SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006                                                                                             

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number       0-368                             

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota	41-0462685
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

215 South Cascade Street, Box 496, Fergus Falls, Minnesota	56538-0496
(Address of principal executive offices)	(Zip Code)

866-410-8780

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ       NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer þ            Accelerated filer o            Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). YES o       NO þ

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date:

April 30, 2006 – 29,461,507 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

			Page No.
Part I. Financial Information
	Item 1.	Financial Statements
		Consolidated Balance Sheets – March 31, 2006 and December 31, 2005 (not audited)	2 & 3
		Consolidated Statements of Income - Three Months Ended March 31, 2006 and 2005 (not audited)	4
		Consolidated Statements of Cash Flows - Three Months Ended March 31, 2006 and 2005 (not audited)	5
		Notes to Consolidated Financial Statements (not audited)	6-19
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20-32
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32-35
	Item 4.	Controls and Procedures	35
Part II. Other Information
	Item 1.	Legal Proceedings	36
	Item 1A.	Risk Factors	36
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
	Item 6.	Exhibits	36
Signatures			37
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)
-Assets-

	March 31,		December 31,
	2006		2005
	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	—	$	5,430
Accounts receivable:
Trade—net		130,103		128,355
Other		8,260		11,790
Inventories		106,458		88,677
Deferred income taxes		6,865		6,871
Accrued utility revenues		22,833		22,892
Costs and estimated earnings in excess of billings		35,618		21,542
Other		17,162		17,301
Assets of discontinued operations		981		2,317
Total current assets		328,280		305,175
Investments and other assets		35,972		33,824
Goodwill—net		98,110		98,110
Other intangibles—net		20,891		21,160
Deferred debits
Unamortized debt expense and reacquisition premiums		6,326		6,520
Regulatory assets and other deferred debits		19,538		19,616
Total deferred debits		25,864		26,136
Plant
Electric plant in service		917,222		910,766
Nonelectric operations		230,331		228,548
Total plant		1,147,553		1,139,314
Less accumulated depreciation and amortization		466,476		459,438
Plant—net of accumulated depreciation and amortization		681,077		679,876
Construction work in progress		24,773		17,215
Net plant		705,850		697,091
Total	$	1,214,967	$	1,181,496

See accompanying notes to consolidated financial statements

- 2 -

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
-Liabilities-

	March 31,			December 31,
	2006			2005
	(Thousands of dollars)
Current liabilities
Short-term debt	$	45,181		$	16,000
Current maturities of long-term debt		3,354			3,340
Accounts payable		111,730			106,570
Accrued salaries and wages		18,470			24,326
Accrued federal and state income taxes		12,996			8,776
Other accrued taxes		12,014			12,620
Other accrued liabilities		14,135			14,975
Liabilities of discontinued operations		330			372
Total current liabilities		218,210			186,979
Pensions benefit liability		22,716			23,216
Other postretirement benefits liability		27,476			26,982
Other noncurrent liabilities		17,454			18,683
Deferred credits
Deferred income taxes		113,183			113,737
Deferred investment tax credit		9,040			9,327
Regulatory liabilities		60,004			61,624
Other		1,305			1,500
Total deferred credits		183,532			186,188
Capitalization
Long-term debt, net of current maturities		257,553			258,260
Class B stock options of subsidiary		1,258			1,258
Cumulative preferred shares authorized 1,500,000 shares without par value; outstanding 2006 and 2005 — 155,000 shares		15,500			15,500
Cumulative preference shares — authorized 1,000,000 shares without par value; outstanding — none		—			—
Common shares, par value $5 per share authorized 50,000,000 shares; outstanding 2006 — 29,446,952 and 2005 — 29,401,223		147,235			147,006
Premium on common shares		95,402			96,768
Unearned compensation		—			(1,720	)
Retained earnings		234,832			228,515
Accumulated other comprehensive loss		(6,201	)		(6,139	)
Total common equity		471,268			464,430
Total capitalization		745,579			739,448
Total	$	1,214,967		$	1,181,496

See accompanying notes to consolidated financial statements

- 3 -

Otter Tail Corporation

Consolidated Statements of Income
(not audited)

	Three months ended
	March 31,
	2006		2005
	(In thousands, except share
	and per share amounts)
Operating revenues	$	278,778	$	232,133
Operating expenses
Production fuel		14,806		15,177
Purchased power — system use		18,736		11,538
Electric operation and maintenance expenses		23,407		23,918
Cost of goods sold (excludes depreciation; included below)		153,074		123,634
Other nonelectric expenses		26,316		22,741
Depreciation and amortization		12,224		11,385
Property taxes — electric operations		2,618		2,673
Total operating expenses		251,181		211,066
Operating income		27,597		21,067
Other income		429		194
Interest charges		4,494		4,566
Income from continuing operations before income taxes		23,532		16,695
Income taxes — continuing operations		8,572		5,645
Net income from continuing operations		14,960		11,050
Discontinued operations
Income from discontinued operations net of taxes of $333 in 2005		—		497
Loss on expected disposal of discontinued operations — net of tax of ($1,051) in 2005		—		(1,576	)
Net loss from discontinued operations		—		(1,079	)
Net income		14,960		9,971
Preferred dividend requirements		184		184
Earnings available for common shares	$	14,776	$	9,787
Basic earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.50	$	0.37
Discontinued operations	$	—	$	(0.03	)
	$	0.50	$	0.34
Diluted earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.50	$	0.37
Discontinued operations	$	—	$	(0.04	)
	$	0.50	$	0.33
Average number of common shares outstanding — basic		29,325,986		29,126,096
Average number of common shares outstanding — diluted		29,676,117		29,230,188
Dividends per common share	$	0.2875	$	0.2800

See accompanying notes to consolidated financial statements

- 4 -

Otter Tail Corporation

Consolidated Statements of Cash Flows
(not audited)

	Three months ended
	March 31,
	2006			2005
	(Thousands of dollars)
Cash flows from operating activities
Net income	$	14,960		$	9,971
Adjustments to reconcile net income to net cash provided by operating activities:
Net loss from sale of discontinued operations		—			1,576
Loss (income) from discontinued operations		—			(497	)
Depreciation and amortization		12,224			11,385
Deferred investment tax credit		(287	)		(288	)
Deferred income taxes		(866	)		(1,549	)
Change in deferred debits and other assets		(1,149	)		745
Discretionary contribution to pension plan		(2,000	)		—
Change in noncurrent liabilities and deferred credits		548			2,028
Allowance for equity (other) funds used during construction		(192	)		(180	)
Change in derivatives net of regulatory deferral		2,400			273
Stock compensation expense		339			324
Other — net		548			221
Cash (used for) provided by current assets and current liabilities:
Change in receivables		2,676			(2,644	)
Change in inventories		(17,811	)		(24,228	)
Change in other current assets		(19,131	)		(438	)
Change in payables and other current liabilities		(22,236	)		217
Change in interest and income taxes payable		6,374			4,477
Net cash (used in) provided by continuing operations		(23,603	)		1,393
Net cash provided by (used in) discontinued operations		405			(301	)
Net cash (used in) provided by operating activities		(23,198	)		1,092
Cash flows from investing activities
Capital expenditures		(15,473	)		(12,733	)
Proceeds from disposal of noncurrent assets		94			948
Acquisitions—net of cash acquired		—			(6,665	)
Increases in other investments		(1,331	)		(169	)
Net cash used in investing activities — continuing operations		(16,710	)		(18,619	)
Net proceeds from the sales of discontinued operations		900			—
Net cash provided by investing activities — discontinued operations		—			41
Net cash used in investing activities		(15,810	)		(18,578	)
Cash flows from financing activities
Change in checks written in excess of cash		12,842			8,132
Net short-term borrowings		29,181			15,889
Proceeds from issuance of common stock, net of issuance expenses		869			4,241
Payments for retirement of common stock		(2	)		(6	)
Proceeds from issuance of long-term debt, net of issuance expenses		57			44
Payments for retirement of long-term debt		(773	)		(2,277	)
Dividends paid		(8,643	)		(8,342	)
Net cash provided by financing activities — continuing operations		33,531			17,681
Net cash used in financing activities — discontinued operations		—			(256	)
Net cash provided by financing activities		33,531			17,425
Effect of foreign exchange rate fluctuations on cash		47			61
Net change in cash and cash equivalents		(5,430	)		—
Cash and cash equivalents at beginning of period — continuing operations		5,430			—
Cash and cash equivalents at end of period — continuing operations	$	—		$	—
Supplemental cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)	$	2,144		$	2,238
Income taxes	$	5,226		$	4,527
Cash paid during the year from discontinued operations for:
Interest	$	—		$	28
Income taxes	$	(156	)	$	763

See accompanying notes to consolidated financial statements

- 5 -

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated results of operations for the periods presented. The consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes as of and for the years ended December 31, 2005, 2004 and 2003 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005. Because of seasonal and other factors, the earnings for the three months ended March 31, 2006 should not be taken as an indication of earnings for all or any part of the balance of the year.

