Edgar Filing: OTTER TAIL CORP

e10vq

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, 2007


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 incorporation or organization)		(I.R.S. Employer 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, 2007 – 29,727,759 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX


	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets – March 31, 2007 and December 31, 2006 (not audited)		2 & 3

Consolidated Statements of Income — Three Months Ended March 31, 2007 and 2006 (not audited)		4

Consolidated Statements of Cash Flows — Three Months Ended March 31, 2007 and 2006 (not audited)		5

Notes to Consolidated Financial Statements (not audited)		6-16

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17-29

Item 3. Quantitative and Qualitative Disclosures About Market Risk		29-31

Item 4. Controls and Procedures		31

Part II. Other Information

Item 1. Legal Proceedings		31

Item 1A. Risk Factors		31

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32

Item 6. Exhibits		32

Signatures		32
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,
	2007		2006
	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	—	$	6,791
Accounts receivable:
Trade—net		151,645		135,011
Other		10,388		10,265
Inventories		100,570		103,002
Deferred income taxes		8,179		8,069
Accrued utility revenues		28,676		23,931
Costs and estimated earnings in excess of billings		48,227		38,384
Other		16,929		9,611
Assets of discontinued operations		289		289

Total current assets		364,903		335,353

Investments and other assets		31,241		29,946
Goodwill—net		98,110		98,110
Other intangibles—net		20,858		20,080

Deferred debits
Unamortized debt expense and reacquisition premiums		5,994		6,133
Regulatory assets and other deferred debits		49,177		50,419

Total deferred debits		55,171		56,552

Plant
Electric plant in service		936,575		930,689
Nonelectric operations		242,745		239,269

Total plant		1,179,320		1,169,958
Less accumulated depreciation and amortization		488,769		479,557

Plant—net of accumulated depreciation and amortization		690,551		690,401
Construction work in progress		37,603		28,208

Net plant		728,154		718,609


Total	$	1,298,437	$	1,258,650

See accompanying notes to consolidated financial statements

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


	March 31,			December 31,
	2007			2006
	(Thousands of dollars)
Current liabilities
Short-term debt	$	74,100		$	38,900
Current maturities of long-term debt		3,114			3,125
Accounts payable		122,219			120,195
Accrued salaries and wages		21,059			28,653
Accrued federal and state income taxes		6,076			2,383
Other accrued taxes		11,202			11,509
Other accrued liabilities		13,114			10,495
Liabilities of discontinued operations		197			197

Total current liabilities		251,081			215,457

Pensions benefit liability		42,915			44,035
Other postretirement benefits liability		32,764			32,254
Other noncurrent liabilities		20,122			18,866

Deferred credits
Deferred income taxes		112,136			112,740
Deferred investment tax credit		7,896			8,181
Regulatory liabilities		62,995			63,875
Other		1,204			281

Total deferred credits		184,231			185,077

Capitalization
Long-term debt, net of current maturities		254,804			255,436

Class B stock options of subsidiary		1,255			1,255

Cumulative preferred shares authorized 1,500,000 shares without par value; outstanding 2007 and 2006 — 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 2007 — 29,650,137 and 2006 — 29,521,770		148,251			147,609
Premium on common shares		101,985			99,223
Retained earnings		246,467			245,005
Accumulated other comprehensive loss		(938	)		(1,067	)

Total common equity		495,765			490,770
Total capitalization		767,324			762,961


Total	$	1,298,437		$	1,258,650

See accompanying notes to consolidated financial statements

Otter Tail Corporation

Consolidated Statements of Income

(not audited)


	Three months ended
	March 31,
	2007		2006
	(In thousands, except share
	and per share amounts)
Operating revenues
Electric	$	89,853	$	82,488
Nonelectric		211,268		175,319

Total operating revenues		301,121		257,807

Operating expenses
Production fuel — electric		16,425		14,806
Purchased power — electric system use		26,011		18,736
Electric operation and maintenance expenses		26,875		23,407
Cost of goods sold — nonelectric (excludes depreciation; included below)		164,659		132,394
Other nonelectric expenses		30,758		26,248
Depreciation and amortization		13,093		12,224
Property taxes — electric		2,526		2,618

