.36	$	.28	$	.30	$	.40	$	.44	$	.52	$	.33
Discontinued operations		.02		.02		.02		.02		.02		.02		.03		.03
		.31		.38		.30		.32		.42		.46		.55		.36
Diluted earnings per share:
Continuing operations	$	.29	$	.36	$	.28	$	.30	$	.40	$	.44	$	.52	$	.33
Discontinued operations		.02		.02		.02		.02		.02		.02		.03		.03
		.31		.38		.30		.32		.42		.46		.55		.36
Dividends paid per common share		.275		.27		.275		.27		.275		.27		.275		.27
Price range:
High	$	27.50	$	28.59	$	27.19	$	28.90	$	26.96	$	28.41	$	27.36	$	28.50
Low		26.00		23.76		24.07		25.27		23.77		25.60		24.99		25.92
Average number of common shares
outstanding—basic		25,793		25,592		25,891		25,673		26,010		25,708		26,663		25,719
Average number of common shares
outstanding—diluted		25,936		25,730		26,014		25,855		26,122		25,869		26,780		25,876

(a)	From continuing operations.
(b)	Includes adjustment for Medicare Part D benefit of $164,000 per quarter under FSP 106-2 adopted in July 2004 but applied retroactively to January 1, 2004.

Stock Listing

Otter Tail Corporation common stock trades on The Nasdaq Stock Market.