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as the electric utility’s forward energy contracts and the energy services company’s swap transactions, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with Statement of Financing Accounting Standards (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 our operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Some of the operating companies enter into fixed-price construction contracts. Revenues under these contracts are primarily recognized on a percentage-of-completion basis. The method used to determine the percentage of completion is based on the ratio of labor costs incurred to total estimated labor costs at the Company’s wind tower manufacturer, square footage completed to total bid square footage for certain floating dock projects and costs incurred to total estimated costs on all other construction projects. The following summarizes costs incurred, billings and estimated earnings recognized on uncompleted contracts:

	March 31,			December 31,
(in thousands)	2006			2005
Costs incurred on uncompleted contracts	$	203,332		$	194,076
Less billings to date		(201,441	)		(203,862	)
Plus estimated earnings recognized		25,636			22,834
	$	27,527		$	13,048

6

The following amounts are included in the Company’s consolidated balance sheets. Billings in excess of costs and estimated earnings on uncompleted contracts are included in accounts payable:

	March 31,			December 31,
(in thousands)	2006			2005
Costs and estimated earnings in excess of billings on uncompleted contracts	$	35,618		$	21,542
Billings in excess of costs and estimated earnings on uncompleted contracts		(8,091	)		(8,494	)
	$	27,527		$	13,048

Adjustments and Reclassifications

The Company’s income statement and statement of cash flows for the three months ended March 31, 2005 reflect the reclassifications of the operating results, assets and liabilities of Chassis Liner Corporation (CLC) to discontinued operations as a result of a second quarter 2005 decision to sell CLC. The Company reached an agreement to sell CLC in the fourth quarter of 2005. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three months ended March 31, 2005.

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2006		2005
Finished goods	$	48,623	$	38,928
Work in process		7,521		7,146
Raw material, fuel and supplies		50,314		42,603
	$	106,458	$	88,677

Goodwill and Other Intangible Assets

Goodwill did not change in the first three months of 2006 as the Company did not acquire or dispose of any businesses or make any adjustments to goodwill during the period.

The following table summarizes the components of the Company’s intangible assets at March 31, 2006 and December 31, 2005.

	March 31, 2006						December 31, 2005
	Gross				Net		Gross				Net
	carrying		Accumulated		carrying		carrying		Accumulated		carrying
(in thousands)	amount		amortization		amount		amount		amortization		amount
Amortized intangible assets:
Covenants not to compete	$	2,198	$	1,549	$	649	$	2,338	$	1,620	$	718
Customer relationships		10,572		691		9,881		10,575		583		9,992
Other intangible assets including contracts		2,634		1,618		1,016		2,785		1,680		1,105
Total	$	15,404	$	3,858	$	11,546	$	15,698	$	3,883	$	11,815
Non-amortized intangible assets:
Brand/trade name	$	9,345	$	—	$	9,345	$	9,345	$	—	$	9,345

7

Intangible assets with finite lives are being amortized over average lives ranging from one to twenty-five years. The amortization expense for these intangible assets was $266,000 for the three months ended March 31, 2006 compared to $254,000 for the three months ended March 31, 2005. The estimated annual amortization expense for these intangible assets for the next five years is: $1,004,000 for 2006, $901,000 for 2007, $758,000 for 2008, $636,000 for 2009 and $507,000 for 2010.

Comprehensive Income

	Three months ended
	March 31,
(in thousands)	2006			2005
Net income	$	14,960		$	9,971
Other comprehensive income (net-of-tax)
Foreign currency translation (loss)		(55	)		(83	)
Unrealized (loss) on available-for-sale securities		(7	)		(22	)
Total other comprehensive income		(62	)		(105	)
Total comprehensive income	$	14,898		$	9,866

The foreign currency translation adjustments are associated with the Canadian operations of Idaho Pacific Holdings, Inc. (IPH). The unrealized losses on available-for-sale securities are associated with investments of the Company’s captive insurance company.

New Accounting Standards

SFAS No. 123(R) (revised 2004), Share-Based Payment, issued in December 2004 is a revision of SFAS No. 123, Accounting for Stock-based Compensation, and supersedes Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees. Beginning in January 2006, we adopted SFAS No. 123(R) on a modified prospective basis. The Company is required to record stock-based compensation as an expense on its income statement over the period earned based on the fair value of the stock or options awarded on their grant date. The application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $160,000, net-of-tax, in 2006 for non-vested stock options that were outstanding on December 31, 2005. Additionally, the application of SFAS No. 123(R) reporting requirements will result in recording compensation expense of approximately $240,000 in 2006 for the 15% discount offered under our Employee Stock Purchase Plan based on amounts currently being withheld for investment by participants. See additional discussion under Share-based Payments in the footnotes that follow. For years prior to 2006, we reported our stock-based compensation under the requirements of APB No. 25 and furnished related pro forma footnote information required under SFAS No. 123.

SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140, was issued in February 2006. This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to resolve issues addressed in SFAS No. 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. This statement also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to eliminate the prohibition on a qualifying special purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. This Statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company has not issued nor does it currently hold any financial instruments that would be affected by this statement and does not anticipate that this statement will have any impact on its consolidated financial statement on the date the statement becomes effective.

8

SFAS No. 156, Accounting for Servicing of Financial Assets, was issued in March 2006. This statement amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, with respect to the accounting for separately recognized servicing assets and servicing liabilities. This statement is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company does not currently have any servicing assets or servicing liabilities and does not anticipate that this statement will have any impact on its consolidated financial statements on the date the statement becomes effective.

Segment Information

The Company’s businesses have been classified into six segments based on products and services and reach customers in all 50 states and international markets. The six segments are: electric, plastics, manufacturing, health services, food ingredient processing and other business operations.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. Electric utility operations have been the Company’s primary business since incorporation.

Plastics consist of businesses producing polyvinyl chloride and polyethylene pipe in the Upper Midwest and Southwest regions of the United States.

Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, material and handling trays and horticultural containers; contract machining; and metal parts stamping and fabrication. These businesses are located primarily in the Upper Midwest and Missouri.

Health services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide service maintenance, diagnostic imaging, positron emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

Food ingredient processing consists of IPH, which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and Souris, Prince Edward Island, Canada, producing dehydrated potato products that are sold in the United States, Canada, Europe, the Middle East, the Pacific Rim and Central America.

Other business operations consists of businesses involved in residential, commercial and industrial electric contracting industries; fiber optic and electric distribution systems; waste-water, water and HVAC systems construction; transportation; energy services and natural gas marketing; and the portion of corporate general and administrative expenses that are not allocated to other segments. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and six Canadian provinces.

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

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information on continuing operations for the business segments for three month periods ended March 31, 2006 and 2005 and total assets by business segment as of March 31, 2006 and December 31, 2005 are presented in the following tables.

9

Operating Revenue

	Three months ended
	March 31,
(in thousands)	2006			2005
Electric	$	82,584		$	73,483
Plastics		38,105			32,155
Manufacturing		68,257			55,529
Health services		32,076			27,798
Food ingredient processing		9,350			9,255
Other business operations		49,250			34,897
Intersegment eliminations		(844	)		(984	)
Total	$	278,778		$	232,133

Income (Loss) Before Income Taxes

	Three months ended
	March 31,
(in thousands)	2006			2005
Electric	$	14,695		$	11,805
Plastics		7,656			4,407
Manufacturing		3,771			1,691
Health services		588			1,349
Food ingredient processing		(1,651	)		1,198
Other business operations		(1,527	)		(3,755	)
Total	$	23,532		$	16,695

Total Assets

	March 31,		December 31,
(in thousands)	2006		2005
Electric	$	648,993	$	654,175
Plastics		95,643		76,573
Manufacturing		208,035		177,969
Health services		66,046		67,066
Food ingredient processing		96,995		96,023
Other business operations		98,274		107,373
Discontinued operations		981		2,317
Total	$	1,214,967	$	1,181,496

No single external customer accounts for 10% or more of the Company’s revenues. Substantially all of the Company’s long-lived assets are within the United States except for a food ingredient processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower manufacturing plant in Fort Erie, Ontario, Canada.

10

The following table presents the percent of consolidated sales revenue by country:

	Three months ended
	March 31,
(in thousands)	2006			2005
United States of America		97.2	%		98.1	%
Canada		1.4	%		0.9	%
All other countries		1.4	%		1.0	%

Rate and Regulatory Matters

In December 2005 the Minnesota Public Utilities Commission (MPUC) issued an order denying the electric utility’s request to allow recovery of certain Midwest Independent Transmission System Operator (MISO)-related costs through the fuel clause adjustment (FCA) in Minnesota retail rates and requiring a refund of amounts previously collected pursuant to an interim order issued in April 2005. A $1.9 million reduction in revenue and a refund payable was recorded in December 2005 by the electric utility to reflect the refund obligation. On February 9, 2006 the MPUC decided to reconsider its December 2005 order. The Commission’s final order was issued on February 24, 2006. In the order the MPUC ordered jurisdictional investor-owned utilities in the state to participate with the Minnesota Department of Commerce and other parties in a proceeding that will evaluate suitability of recovery of certain MISO Day 2 energy market costs through the FCA. The Minnesota utilities and other parties are currently active in this effort and expect to provide a final report to the MPUC in June 2006. In addition, the order eliminated the refund provision from the December 2005 order, and allowed that any MISO-related costs not recovered through the FCA may be deferred for a period of 36 months, with possible recovery through base rates in the electric utility’s next general rate case which is expected to be filed on or before September 30, 2007. As a result of this order, the electric utility recognized $1.9 million in revenue and reversed the refund payable in February 2006 and expects to recover all MISO-related costs through the FCA, or to seek recovery, in a rate case, of any MISO-related costs not recoverable through the FCA.