Total operating expenses		280,347		230,433

Operating income		20,774		27,374

Other income and deductions		273		428
Interest charges		4,868		4,444

Income from continuing operations before income taxes		16,179		23,358
Income taxes — continuing operations		5,771		8,503

Net income from continuing operations		10,408		14,855
Net income from discontinued operations net of taxes of $0 and $69 for the respective periods		—		105

Net income		10,408		14,960
Preferred dividend requirements		184		184

Earnings available for common shares	$	10,224	$	14,776


Basic earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.35	$	0.50
Discontinued operations	$	—	$	—

	$	0.35	$	0.50

Diluted earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.34	$	0.50
Discontinued operations	$	—	$	—

	$	0.34	$	0.50

Average number of common shares outstanding — basic		29,503,252		29,325,986
Average number of common shares outstanding — diluted		29,756,904		29,676,117

Dividends per common share	$	0.2925	$	0.2875

See accompanying notes to consolidated financial statements

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)


	Three months ended
	March 31,
	2007			2006
	(Thousands of dollars)
Cash flows from operating activities
Net income	$	10,408		$	14,960
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—			(105	)
Depreciation and amortization		13,093			12,224
Deferred investment tax credit		(283	)		(287	)
Deferred income taxes		(742	)		(866	)
Change in deferred debits and other assets		1,302			(1,149	)
Discretionary contribution to pension plan		(2,000	)		(2,000	)
Change in noncurrent liabilities and deferred credits		3,523			548
Allowance for equity (other) funds used during construction		—			(192	)
Change in derivatives net of regulatory deferral		(151	)		2,489
Stock compensation expense		572			339
Other — net		42			548
Cash (used for) provided by current assets and current liabilities:
Change in receivables		(15,574	)		(660	)
Change in inventories		2,812			(17,811	)
Change in other current assets		(23,047	)		(19,131	)
Change in payables and other current liabilities		(11,323	)		(18,727	)
Change in interest and income taxes payable		5,757			6,717

Net cash used in continuing operations		(15,611	)		(23,103	)
Net cash used in discontinued operations		—			(95	)

Net cash used in operating activities		(15,611	)		(23,198	)


Cash flows from investing activities
Capital expenditures		(23,866	)		(15,473	)
Proceeds from disposal of noncurrent assets		5,739			94
Acquisitions—net of cash acquired		(1,965	)		—
Increases in other investments		(5,449	)		(1,331	)

Net cash used in investing activities — continuing operations		(25,541	)		(16,710	)
Net cash provided by investing activities — discontinued operations		—			900

Net cash used in investing activities		(25,541	)		(15,810	)


Cash flows from financing activities
Change in checks written in excess of cash		5,629			12,842
Net short-term borrowings		35,200			29,181
Proceeds from issuance of common stock, net of issuance expenses		2,787			869
Payments for retirement of common stock		(2	)		(2	)
Proceeds from issuance of long-term debt		90			57
Debt issuance expenses		(77	)		—
Payments for retirement of long-term debt		(748	)		(773	)
Dividends paid		(8,828	)		(8,643	)

Net cash provided by financing activities — continuing operations		34,051			33,531
Net cash provided by financing activities — discontinued operations		—			—

Net cash provided by financing activities		34,051			33,531

Effect of foreign exchange rate fluctuations on cash		310			47

Net change in cash and cash equivalents		(6,791	)		(5,430	)
Cash and cash equivalents at beginning of period — continuing operations		6,791			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)	$	2,449		$	2,094
Income taxes	$	1,046		$	4,813

Cash paid during the year from discontinued operations for:
Interest	$	—		$	50
Income taxes	$	—		$	257

See accompanying notes to consolidated financial statements

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, 2006, 2005 and 2004 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Because of seasonal and other factors, the earnings for the three months ended March 31, 2007 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, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

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


	March 31,			December 31,
(in thousands)	2007			2006

Costs incurred on uncompleted contracts	$	216,491		$	257,370
Less billings to date		(229,033	)		(284,273	)
Plus estimated earnings recognized		36,241			35,955