In September 2004, a letter was provided to the MPUC summarizing issues and conclusions of an internal investigation completed by the Company related to claims of allegedly improper regulatory filings brought to the attention of the Company by certain individuals. On November 30, 2004 the electric utility filed a report with the MPUC responding to these claims. In 2005, the Energy Division of the Department of Commerce (DOC), the Residential Utilities Division of the Office of Attorney General and the claimants filed comments in response to the report, to which the Company filed reply comments. A hearing before the MPUC was held on February 28, 2006. As a result of the hearing the electric utility agreed that within the next 60 to 90 days it would file a revised Regulatory Compliance Plan, an updated Corporate Cost Allocation Manual and documentation of the definitions of its chart of accounts. The electric utility filed a revised Regulatory Compliance Plan in April 2006 and will file an updated Corporate Cost Allocation Manual and documentation of the definitions of its chart of accounts in May 2006. The electric utility also agreed to file a general rate case in Minnesota on or before September 30, 2007.

On April 25, 2006 the Federal Energy Regulatory Commission (FERC) issued an order requiring MISO to refund to customers, with interest, amounts related to real-time revenue sufficiency guarantee (RSG) charges that were not allocated to day-ahead virtual supply offers in accordance with MISO’s Transmission and Energy Markets Tariff (TEMT) going back to the commencement of MISO Day 2 markets in April 2005. The Company recorded $12.7 million in net revenues in 2005 and $1.0 million in net revenues in the first quarter of 2006 related to virtual transactions. As of the date of this report, the Company is not able to determine the financial impact of this order on its operations.

On December 29, 2000 the North Dakota Public Service Commission (NDPSC) approved a performance-based ratemaking plan that links allowed earnings in North Dakota to seven defined performance standards in the areas of price, electric service reliability, customer satisfaction and employee safety. The plan was in place through 2005. The electric utility’s 2005 rate of return was within the allowable range defined in

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the plan, so no refunds or recoveries were ordered under the plan for 2005. The performance-based ratemaking plan expired on December 31, 2005. While the electric utility has applied to the NDPSC for a three year extension with certain modifications, the NDPSC has taken no action on the application.

In a letter from the FERC Office of Market Oversight and Investigations (OMOI) dated September 27, 2005 the electric utility was informed that the Division of Operation Audits of the OMOI would be commencing an audit of the electric utility. The purpose of the audit is to determine whether and how the electric utility’s transmission practices are in compliance with the FERC’s applicable rules and regulations and tariff requirements and whether and how the implementation of the electric utility’s waivers from the requirements of Order No. 889 and Order No. 2004 restricts access to transmission information that would benefit the electric utility’s off-system sales. As of the date of this report the Division of Operation Audits of the OMOI had not completed its audit.

Regulatory Assets and Liabilities

As a regulated entity the Company and the electric utility account for the financial effects of regulation in accordance with SFAS No. 71, Accounting for the Effect of Certain Types of Regulation. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation.

The following table indicates the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheet:

	March 31,		December 31,
(in thousands)	2006		2005
Regulatory assets:
Deferred income taxes	$	16,869	$	16,724
Accrued cost-of-energy revenue		10,620		10,400
Reacquisition premiums		2,918		2,995
Deferred marked-to-market losses		999		1,423
Deferred conservation program costs		613		1,064
Accumulated ARO accretion/depreciation adjustment		234		209
Plant acquisition costs		185		196
Total regulatory assets	$	32,438	$	33,011
Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	52,852	$	52,582
Deferred income taxes		5,778		5,961
Deferred marked-to-market gains		1,219		2,925
Gain on sale of division office building		155		156
Total regulatory liabilities	$	60,004	$	61,624
Net regulatory liability position	$	27,566	$	28,613

The regulatory assets and liabilities related to deferred income taxes result from changes in statutory tax rates accounted for in accordance with SFAS No. 109, Accounting for Income Taxes. Reacquisition premiums included in Unamortized debt expense and reacquisition premiums are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 16.3 years. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. Plant acquisition costs will be amortized over the next 4.2 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

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sales of energy scheduled for delivery prior to September 2006. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. The remaining regulatory assets and liabilities are being recovered from, or will be paid to, electric customers over the next 30 years.

If for any reason, the Company’s regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of SFAS No. 71 ceases.

Share-based Payments

No new stock awards were granted in the first quarter of 2006. As of March 31, 2006, the total remaining unrecognized compensation expense related to stock-based compensation was approximately $2.5 million (before income taxes) which will be amortized over a weighted-average period of 1.5 years.

On January 1, 2006 the Company adopted the accounting provisions of SFAS No. 123(R) (revised 2004), Share-Based Payment, on a modified prospective basis. SFAS No. 123(R) is a revision of SFAS No. 123, Accounting for Stock-based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Under SFAS No. 123(R), the Company will record stock-based compensation as an expense on its income statement over the period earned based on the estimated fair value of the stock or options awarded on their grant date. The company elected the modified prospective method of adopting SFAS No. 123(R), under which prior periods are not retroactively revised. The valuation provisions of SFAS No. 123(R) apply to awards granted after the effective date. Estimated stock-based compensation expense for awards granted prior to the effective date but that remain nonvested on the effective date will be recognized over the remaining service period using the compensation cost estimated for the SFAS No. 123 pro forma disclosures. Additionally, the adoption of SFAS No. 123(R) resulted in the transfer of $798,000 in credits related to outstanding restricted share-based compensation for employees from equity on the Company’s consolidated balance sheet to a liability on January 1, 2006 because of income tax withholding provisions in the share-based award agreements. The adoption of SFAS 123(R) also resulted in the elimination of Unearned compensation (contra-equity account) from the equity section of the Company’s consolidated balance sheet on January 1, 2006 by netting the account balance of $1,720,000 against Premium on common shares.

The Company has five share-based payment programs. The effect of the adoption of SFAS No. 123(R) accounting on each of these programs is explained in the following paragraphs.

1999 Employee Stock Purchase Plan, as Amended (Purchase Plan)
The Purchase Plan allows employees through payroll withholding to purchase shares of the Company’s common stock at a 15% discount from the average market price on the last day of a six month investment period. Under APB No. 25, the Company was not required to record compensation expense related to the 15% discount. Under SFAS 123(R) the Company is required to record compensation expense related to the 15% discount. Based on the participants’ current level of withholdings, the Company estimates that the 15% discount will amount to approximately $240,000 in 2006. Accordingly, the Company recorded $60,000 in compensation expense for the three month period ended March 31, 2006 related to the Purchase Plan. The 15% discount is not taxable to the employee and is not a deductible expense for tax purposes for the Company. The shares to be purchased by employees participating in the Purchase Plan are not considered dilutive for the purpose of calculating diluted earnings per share during the investment period. At the discretion of the Company, shares purchased under the Purchase Plan can be either new issue shares or shares purchased in the open market. Currently, the Company intends to purchase shares for the Purchase Plan in the open market.

Stock Options granted under the 1999 Stock Incentive Plan, as Amended (Incentive Plan)
Since the inception of the Incentive Plan in 1999, the Company has granted 2,041,500 options for the purchase of the Company’s common stock. Of the options granted, 1,860,438 had vested or were forfeited and 181,062 were not vested as of March 31, 2006. The exercise price of

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the options granted has been the average market price of the Company’s common stock on the grant date. These options were not compensatory under APB No. 25 accounting rules. Under SFAS No.123(R) accounting, compensation expense will be recorded based on the estimated fair value of the options on their grant date using a fair-value option pricing model. Under SFAS No. 123(R) accounting, the fair value of the options granted will be recorded as compensation expense over the requisite service period (the vesting period of the options). The estimated fair value of all options granted under the Incentive Plan has been based on the Black-Scholes option pricing model.

Under the modified prospective application of SFAS No.123(R) accounting requirements, the difference between the intrinsic value of nonvested options and the fair value of those options of $362,000 ($217,000 net-of-tax) on January 1, 2006 is being recognized on a straight-line basis as compensation expense over the remaining vesting period of the nonvested options, which, for nonvested options outstanding on January 1, 2006, will be from January 1, 2006 through April 30, 2007. Accordingly, the Company recorded $68,000 ($41,000 net-of-tax) in compensation expense for the three month period ended March 31, 2006 related to nonvested options issued under the Incentive Plan.

Had compensation expense for stock options been determined based on estimated fair value at the award date, as prescribed by SFAS No. 123, the Company’s net income for three months ended March 31, 2005 would have decreased as presented in the table below.

	Three months ended
(in thousands)	March 31, 2005
Net income
As reported	$	9,971
Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effects		(106	)
Pro forma	$	9,865
Basic earnings per share
As reported	$	0.34
Pro forma	$	0.33
Diluted earnings per share
As reported	$	0.33
Pro forma	$	0.33

For the purpose of calculating diluted earnings per share, the underlying shares of all vested and nonvested in-the-money options (options where the reporting date market price of underlying shares exceeds the exercise price of the options) are considered dilutive.

Presented below is a summary of the stock options activity for the three months ended March 31, 2006:

					Aggregate
			Average		intrinsic
			exercise		value
	Options		price		(000’s)
Outstanding, January 1, 2006		1,237,164	$	25.58
Granted		—
Exercised		45,218	$	22.98	$	321
Forfeited		—
Outstanding, March 31, 2006		1,191,946	$	25.68	$	4,105
Exercisable, March 31, 2006		1,050,054	$	25.25	$	3,986

The aggregate intrinsic value in the preceding table represents the total intrinsic value (before income taxes), based on the average market price of the Company’s common stock on March 31, 2006, which would have been received by the option holders had all option holders exercised their options on that date.

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The following table summarizes information about options outstanding as of March 31, 2006:

Options outstanding							Options exercisable
			Weighted-
			average		Weighted-				Weighted-
	Outstanding		remaining		average		Exercisable		average
Range of	as of		contractual		exercise		as of		exercise
exercise prices	3/31/06		life (yrs)		price		3/31/06		price
$18.80-$21.94		286,497		3.7	$	19.48		286,497	$	19.48
$21.95-$25.07		62,850		9.3	$	24.93		62,850	$	24.93
$25.08-$28.21		604,975		6.1	$	26.54		517,475	$	26.41
$28.22-$31.34		237,624		6.1	$	31.21		183,232	$	31.17

The Company received cash of $1,039,000 for options exercised in the first quarter of 2006.

Restricted Stock granted to Directors
Under the Incentive Plan, restricted shares of the Company’s common stock have been granted to members of the Company’s Board of Directors as a form of compensation. Under APB No. 25 accounting rules, the Company had recognized compensation expense for these restricted stock grants, ratably, over the four-year vesting period of the restricted shares based on the market value of the Company’s common stock on the grant date. Under the modified prospective application of SFAS No.123(R) accounting requirements, compensation expense related to nonvested restricted shares outstanding will be recorded based on the estimated fair value of the restricted shares on their grant dates using the Black-Scholes fair-value option pricing model. The amount of compensation expense recorded related to nonvested restricted shares granted to directors under SFAS No. 123(R) for the three month period ended March 31, 2006 was $71,000 ($43,000 net-of-tax). The amount of compensation expense recorded related to nonvested restricted shares granted to directors based on the intrinsic value of the restricted stock grants under APB No. 25 for the three month period ended March 31, 2005 was $53,000 ($32,000 net-of-tax). Nonvested restricted shares granted to directors are considered dilutive for the purpose of calculating diluted earnings per share but are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share.

Presented below is a summary of the status of Directors’ restricted stock awards for the three months ended March 31, 2006:

			Weighted average
			grant-date
	Shares		fair value
Nonvested, January 1, 2006		27,900	$	22.37
Granted		—
Vested		—
Forfeited		—
Nonvested, March 31, 2006		27,900	$	22.37

Restricted Stock granted to Employees
Under the Incentive Plan, restricted shares of the Company’s common stock have been granted to employees as a form of compensation. Under APB No. 25 accounting rules, the Company had recognized compensation expense for these restricted stock grants, ratably, over the vesting periods of the restricted shares based on the market value of the Company’s common stock on the grant date. Because of income tax withholding provisions in the restricted stock award agreements related to restricted stock granted to employees, the value of these grants is considered variable, which, under SFAS No. 123(R), will require the offsetting credit to compensation expense to be recorded as a liability. Under the modified prospective application of SFAS No.123(R) accounting requirements and accounting rules for variable awards, compensation expense related to nonvested restricted shares granted to employees will be recorded based on the estimated fair value of the

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restricted shares on their grant dates and adjusted for the estimated fair value of any nonvested restricted shares on each subsequent reporting date. The reporting date fair value of nonvested restricted shares under this program will be based on the average market value of the Company’s common stock on the reporting date.

The amount of compensation expense recorded related to nonvested restricted shares granted to employees based on the estimated fair value of the restricted stock grants under SFAS No. 123(R) for the three month period ended March 31, 2006 was $291,000 ($175,000 net-of-tax). The amount of compensation expense recorded related to nonvested restricted shares granted to employees based on the intrinsic value of the restricted stock grants under APB No. 25 for the three month period ended March 31, 2005 was $271,000 ($163,000 net-of-tax). The equity account, Unearned Compensation, was credited when compensation expense was recorded related to these shares under APB No. 25 accounting. Under SFAS 123(R) accounting, a current liability account is credited when compensation expense is recorded. Accumulated liabilities related to nonvested restricted shares issued to employees under this program will be reversed and credited to the Premium on common shares equity account as the shares vest. Nonvested restricted shares granted to employees are considered dilutive for the purpose of calculating diluted earnings per share but are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share.

Presented below is a summary of the status of Employee’s restricted stock awards for the three months ended March 31, 2006:

			Weighted average
			reporting-date
	Shares		fair value
Nonvested, January 1, 2006		71.525	$	27.99
Granted		—
Vested (fair value: $29,000)		996	$	28.47
Forfeited		—
Nonvested, March 31, 2006		70,529	$	27.97

Stock Performance Awards granted to Executive Officers
The Compensation Committee of the Company’s Board of Directors has approved stock performance award agreements under the Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the awards are granted. The number of shares earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement period. Under APB No. 25 accounting, these awards were valued based on the average market price of the underlying shares of the Company’s common stock on the award grant date, multiplied by the estimated probable number of shares to be awarded at the end of the performance measurement period with compensation expenses recorded ratably over the related three-year measurement period. Compensation expense recognized was adjusted at each reporting date subsequent to the grant date of the awards for the difference between the market value of the underlying shares on their grant date and the market value of the underlying shares on the reporting date. Under the modified prospective application of SFAS No.123(R) accounting requirements, the amount of compensation expense that will be recorded subsequent to January 1, 2006 related to awards outstanding on March 31, 2006 will be based on the estimated fair value of the awards on their grant dates as determined under the Black-Scholes option pricing model, multiplied by the estimated number of shares ultimately expected to be awarded.

The amount of compensation expense related to the executive stock performance awards outstanding for the three month period ended March 31, 2006 was $141,000 ($85,000 net-of-tax). No compensation expense was recorded under APB No. 25 related to the executive stock

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performance awards outstanding during the three month period ended March 31, 2005 because the Company estimated that no shares were probable of issuance under the program at that time based on the Company’s total shareholder return relative to the total shareholder returns of the companies in its EEI peer group. For the purpose of calculating diluted earnings per share, shares expected to be awarded are considered dilutive. Currently, the Company intends to purchase shares on the open market for executive stock performance awards earned.

A summary of activity under the performance award agreements as of and for the three months ended December 31, 2006 and 2005 is as follows:

	Maximum				Amount of expense
	shares				during the three
Performance	subject		Shares		months ended
period	to award		expected to be awarded		March 31,
					2006		2005
2005-2007		75,150		50,872	$	94,000		—
2004-2006		70,500		23,500	$	47,000		—

Common Shares and Earnings per Share

In the first quarter of 2006 the Company issued 45,218 common shares for stock options exercised and 579 common shares for director’s compensation and retired 68 common shares for tax withholding purposes related to 996 restricted shares that vested in March 2006.

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 excluding any nonvested restricted shares outstanding during the period. Diluted earnings per common share are calculated by adjusting outstanding shares, assuming conversion of all potentially dilutive stock options and vesting of all nonvested restricted shares outstanding and including contingently issuable shares under the Company’s 2004 and 2005 performance award agreements with its executive officers. Stock options with exercise prices greater than the market price are excluded from the calculation of diluted earnings per common share.

Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company’s noncontributory funded pension plan are as follows:

	Three months ended
	March 31,
(in thousands)	2006			2005
Service cost—benefit earned during the period	$	1,210		$	1,034
Interest cost on projected benefit obligation		2,544			2,448
Expected return on assets		(3,065	)		(2,996	)
Amortization of prior-service cost		186			241
Amortization of net actuarial loss		378			—
Net periodic pension cost	$	1,253		$	727

The Company made a $2.0 million discretionary contribution to its pension plan in March 2006. An additional $2.0 million discretionary contribution was made in April 2006.

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Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three months ended
	March 31,
(in thousands)	2006		2005
Service cost—benefit earned during the period	$	106	$	92
Interest cost on projected benefit obligation		326		316
Amortization of prior-service cost		18		18
Recognized net actuarial loss		118		104
Net periodic pension cost	$	568	$	530

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired electric utility and corporate employees are as follows:

	Three months ended
	March 31,
(in thousands)	2006			2005
Service cost—benefit earned during the period	$	334		$	311
Interest cost on projected benefit obligation		637			666
Amortization of transition obligation		187			187
Amortization of prior-service cost		(76	)		(77	)
Amortization of net actuarial loss		133			156
Effect of Medicare Part D expected subsidy		(293	)		(201	)
Net periodic postretirement benefit cost	$	922		$	1,042

Discontinued Operations

In 2005, the Company completed the sales of Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC). Discontinued operations includes the operating results of MIS, SGS and CLC and an after-tax loss on the expected disposal of SGS of $1.6 million for the three months ended March 31, 2005. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets requires that MIS, SGS and CLC be classified and reported separately as discontinued operations.

The results of discontinued operations for the three months ended March 31, 2005 are summarized as follows:

	Three months ended
	March 31, 2005
(in thousands)	MIS		SGS			CLC			Total
Operating revenues	$	2,044	$	4,870		$	1,705		$	8,619
Impairment loss		—		(2,627	)		—			(2,627	)
Income/(loss) before income taxes		1,270		(3,011	)		(56	)		(1,797	)
Income tax expense/(benefit)		508		(1,204	)		(22	)		(718	)

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At March 31, 2006 and December 31, 2005 the major components of assets and liabilities of the discontinued operations were as follows:

	March 31, 2006						December 31, 2005
(in thousands)	SGS		CLC		Total		SGS		CLC		Total
Current assets	$	463	$	518	$	981	$	857	$	1,455	$	2,312
Investments and other assets		—		—		—		—		5		5
Assets of discontinued operations	$	463	$	518	$	981	$	857	$	1,460	$	2,317
Current liabilities	$	274	$	56	$	330	$	328	$	44	$	372
Liabilities of discontinued operations	$	274	$	56	$	330	$	328	$	44	$	372

The remaining assets and liabilities of SGS and CLC consist of accounts receivable, accounts payable and inventory at estimated fair market value that were not settled or disposed of as of March 31, 2006.