	$	23,699		$	9,052

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)	2007			2006

Costs and estimated earnings in excess of billings on uncompleted contracts	$	48,227		$	38,384
Billings in excess of costs and estimated earnings on uncompleted contracts		(24,528	)		(29,332	)

	$	23,699		$	9,052

Adjustments and Reclassifications

The Company’s consolidated statements of income and cash flows for the three months ended March 31, 2006 reflect the reclassifications of the operating results, assets and liabilities of the natural gas marketing operations of OTESCO, the Company’s energy services company, to discontinued operations as a result of the sale of these operations in June 2006.

Inventories

Inventories consist of the following:


	March 31,		December 31,
(in thousands)	2007		2006

Finished goods	$	42,404	$	46,477
Work in process		4,668		5,663
Raw material, fuel and supplies		53,498		50,862

	$	100,570	$	103,002

Goodwill and Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at March 31, 2007 and December 31, 2006:


	March 31, 2007						December 31, 2006
	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	$	2,575	$	1,900	$	675	$	2,198	$	1,813	$	385
Customer relationships		10,579		1,126		9,453		10,574		1,016		9,558
Other intangible assets including contracts		2,704		1,403		1,301		2,083		1,291		792

Total	$	15,858	$	4,429	$	11,429	$	14,855	$	4,120	$	10,735

Non-amortized intangible assets:
Brand/trade name	$	9,429	$	—	$	9,429	$	9,345	$	—	$	9,345

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 $309,000 for the three months ended March 31, 2007 compared to $266,000 for the three months ended March 31, 2006. The estimated annual amortization expense for these intangible assets for the next five years is $984,000 for 2007, $968,000 for 2008, $780,000 for 2009, $641,000 for 2010 and $493,000 for 2011.

Comprehensive Income


	Three months ended
	March 31,
(in thousands)	2007			2006

Net income	$	10,408		$	14,960
Other comprehensive income (loss) (net-of-tax)
Foreign currency translation gain (loss)		104			(55	)
Amortization of unrecognized losses and costs related to postretirement benefit programs		44			—
Unrealized loss on available-for-sale securities		(19	)		(7	)

Total other comprehensive income (loss)		129			(62	)

Total comprehensive income	$	10,537		$	14,898

New Accounting Standards

FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, was issued by the Financial Accounting Standards Board (FASB) in June 2006. FIN No. 48 clarifies the accounting for uncertain tax positions in accordance with SFAS 109, Accounting for Income Taxes. The Company adopted FIN No. 48 on January 1, 2007 and has recognized, in its consolidated financial statements, the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of March 31, 2007. The term “more-likely-than-not” means a likelihood of more than 50%. FIN No. 48 also provides guidance on new disclosure requirements, reporting and accrual of interest and penalties, accounting in interim periods and transition. Only tax positions that meet the “more-likely-than-not” threshold on the reporting date may be recognized. The cumulative effect of adoption of FIN No. 48, which is reported as an adjustment to the beginning balance of retained earnings, was $119,000. As of the date of adoption, the total amount of unrecognized tax benefits for uncertain tax positions was $1,874,000. The amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate was $575,000 as of January 1, 2007.

The amount of unrecognized tax benefits is not expected to change significantly within the next 12 months.

The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes. The total amount of interest and penalties accrued as of the date of adoption of FIN No. 48 was $351,000.

The Company and its subsidiaries file a consolidated federal income tax return and various state income tax returns. As of the date of adoption of FIN No. 48, the Company is no longer subject to U.S. federal income tax examinations by tax authorities for years before 2003. As of March 31, 2007 the Company’s earliest open tax year in which an audit can be initiated by state taxing authorities in the Company’s major operating jurisdictions is 2003 for both Minnesota and North Dakota.

SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 will be effective for fiscal years beginning after November 15, 2007. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements where fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. The Company cannot predict what, if any, impact this new standard will have on its consolidated financial statements when the standard becomes effective in 2008.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115, was issued by the FASB in February 2007. SFAS No. 159, provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses in earnings at each subsequent reporting date on items for which the fair value option has been elected. This statement also establishes presentation and disclosure requirements to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company is evaluating the impact that adoption of SFAS No. 159 could have on its consolidated financial statements.