Subsequent Events

On April 9, 2006 the Compensation Committee of 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 Company’s executive officers could earn up to an aggregate of 88,050 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance period of January 1, 2006 through December 31, 2008. The aggregate target share award is 58,700 shares. Actual payment may range from zero to 150 percent of the target amount. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. Under SFAS 123(R) accounting, the Company will be required to estimate the number of shares ultimately expected to be issued under these agreements for the purpose of estimating the fair value of the awards on the date of grant and recording compensation expense over the performance period.

On April 9, 2006, the Compensation Committee of the Company’s Board of Directors granted 47,340 restricted stock units to key employees under the Incentive Plan payable in common shares upon vesting according to the following schedule:

	Number of
Vesting date	shares vesting
April 10, 2006		7,450
April 8, 2007		3,850
June 27, 2007		1,000
April 8, 2008		3,850
January 9, 2009		1,000
January 16, 2009		500
April 8, 2009		3,850
May 1, 2009		500
April 8, 2010		25,340

On April 9, 2006 the Compensation Committee of the Company’s Board of Directors granted 19,800 shares of restricted stock to the directors under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2007 through 2010.

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On April 10, 2006, the Company’s shareholders approved amendments to the Incentive Plan increasing the number of common shares available under the Incentive Plan from 2,600,000 common shares to 3,600,000 common shares, extending the term of the Incentive Plan from December 13, 2008 to December 13, 2013 and making certain other changes to the terms of the Incentive Plan.

On April 10, 2006, the Company’s shareholders approved an amendment to the Purchase Plan increasing the number of common shares available under the Purchase Plan from 400,000 common shares to 900,000 common shares.

On April 26, 2006 the Company renewed its line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Harris Nesbitt Financing, Inc., Keybank National Association, Union Bank of California, N.A., Bank of America, N.A., Bank Hapoalim B.M., and Bank of the West and increased the amount available under the line from $100 million to $150 million. The renewed agreement expires on April 26, 2009. The terms of the renewed line of credit are essentially the same as those in place prior to the renewal. However, outstanding letters of credit issued by the Company can reduce the amount available for borrowing under the line by up to $30 million and the Company can increase its commitments under the renewed line of credit up to $200 million. Borrowings under the line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. This line is an unsecured revolving credit facility available to support borrowings of the Company’s nonelectric operations. The Company anticipates that the electric utility’s cash requirements through April 2009 will be provided for by cash flows from electric utility operations or through other borrowing arrangements. The Company’s obligations under this line of credit are guaranteed by a 100%-owned subsidiary that owns substantially all of the Company’s nonelectric companies. As of March 31, 2006, $45.2 million of the $100 million line of credit in place at that date was in use and $14.4 million was restricted from use to cover outstanding letters of credit.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

Comparison of the Three Months Ended March 31, 2006 and 2005

Consolidated operating revenues were $278.8 million for the three months ended March 31, 2006 compared with $232.1 million for the three months ended March 31, 2005. Operating income was $27.6 million for the three months ended March 31, 2006 compared with $21.1 million for the three months ended March 31, 2005. The Company recorded diluted earnings per share from continuing operations of $0.50 for the three months ended March 31, 2006 compared to $0.37 for the three months ended March 31, 2005 and total diluted earnings per share from continuing and discontinued operations of $0.50 for the three months ended March 31, 2006 compared to $0.33 for the three months ended March 31, 2005.

Following is a more detailed analysis of our operating results by business segment for the quarters ended March 31, 2006 and 2005, followed by our outlook for the remainder of 2006 and a discussion of changes in our financial position during the quarter ended March 31, 2006.

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Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended March 31, 2006 and 2005 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

	March 31,		March 31,
(in thousands)	2006		2005
Operating revenues	$	844	$	984
Cost of goods sold		319		511
Other nonelectric expenses		525		473

Electric

	Three months ended
	March 31,								%
(in thousands)	2006			2005		Change			Change
Retail sales revenues	$	73,359		$	63,315	$	10,044			15.9
Wholesale revenues		5,658			4,917		741			15.1
Net marked-to-market (loss) gain		(909	)		104		(1,013	)		—
Other revenues		4,476			5,147		(671	)		(13.0	)
Total operating revenues	$	82,584		$	73,483	$	9,101			12.4
Production fuel		14,806			15,177		(371	)		(2.4	)
Purchased power — system use		18,736			11,538		7,198			62.4
Other operation and maintenance expenses		23,407			23,918		(511	)		(2.1	)
Depreciation and amortization		6,357			6,100		257			4.2
Property taxes		2,618			2,673		(55	)		(2.1	)
Operating income	$	16,660		$	14,077	$	2,583			18.3

The increase in retail electric revenue is due mainly to a $9.5 million increase in fuel clause adjustment (FCA) revenues related to increases in fuel and purchased power costs for system use, but also includes $1.9 million related to the reversal of the refund provision established in December 2005 relating to Midwest Independent Transmission System Operator (MISO) costs. In December 2005, the Minnesota Public Utilities Commission (MPUC) issued an order denying recovery of certain MISO related costs through the FCA in Minnesota retail rates and requiring a refund of amounts previously collected. In February 2006 the MPUC reconsidered its order and eliminated the refund requirement. The remaining $0.5 million increase in retail revenues resulted from a 1.4% increase in retail megawatt-hours (mwh) sold between the periods reflecting increased sales to industrial customers partially offset by decreased sales to residential and commercial customers. Industrial mwh sales increased 25.2% between the quarters mainly due to increased consumption by pipeline customers as higher oil prices have led to an increase in volume of product being transported from Canada and the Williston basin. A 9.2% decrease in heating degree-days was the main factor contributing to 3.2% decrease in residential mwh sales and a 0.5% decrease in commercial mwh sales between the periods.

Wholesale sales revenue from company-owned generation increased $1.2 million in the three months ended March 31, 2006 compared to the three months ended March 31, 2005 as a result of a 15.3% increase in mwhs sold combined with an 11.3% increase in the price per mwh sold between the periods. Advance purchases of electricity in anticipation of normal winter weather resulted in increased wholesale electric sales in January of 2006 due to unseasonably mild weather. Wholesale sales from company-owned generation were curtailed in February and March 2006 as generation levels were restricted due to coal supply constraints. Net revenue from the resale of purchased power combined with net mark-to-market losses on forward energy contracts were ($0.6) million for the quarter ended March 31, 2006 compared with a combined

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$0.8 million in net revenue on purchased power resold and net mark-to-market gains on forward energy contracts for the quarter ended March 31, 2005. Of the $2.9 million in net mark-to-market gains recognized on open forward energy contracts at December 31, 2005, $1.9 million was realized and $0.5 million was reversed in the first quarter of 2006 as market prices on forward electric contracts declined in response to decreased demand for electricity due, in part, to regional winter weather that was milder than expected.

The decrease in other electric operating revenues for the three months ended March 31, 2006 compared to the three months ended March 31, 2005 is mainly due to a reduction in transmission services revenue related to the initiation of the MISO Day 2 market in April 2005. Certain revenues that were billed separately prior to inception of the MISO Day 2 market are now included in revenue from wholesale energy sales or reflected as a reduction in purchased power costs.

The decrease in fuel costs for the three months ended March 31, 2006 compared with the three months ended March 31, 2005 reflects a 6.8% reduction in mwhs generated partially offset by a 4.7% increase in the cost of fuel per mwh generated. Generation used for wholesale electric sales increased 15.3% while generation for retail sales decreased 9.8% between the periods. Fuel costs per mwh increased at all three of our coal-fired generating plants as a result of increases in coal and coal transportation costs between the periods. Much of the increase in coal and coal transportation costs is directly related to higher diesel fuel prices. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

The increase in purchased power — system use (to serve retail customers) is due to a 57.8% increase in mwhs purchased combined with a 2.9% increase in the cost per mwh purchased. An increase in mwh purchases for system use was necessary to make up for reductions in generation levels caused by delayed coal shipments to Big Stone and Hoot Lake Plants in February and March of 2006. The increase in purchased power costs reflects a general increase in fuel and purchased power costs across the Mid-Continent Area Power Pool (MAPP) region related to increased coal mining and transportation costs mainly as a result of higher fuel prices between the periods.

The decrease in other operation and maintenance expenses for the three months ended March 31, 2006 compared with the three months ended March 31, 2005 is mainly due to an increase in capitalized labor and other expenses related to more construction and storm repair work completed in the first quarter of 2006 than in the first quarter of 2005. Required storm repairs and mild weather resulted in the completion of more construction work than normal in the first quarter of 2006. Much of the storm repairs required replacement of damaged poles and power lines resulting in capitalization of removal and replacement costs.

Depreciation expense increased in the three months ended March 31, 2006 compared with the three months ended March 31, 2005 as a result of a $20.6 million increase in electric plant in service in 2005. The decrease in property taxes between the periods is a result of slightly lower utility property valuations in Minnesota in 2005.

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Plastics

	Three months ended
	March 31,							%
(in thousands)	2006		2005		Change			Change
Operating revenues	$	38,105	$	32,155	$	5,950			18.5
Cost of goods sold		28,180		25,417		2,763			10.9
Operating expenses		1,448		1,509		(61	)		(4.0	)
Depreciation and amortization		730		591		139			23.5
Operating income	$	7,747	$	4,638	$	3,109			67.0

Operating revenues for the plastics segment increased between the periods mainly as result of a 32.9% increase in the price per pound of polyvinyl chloride (PVC) pipe sold offset by a 15.3% decrease in pounds of PVC pipe sold. The increase in revenue reflects the effect of an increase in PVC resin prices between the periods. The increase in cost of goods sold was directly related to the increase in resin prices. The resin cost per pound of PVC pipe shipped increased 25.1% between the quarters. The increase in depreciation and amortization expense is the result of $3.6 million in capital expenditures in 2005, mainly for production equipment.

Manufacturing

	Three months ended
	March 31,						%
(in thousands)	2006		2005		Change		Change
Operating revenues	$	68,257	$	55,529	$	12,728		22.9
Cost of goods sold		54,399		45,359		9,040		19.9
Operating expenses		6,215		5,422		793		14.6
Depreciation and amortization		2,569		2,205		364		16.5
Operating income	$	5,074	$	2,543	$	2,531		99.5

The increase in revenues in our manufacturing segment relates to the following:

• Revenues at DMI Industries, Inc. (DMI) increased $10.4 million due to an increase in production and sales activity due in part to plant additions and continued improvements in productivity and capacity utilization.

• Revenues at ShoreMaster increased $1.5 million between the quarters mainly due to the acquisition of Southeast Floating Docks in May 2005.

• Revenues at BTD Manufacturing, Inc. (BTD) increased $0.5 million mainly as a result of higher prices received for goods manufactured. The number of units sold at BTD decreased 8.7% between the quarters while the revenue per unit sold increased 18.0%. Increased revenues from tooling activities enhanced by the acquisition of Performance Tool & Die in January of 2005, contributed as well to BTD’s revenue increase.

• Revenues at T.O. Plastics, Inc. increased $0.4 million between the quarters as a result of a 7.5% increase in unit sales.

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The increase in cost of goods sold in our manufacturing segment relates to the following:

• DMI’s cost of goods sold increased $8.0 million between the quarters, including $6.4 million in material costs increases. The increase in cost of goods sold is directly related to DMI’s increase in production and sales activity.

• Cost of goods sold at ShoreMaster increased $0.8 million between the quarters as a result of increase in labor and benefit costs, mainly related to the acquisition of Southeast Floating Docks in May 2005.

• Cost of goods sold at BTD decreased $0.6 million between the quarters mainly due to decreases in production labor costs related to a decrease in production employees and a decrease in overtime pay between the quarters. Productivity gains at BTD were achieved through efforts to better utilize and allocate available labor resources.

• Cost of goods sold at T.O. Plastics increased $0.7 million, reflecting $0.5 million in material cost increases and $0.2 million in increased labor and benefit costs between the quarters.

Operating expenses at DMI increased $0.6 million as a result of increases in labor, professional services and maintenance expenses. ShoreMaster’s operating expenses increased $0.2 million as a result of increases in wage and benefit expenses mainly related to the May 2005 acquisition on Southeast Floating Docks. Depreciation expense increased between the quarters as a result of the Southeast Floating Docks acquisition and 2005 capital additions at all four manufacturing companies.

Health Services

	Three months ended
	March 31,							%
(in thousands)	2006		2005		Change			Change
Operating revenues	$	32,076	$	27,798	$	4,278			15.4
Cost of goods sold		24,822		20,292		4,530			22.3
Operating expenses		5,514		4,913		601			12.2
Depreciation and amortization		957		1,067		(110	)		(10.3	)
Operating income	$	783	$	1,526	$	(743	)		(48.7	)

The increase in health services operating revenues for the three months ended March 31, 2006 compared with the three months ended March 31, 2005 reflects a $3.7 million increase in imaging revenues combined with a $0.6 million increase in revenues from sales and servicing of diagnostic imaging equipment. On the imaging side of the business, $2.2 million of the $3.7 million increase in revenue came from imaging services where the revenue per scan increased 18.4% between the quarters while the number of scans completed decreased 1.4%. Revenues from rentals and interim installations of scanning equipment along with providing technical support services for those rental and interim installations increased $1.4 million between the quarters. The increase in health services revenue was mostly offset by the increase in health services cost of goods sold, reflecting increased equipment rental and labor costs related to an increase in imaging and interim services activity and maintenance and sublease costs related to units that were out of service in the first quarter of 2006. The increase in revenue from sales and servicing of equipment was more than offset by increases in costs and operating expenses in these operations, resulting in a $0.8 million decrease in operating income from sales of supplies and sales and servicing of diagnostic medical equipment. The increase in operating expenses is mainly due to higher labor, benefits, travel and insurance expenses. The decrease in depreciation and amortization expense is the result of certain assets reaching the ends of their depreciable lives. When these assets are replaced, they are generally replaced with assets leased under operating leases.

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Food Ingredient Processing

	Three months ended
	March 31,								%
(in thousands)	2006			2005		Change			Change
Operating revenues	$	9,350		$	9,255	$	95			1.0
Cost of goods sold		9,318			6,685		2,633			39.4
Operating expenses		685			543		142			26.2
Depreciation and amortization		919			825		94			11.4
Operating (loss) income	$	(1,572	)	$	1,202	$	(2,774	)		(230.8	)

The increase in food ingredient processing revenues reflects a 14.8% increase in revenue per pound of product sold offset by a 12.0% decrease in pounds sold between the periods. The food ingredient processing segment has been negatively impacted by raw product supply shortage in Idaho and Prince Edward Island. This shortage has caused production to be curtailed at these two plants contributing to the 12.0% decrease in pounds of product sold. Higher than expected raw product costs related to the supply shortage have resulted in a 58.4% increase in the cost per pound of product sold. The increase in operating expenses between the quarters is due to an increase in compensation expenses.

Other Business Operations

	Three months ended
	March 31,								%
(in thousands)	2006			2005			Change		Change
Operating revenues	$	49,250		$	34,897		$	14,353		41.1
Cost of goods sold		36,674			26,392			10,282		39.0
Operating expenses		12,979			10,827			2,152		19.9
Depreciation and amortization		692			597			95		15.9
Operating loss	$	(1,095	)	$	(2,919	)	$	1,824		(62.5	)

The increase in revenues in the other business operations segment relates to the following:

• Revenues at Foley Company increased $7.3 million in the first quarter of 2006 compared to the first quarter of 2005 due to an increase in the volume and dollar value of jobs in progress.

• Revenues at Otter Tail Energy Services Co. (OTESCO) increased $4.9 million between the quarters mainly as a result of increases in natural gas prices.

• Revenues at Midwest Construction Services, Inc. (MCS) increased $1.3 million between the quarters as a result of an increase in work in progress.

• Revenues at E.W. Wylie Corporation (Wylie) increased $0.8 million between the quarters mainly due to a 2.8% net increase in miles driven by owner-operated and company-operated trucks. Miles driven by owner-operated trucks increased 48.8% while miles driven by company-operated trucks decreased 12.8% between the quarters. Wylie’s increased revenues also reflect increased fuel costs recovered through fuel surcharges between the quarters.

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The increase in cost of goods sold in the other business operations segment relates to the following:

• Foley Company’s cost of goods sold increased $6.3 million mainly in the areas of materials and subcontractor costs as a result of increased construction activity and jobs in progress.

• Cost of goods sold at OTESCO increased by a $4.7 million as a result of increases in natural gas costs.

• Cost of goods sold at MCS decreased $0.7 million mainly due to a reduction in subcontractor costs between the quarters.

The increase in operating expenses in the other business operations segment is due to the following:

• Wylie’s revenue increase was more than offset by a $0.9 million increase in operating expenses, mainly contractor costs related to the increase in miles driven by owner-operated trucks between the periods.

• MCS operating expenses increased $0.3 million between the quarters, mainly as a result of increases in salary and benefit expenses.

• Operating expenses in this segment also increased $1.1 million due to increases in health and other insurance costs and other employee benefit costs not allocated to the other operating segments.

Income Taxes — Continuing Operations

The $2.9 million (51.9%) increase in income taxes — continuing operations between the quarters is primarily the result of a $6.8 million (40.9%) increase in income from continuing operations before income taxes for the three months ended March 31, 2006 compared with the three months ended March 31, 2005. The effective tax rate for continuing operations for the three months ended March 31, 2006 was 36.4% compared to 33.8% for the three months ended March 31, 2005. The increase in the effective tax rate is related to a change in estimate in the reversal of regulatory deferred tax liabilities at the electric utility and an increase in taxable income relative to a fixed level of tax credits between the quarters.

Discontinued Operations

In 2005, the Company completed the sales of Midwest Information Systems, Inc. (MIS), St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC). Discontinued operations includes the operating results of MIS, SGS and CLC and an after-tax loss on the expected disposal of SGS of $1.6 million for the three months ended March 31, 2005. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets requires that MIS, SGS and CLC be classified and reported separately as discontinued operations.