Acquisitions

On February 19, 2007 ShoreMaster, Inc. (ShoreMaster) acquired the assets of the Aviva Sports product line for $2.0 million in cash. The Aviva Sports product line will be operated through Aviva Sports, Inc. (Aviva), a newly-formed wholly owned subsidiary of ShoreMaster. The Aviva Sports product line is sold internationally and consists of products for consumer use in the pool, lake and yard, as well as commercial use at summer camps, resorts and large public swimming pools. The acquisition of the Aviva Sports product line fits well with the other product lines of ShoreMaster, a leading manufacturer and supplier of waterfront equipment.

Disclosure of pro forma information related to the results of operations of the acquired entity for the periods presented in this report is not required due to immateriality.

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


(in thousands)	Aviva

Assets
Current assets	$	2,083
Goodwill		—
Other intangible assets		870

Total assets	$	2,953


Liabilities
Current liabilities	$	988
Noncurrent liabilities		—

Total liabilities	$	988

Cash paid	$	1,965

Other intangible assets related to the Aviva acquisition include $83,000 for a nonamortizable brand name and $787,000 in intangible assets being amortized over 2 to 15 years.

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. In addition, the electric utility is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. The electric utility

operations have been the Company’s primary business since incorporation. The Company’s electric operations, including wholesale power sales, are operated as a division of Otter Tail Corporation.

All of the businesses in the following segments are owned by a wholly owned subsidiary of the Company.

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

Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, material and handling trays and horticultural containers, contract machining, and metal parts stamping and fabrication. These businesses have manufacturing facilities in Minnesota, North Dakota, South Carolina, Missouri, California, Florida and Ontario, Canada and sell products primarily in the United States.

Health services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide equipment maintenance, diagnostic imaging services and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

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

Other business operations consists of businesses in residential, commercial and industrial electric contracting industries, fiber optic and electric distribution systems, wastewater and HVAC systems construction, transportation and energy services, as well as the portion of corporate general and administrative expenses that are not allocated to other segments. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and 6 Canadian provinces.

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

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


	Three months ended
	March 31,
	2007			2006

United States of America		96.5	%		97.0	%
Canada		1.2	%		1.6	%
All other countries (none greater than 1%)		2.3	%		1.4	%

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, 2007 and 2006 and total assets by business segment as of March 31, 2007 and December 31, 2006 are presented in the following tables:

Operating Revenue


	Three months ended
	March 31,
(in thousands)	2007			2006

Electric	$	89,980		$	82,584
Plastics		37,819			38,105
Manufacturing		86,225			68,257
Health services		32,963			32,076
Food ingredient processing		19,495			9,350
Other business operations		35,796			28,279
Intersegment eliminations		(1,157	)		(844	)

Total	$	301,121		$	257,807

Earnings Available for Common Shares from Continuing Operations


	Three months ended
	March 31,
(in thousands)	2007			2006

Electric	$	5,738		$	9,274
Plastics		2,828			4,576
Manufacturing		2,539			2,245
Health services		948			321
Food ingredient processing		449			(1,010	)
Other business operations*		(2,278	)		(735	)

Total	$	10,224		$	14,671


*		Other business operations includes unallocated corporate expenses net-of-tax of $2,524,000 and $1,876,000 for the three months ended March 31, 2007 and 2006, respectively.

Total Assets


	March 31,		December 31,
(in thousands)	2007		2006

Electric	$	699,377	$	689,653
Plastics		90,087		80,666
Manufacturing		248,948		219,336
Health services		68,877		66,126
Food ingredient processing		93,057		94,462
Other business operations		97,802		108,118
Discontinued operations		289		289