The results of discontinued operations for the three months ended March 31, 2005 are summarized as follows:

	Three months ended
	March 31, 2005
(in thousands)	MIS		SGS			CLC			Total
Income (loss) before income taxes	$	1,270	$	(384	)	$	(56	)	$	830
Loss on expected disposal		—		(2,627	)		—			(2,627	)
Income tax expense (benefit)		508		(1,204	)		(22	)		(718	)
Net income (loss)	$	762	$	(1,807	)	$	(34	)	$	(1,079	)

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2006 OUTLOOK

The statements in this section are based on our current outlook for 2006 and are subject to risks and uncertainties described under “Forward Looking Information — Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995.”

We are revising our 2006 earnings guidance to be in the range of $1.50 to $1.70 of diluted earnings per share from continuing operations from $1.60 to $1.80. The key factor contributing to the earnings guidance revision for 2006 is curtailed generation related to reduced coal shipments to Big Stone and Hoot Lake Plants as a result of rail transportation issues. The reduced coal shipments have caused reduced generation levels at these plants. This in turn has reduced the amount of excess generation available to sell into the wholesale energy markets. Other items contributing to the revision in earnings guidance for 2006 are as follows:

• Due to the coal supply issue mentioned above, decreasing margins on wholesale energy sales involving the purchase and sale of electric energy contracts and increasing transmission and wage and benefit costs, we expect performance in the electric segment in 2006 to be in the lower end of the range of historical earnings levels.

• We expect plastics segment earnings for 2006 to be higher than originally anticipated due to the strong first quarter performance.

• Our forecasted 2006 net income from the manufacturing segment is in line with initial 2006 expectations. The improving economy, continued enhancements in productivity and capacity utilization, expanded markets, and expansion of production capacity with the opening of a new wind tower production facility in Fort Erie, Ontario, Canada are expected to result in increased net income in our manufacturing segment in 2006.

• The health services segment is expected to have lower earnings than original 2006 guidance due to the lower than expected first quarter results.

• We expect break-even earnings performance from our food ingredient processing business (IPH) in 2006. This is a reduction from the previously announced range of $2 million to $4 million in net earnings. This change in guidance is due to the factors mentioned in the Results of Operations section of this report which are expected to continue through most of 2006.

• Our other business operations segment is expected to show improved results over 2005, consistent with our expectations at the beginning of 2006, due to an improving economy and an increase in its backlog of construction contracts. An increase in wind energy projects activity is expected to have a positive impact on our electrical contracting business.

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

FINANCIAL POSITION

For the period 2006 through 2010, we estimate funds internally generated net of forecasted dividend payments will be sufficient to meet scheduled debt retirements (excluding the scheduled retirement of the $50 million 6.375% senior debentures due December 1, 2007), to repay currently outstanding short-term debt and to provide for our estimated consolidated capital expenditures (excluding expenditures related to the

27

proposed generating unit at the Big Stone Plant site). Reduced demand for electricity, reductions in wholesale sales of electricity or margins on wholesale sales, or declines in the number of products manufactured and sold by our companies could have an effect on funds internally generated. Additional equity or debt financing will be required in the period 2006 through 2010 in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to retire the $50 million 6.375% senior debentures due December 1, 2007, to complete acquisitions, to fund the construction of the proposed generating unit at the Big Stone Plant site or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.

During the first quarter of 2006 the Company issued 45,218 common shares for stock options exercised and 579 common shares for director’s compensation and retired 68 common shares for tax withholding purposes related to 996 restricted shares that vested in March 2006.

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. On April 26, 2006 we renewed our line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Harris Nesbitt Financing, Inc., Keybank National Association, Union Bank of California, N.A., Bank of America, N.A., Bank Hapoalim B.M., and Bank of the West and increased the amount available under the line from $100 million to $150 million. The renewed agreement expires on April 26, 2009. The terms of the renewed line of credit are essentially the same as those in place prior to the renewal. However, outstanding letters of credit issued by the Company can reduce the amount available for borrowing under the line by up to $30 million and we can increase our commitments under the renewed line of credit up to $200 million. Borrowings under the line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of our senior unsecured debt. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements through April 2009 will be provided for by cash flows from electric utility operations or through other borrowing arrangements. Our obligations under this line of credit are guaranteed by a 100%-owned subsidiary that owns substantially all of our nonelectric companies. As of March 31, 2006, $45.2 million of the $100 million line of credit in place at that date was in use and $14.4 million was restricted from use to cover outstanding letters of credit.

Our line of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under our financing agreements as of March 31, 2006.

Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. Our Grant County and Mercer County pollution control refunding revenue bonds and our 5.625% insured senior notes require that we grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds and notes, a security interest in the assets of the electric utility if the rating on our senior unsecured debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).

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Our current securities ratings are:

	Moody's
	Investors	Standard
	Service	& Poor's
Senior unsecured debt	A3	BBB+
Preferred stock	Baa2	BBB-
Outlook	Stable	Stable

Our 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.

Cash used in operating activities for continuing operations was $23.6 million for the three months ended March 31, 2006 compared with cash provided by operating activities from continuing operations of $1.4 million for the three months ended March 31, 2005. The $25.0 million increase in cash used for operating activities by continuing operations reflects an increase in cash used for working capital items of $27.5 million between the periods and a $2.0 million discretionary contribution to the company’s pension plan in March 2006, offset by a $5.0 million increase in net income between the quarters. Cash used for working capital items during the three months ended March 31, 2006 was $50.1 million compared with $22.6 million used for working capital items during the three months ended March 31, 2005.

Major uses of funds for working capital items in the first quarter of 2006 was a decrease in payables and other current liabilities of $22.2 million, an increase in other current assets of $19.1 million and an increase in inventories of $17.8 million. Accrued bonuses, wages and commissions decreased by a combined $5.8 million as incentives earned in 2005 were paid out in the first quarter of 2006. Trade accounts payable related to operating activities decreased $5.4 million at the electric utility mainly as a result of reductions in energy purchases in March 2006 compared with December 2005. A $5.3 million decrease in DMI’s accounts payable and other current liabilities related to operating activities reflects first quarter payment for a large shipment of raw steel plates received in December 2005. Accounts payable and other current liabilities related to operating activities decreased by $2.8 million in the plastics segment in the first quarter of 2006 as the PVC pipe companies paid for large shipments of resin received in December 2005 at favorable prices and payment terms. ShoreMaster reduced its accounts payable and other current liabilities related to operating activities by $2.6 million in the first quarter of 2006 as a result of paying for a build-up of raw materials purchased in December 2006 and recognizing deferred revenue on Southeast Floating Docks projects accounted for on a completed contract basis.

The increase in other current assets includes an increase of $15.1 million in costs in excess of billings at DMI mainly related to wind tower production to fill a large order that extends into 2007. While a number of units in this order have been completed, the terms of the contract specify that the customer, who has a strong senior unsecured debt rating, will not be billed until the units are shipped. The increase in other current assets also includes increases in prepaid insurance across all companies totaling $4.5 million related to annual premium payments. Inventories at our PVC pipe companies increased $8.5 million in anticipation of the upcoming construction season and as a result of increases in raw material costs. Our construction company inventories increased $2.3 million mostly related to a build up of electronic surveillance and security products at MCS. Our manufacturing companies’ inventories increased $5.5 million in the first quarter of 2006 as a result of increases in raw material costs and in response to increased demand for wind towers and waterfront equipment products. Our food ingredient processing companies’ inventories increased $1.6 million mainly as a result of increases in raw material costs (prices paid for process-grade potatoes).

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Net cash used in investing activities of continuing operations was $16.7 million for the three months ended March 31, 2006 compared to $18.6 million for the three months ended March 31, 2005. Cash used for capital expenditures increased by $2.7 million between the periods. Cash used for capital expenditures at the electric utility increased by $3.8 million mainly related to replacement of assets damaged in the November 2005 ice storm. Cash used for capital expenditures in the plastics segment increased by $0.7 million between the quarters mainly related to the installation of additional equipment at the production plant in Phoenix, Arizona. Cash used for capital expenditures in the manufacturing business decreased by $1.7 million between the quarters. Cash used for acquisitions decreased by $6.7 million between the quarters. We invested $6.4 million in cash, net of cash acquired, in the acquisitions of Performance Tool & Die and Shoreline in the first quarter of 2005. We made no acquisition expenditures in the first quarter of 2006.

Net cash provided by financing activities from continuing operations increased $15.8 million in the three months ended March 31, 2006 compared with the three months ended March 31, 2005 mainly due to an $18.0 million increase in short-term borrowings and checks issued in excess of cash between the quarters. A decrease in proceeds from the issuance of common stock of $3.4 million between the quarters reflects the issuance of common stock related to the partial exercise of the underwriters’ over-allotment option in January 2005. Payments for the retirement of long-term debt decreased by $1.5 million between the periods. An increase of 0.75 cents in the dividend paid per common share in the first quarter of 2006 compared with the first quarter of 2005 combined with the issuance of approximately 300,000 additional common shares between first quarter 2005 and first quarter 2006 ex-dividend dates contributed to the $0.3 million increase in dividends paid between the quarters.

There have been no material changes in our contractual obligations from those reported under the caption “Capital Requirements” on page 24 of our 2005 Annual Report to Shareholders. We do not have any material off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, valuation of forward energy contracts, unbilled electric revenues, unscheduled power exchanges, MISO electric market residual load adjustments, service contract maintenance costs, percentage-of-completion, valuation of stock-based payments 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.