Total	$	1,298,437	$	1,258,650

Rate and Regulatory Matters

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. On May 17, 2006 the FERC issued a Notice of Extension of Time, permitting MISO to delay compliance with the directives contained in its April 2006 order, including the requirement to refund to customers the amounts due, with interest, from April 1, 2005 and the requirement to submit a compliance filing. The Notice stated that the order on rehearing would provide the appropriate guidance regarding the timing of compliance filing. On October 26, 2006 the FERC issued an order on rehearing of the April 25, 2006 order, stating it would not require refunds related to real-time RSG charges that had not been allocated to day-ahead virtual supply offers in accordance with MISO’s TEMT going back to the commencement of the MISO Day 2 market in April 2005. However, the FERC ordered prospective allocation of RSG charges to virtual transactions consistent with the TEMT to prevent future inequity and directed MISO to propose a charge that assesses RSG costs to virtual supply offers based on the RSG costs that virtual supply offers cause within 60 days of the October 26, 2006 order. On December 27, 2006 the FERC issued an order granting rehearing of the October 26, 2006 order.

On March 15, 2007 the FERC issued an order on rehearing denying requests for rehearing of the RSG rehearing order dated October 27, 2006. In the March 15, 2007 order on rehearing the FERC stated that its findings in the April 25, 2006 RSG order that virtual offers should share in the allocation of RSG costs, per the terms of the currently-effective tariff, served as notice to market participants that virtual offers, for those market participants withdrawing energy, were liable for RSG charges. FERC clarified that the RSG rehearing order’s waiver of refunds applies to the period before that order, from market start-up in April 2005 until April 24, 2006. After that date, virtual supply offers are liable for RSG costs and therefore, to the extent virtual supply offers were not assessed RSG costs, refunds are due for the period starting April 25, 2006.

The Company recorded a $1.7 million ($1.0 million net-of-tax) charge to earnings in the first quarter of 2007 based on an estimate of the net impact of MISO reallocating RSG charges in response to the FERC order on rehearing.

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)	2007		2006

Regulatory assets:
Unrecognized transition obligation, prior service costs and actuarial losses on pension and other postretirement benefits	$	35,886	$	36,736
Accrued cost-of-energy revenue		16,945		10,735
Deferred income taxes		11,551		11,712
Reacquisition premiums		2,619		2,694
Deferred conservation program costs		700		1,036
MISO schedule 16 and 17 deferred administrative costs		627		541
Accumulated ARO accretion/depreciation adjustment		273		249
Plant acquisition costs		140		151

Total regulatory assets	$	68,741	$	63,854

Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	57,799	$	58,496
Deferred income taxes		5,047		5,228
Gain on sale of division office building		149		151

Total regulatory liabilities	$	62,995	$	63,875

Net regulatory asset (liability) position	$	5,746	$	(21	)

The regulatory asset related to the unrecognized transition obligation on postretirement medical benefits and prior service costs and actuarial losses on pension and other postretirement benefits represents benefit costs that will be subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. The regulatory assets and liabilities related to deferred income taxes result from changes in statutory tax rates accounted for in accordance with SFAS No. 109, Accounting for Income Taxes. Accrued cost-of-energy revenue included in Accrued utility revenues will be recovered over the next nine months. Reacquisition premiums included in Unamortized debt expense and reacquisition premiums are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 15.3 years. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. MISO schedule 16 and 17 deferred administrative costs were excluded from recovery through the Fuel Clause Adjustment (FCA) in Minnesota in a December 2006 order issued by the Minnesota Public Utilities Commission (MPUC). The MPUC ordered the Company to refund MISO schedule 16 and 17 charges that had been recovered through the FCA since the inception of MISO Day 2 markets in April 2005, but allowed for deferral and possible recovery of those costs through rates established in the Company’s next rate case scheduled to be filed on or before October 1, 2007. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. Plant acquisition costs will be amortized over the next 3.2 years. The remaining regulatory assets and liabilities are being recovered from, or will be paid to, electric customers over the next 30 years.

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

Common Shares and Earnings per Share

In the first three months of 2007 the Company issued 127,931 common shares for stock options exercised and 500 common shares for director’s compensation and retired 64 common shares for tax withholding purposes related to 996 restricted shares that vested in March 2007.