Goodwill Impairment

We currently have $24.2 million of goodwill recorded on our balance sheet related to the acquisition of IPH in 2004. If current conditions of low sales volumes and prices, increasing raw material costs, high energy costs and the increasing value of the Canadian dollar relative to the U.S. dollar persist and operating margins do not improve according to our projections, the reductions in anticipated cash flows from this business may indicate that its fair value is less than its book value resulting in an impairment of goodwill and a corresponding charge against earnings.

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We evaluate goodwill for impairment on an annual basis and as conditions warrant. As of December 31, 2005 an assessment of the carrying values of our goodwill indicated no impairment.

A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 30 through 32 of our 2005 Annual Report to Shareholders. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2006.

Forward Looking Information — Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as “may”, “will”, “expect”, “anticipate”, “continue”, “estimate”, “project”, “believes” or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act.

The following factors, among others, could cause actual results for the Company to differ materially from those discussed in the forward-looking statements:

• We are subject to government regulations and actions that may have a negative impact on its business and results of operations.

• Certain MISO-related costs currently included in the FCA in Minnesota retail rates may be excluded from recovery through the FCA and subject to future recovery through rates established in a general rate case.

• Weather conditions can adversely affect our operations and revenues.

• Electric wholesale margins could be reduced as the MISO market becomes more efficient.

• Electric wholesale trading margins could be reduced or eliminated by losses due to trading activities.

• Wholesale sales of electricity from excess generation may decrease as a result of reduced coal shipments to Big Stone and Hoot Lake Plants due to rail transportation bottlenecks.

• The Federal Energy Regulatory Commission issued an order on April 25, 2006 that requires MISO to make refunds related to real time revenue sufficiency guarantee charges that were not allocated to day-ahead virtual supply offers in accordance with MISO’s Transmission and Energy Markets Tariff going back to the commencement of the MISO Day 2 market in April 2005. We are not yet able to assess what financial impact, if any, this order will have on our operations.

• Our manufacturer of wind towers operates in a market that has been dependent on the Production Tax Credit. This tax credit is currently in place through December 31, 2007. Should this tax credit not be renewed, the revenues and earnings of this business could be reduced.

• Federal and state environmental regulation could cause us to incur substantial capital expenditures which could result in increased operating costs.

31

• Our plans to grow and diversify through acquisitions may not be successful and could result in poor financial performance.

• Competition is a factor in all of our businesses.

• Economic uncertainty could have a negative impact on our future revenues and earnings.

• Volatile financial markets could restrict our ability to access capital and could increase borrowing costs and pension plan expenses.

• Our food ingredient processing segment operates in a highly competitive market and is dependent on adequate sources of raw materials for processing. Should the supply of these raw materials be affected by poor growing conditions, this could negatively impact the results of operations for this segment. This segment could also be impacted by foreign currency changes between Canadian and United States currency and prices of natural gas.

• Our plastics segment is highly dependent on a limited number of vendors for PVC resin. In the first quarter of 2006, 100% of resin purchased was from two vendors, 54% from one and 46% from the other. The loss of a key vendor or an interruption or delay in the supply of PVC resin could result in reduced sales or increased costs for this business. Reductions in PVC resin prices could negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory.

• Our health services businesses may not be able to retain or comply with the dealership arrangement and other agreements with Philips Medical.

For a further discussion of other risk factors and cautionary statements, refer to “Risk Factors and Cautionary Statements” and “Critical Accounting Policies Involving Significant Estimates” on pages 26 through 32 of our 2005 Annual Report to Shareholders. These factors are in addition to any other cautionary statements, written or oral, which may be made or referred to in connection with any such forward-looking statement or contained in any subsequent filings by the Company with the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

At March 31, 2006 we had limited exposure to market risk associated with interest rates and commodity prices and limited exposure to market risk associated with changes in foreign currency exchange rates. Outstanding trade accounts receivable of the Canadian operations of IPH are not at risk of valuation change due to changes in foreign currency exchange rates because the Canadian company transacts all sales in U.S. dollars. However, IPH does have market risk related to changes in foreign currency exchange rates because approximately 33% of IPH sales are outside the United States and the Canadian operations of IPH pays its operating expenses in Canadian dollars.

The majority of our consolidated long-term debt has fixed interest rates. The interest rate on variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of March 31, 2006 we had $21.5 million of long-term debt subject to variable interest rates. In April 2006, we negotiated a fixed rate of 6.76% on our Lombard US Equipment Finance note (the Lombard note) over the remaining term of the note that has a final payment due on October 2, 2010. The balance outstanding on the Lombard note on March 31, 2006 was $11.1 million. 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 March 31, 2006, annualized interest expense and pretax earnings would change by approximately $104,000.

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We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower. Gross margins also decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

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

Our energy services subsidiary has entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although our energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on our consolidated statement of income for the three months ended March 31, 2006 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 March 31, 2006 and the change in our consolidated balance sheet position from December 31, 2005 to March 31, 2006:

(in thousands)	March 31, 2006
Current asset — marked-to-market gain	$	594
Current liability — marked-to-market loss		(532	)
Net fair value of marked-to-market gas contracts	$	62

	Year-to-date
(in thousands)	March 31, 2006
Fair value at beginning of year	$	(26	)
Amount realized on contracts entered into in 2005 and settled in 2006		(26	)
Changes in fair value of contracts entered into in 2005		—
Net fair value of contracts entered into in 2005 at end of period		—
Changes in fair value of contracts entered into in 2006		62
Net fair value end of period	$	62

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The $62,000 recognized but unrealized net gain on these forward natural gas swap transactions marked to market on March 31, 2006 is expected to be realized on settlement as scheduled over the following quarters in the amounts listed:

	2nd Quarter		3rd Quarter		4th Quarter
(in thousands)	2006		2006		2006			Total
Net gain	$	85	$	40		($63	)	$	62

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 March 31, 2006 the electric utility had recognized, on a pretax basis, $427,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties by the electric utility’s power services’ personnel responsible for contract pricing and are benchmarked to regional hub prices as published in Megawatt Daily and as observed in the Intercontinental Exchange trading system. Of the forward energy contracts that are marked-to-market as of March 31, 2006, 86% of the forward purchases of electricity had offsetting sales in terms of volumes and delivery periods. The amount of net unrealized marked-to-market losses recognized on forward purchases of electricity not offset by forward sales of electricity as of March 31, 2006 was $35,000.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. With the advent of the MISO Day 2 market in April 2005, several changes were made to the energy risk management policy to recognize new trading opportunities created by this new market. Most of the changes were in new volumetric limits and loss limits to adequately manage the risks associated with these new opportunities. In addition, a Value at Risk (VaR) limit was also implemented to further manage market price risk. Exposure to price risk on any open positions as of March 31, 2006 was not material.

The following tables show the effect of marking-to-market forward contracts for the purchase and sale of electricity on our consolidated balance sheet as of March 31, 2006 and the change in our consolidated balance sheet position from December 31, 2005 to March 31, 2006:

(in thousands)	March 31, 2006
Current asset — marked-to-market gain	$	3,584
Regulatory asset — deferred marked-to-market loss		999
Total assets		4,583
Current liability — marked-to-market loss		(2,937	)
Regulatory liability — deferred marked-to-market gain		(1,219	)
Total liabilities		(4,156	)
Net fair value of marked-to-market energy contracts	$	427

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	Year-to-date
(in thousands)	March 31, 2006
Fair value at beginning of year	$	2,916
Amount realized on contracts entered into in 2005 and settled in 2006		(1,864	)
Changes in fair value of contracts entered into in 2005		(556	)
Net fair value of contracts entered into in 2005 at end of period		496
Changes in fair value of contracts entered into in 2006		(69	)
Net fair value end of period	$	427

The $427,000 recognized but unrealized net gain on the forward energy purchases and sales marked to market on March 31, 2006 is expected to be realized on physical settlement as scheduled over the following quarters in the amount listed:

	2nd Quarter		3rd Quarter
(in thousands)	2006		2006		Total
Net gain	$	319	$	108	$	427

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 March 31, 2006 was $3.0 million. As of March 31, 2006 we had a net credit risk exposure of $4.6 million from 12 counterparties with investment grade credit ratings. We have no exposure at March 31, 2006 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch).

The $4.6 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 March 31, 2006. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Item 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2006, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2006.

During the fiscal quarter ended March 31, 2006, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is the subject of various pending or threatened legal actions and proceedings in the ordinary course of its business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. The Company records a liability in its consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where it has assessed that a loss is probable and an amount can be reasonably estimated. The Company believes that the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

There has been no material change in the risk factors set forth under the caption “Risk Factors and Cautionary Statements” on pages 26 through 28 of the Company’s 2005 Annual Report to Shareholders, which is incorporated by reference to Part I, Item 1A, “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The Company does not have a publicly announced stock repurchase program. The following table shows previously issued common shares that were surrendered to the Company by employees to pay taxes in connection with the vesting of restricted stock granted to such employees under the Company’s 1999 Stock Incentive Plan:

	Total number of		Average price paid
Calendar Month	shares purchased		per share
January 2006		—		—
February 2006		—		—
March 2006		68	$	28.56
Total		68

Item 6. Exhibits

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	OTTER TAIL CORPORATION
	By:	/s/ Kevin G. Moug
		Kevin G. Moug
	Chief Financial Officer and Treasurer
(Chief Financial Officer/Authorized Officer)

Dated:    May 10, 2006

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EXHIBIT INDEX

Exhibit Number	Description
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.