Basic earnings per common share are calculated by dividing earnings available for common shares by the weighted average number of common shares outstanding during the period. Diluted earnings per common share are calculated by adjusting outstanding shares, assuming conversion of all potentially dilutive stock options. Stock options with exercise prices greater than the market price are excluded from the calculation of diluted earnings per common share. Nonvested restricted shares granted to the Company’s directors and employees are considered dilutive for the purpose of calculating diluted earnings per share but are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. Underlying shares related to nonvested restricted stock units granted to employees are considered dilutive for the purpose of calculating diluted earnings per share. Shares expected to be awarded for stock performance awards granted to executive officers are considered dilutive for the purpose of calculating diluted earnings per share.

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the quarters ended March 31, 2007 and 2006:


Quarter ended March 31,	Options Outstanding	Range of Exercise Prices

2007	—	N/A
2006	231,624	$29.74 — $31.34

Share-based Payments

The Company has six share-based payment programs. No new stock awards were granted under these programs in the first quarter of 2007. As of March 31, 2007 the total remaining unrecognized compensation expense related to stock-based compensation was approximately $2.6 million (before income taxes) which will be amortized over a weighted-average period of 1.9 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three months ended March 31, 2007 and 2006 are presented in the table below:


	Three months ended
	March 31,
(in thousands)	2007		2006

1999 Employee Stock Purchase Plan	$	64	$	60
Stock options granted under the 1999 Stock Incentive Plan		68		68
Restricted stock granted to directors		151		71
Restricted stock granted to employees		166		291
Restricted stock units granted to employees		69		—
Stock performance awards granted to executive officers		221		94

Totals	$	739	$	584

Class B Stock Options of Subsidiary

As of March 31, 2007 there were 1,058 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $952,000, of which 200 options were “in-the-money” with a combined exercise price of $30,000.

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)	2007			2006

Service cost—benefit earned during the period	$	1,263		$	1,210
Interest cost on projected benefit obligation		2,733			2,544
Expected return on assets		(3,223	)		(3,065	)
Amortization of prior-service cost		185			186
Amortization of net actuarial loss		309			378

Net periodic pension cost	$	1,267		$	1,253

The Company made a $2.0 million discretionary contribution to its pension plan in the three months ended March 31, 2007 and expects to make an additional $2.0 million contribution later in 2007.

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)	2007		2006

Service cost—benefit earned during the period	$	156	$	106
Interest cost on projected benefit obligation		363		326
Amortization of prior-service cost		17		18
Recognized net actuarial loss		135		118

Net periodic pension cost	$	671	$	568

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)	2007			2006

Service cost—benefit earned during the period	$	315		$	334
Interest cost on projected benefit obligation		698			637
Amortization of transition obligation		187			187
Amortization of prior-service cost		(51	)		(76	)
Amortization of net actuarial loss		129			133
Effect of Medicare Part D expected subsidy		(410	)		(293	)

Net periodic postretirement benefit cost	$	868		$	922

Discontinued Operations

In June 2006, OTESCO, the Company’s energy services company, sold its gas marketing operations for $0.5 million in cash. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets requires that OTESCO’s gas marketing operations be classified and reported separately as discontinued operations. The results of discontinued operations for the three months ended March 31, 2006 are summarized as follows:


	Three months ended
(in thousands)	March 31, 2006

Operating revenues	$	20,971
Income before income taxes		174
Income tax expense		69

At both March 31, 2007 and December 31, 2006 the major components of assets and liabilities of discontinued operations at estimated fair market values consisted of deferred taxes of $289,000 and warranty reserves of $197,000 from St. George Steel Fabrication, Inc., which was sold in 2005.

Subsequent Events

On April 9, 2007 the Compensation Committee of the Company’s Board of Directors granted 23,450 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan) payable in common shares on April 8, 2011, the date the units vest. The grant date fair value of each restricted stock unit was $30.07 per share, as determined under a Monte Carlo valuation method.

On April 9, 2007 the Compensation Committee of the Company’s Board of Directors granted 15,200 shares of restricted stock to the Company’s nonemployee directors under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2008 through 2011. The grant date fair value of each share of restricted stock was $35.045 per share, the average market price on the date of grant.

On April 13, 2007 Otter Tail Corporation, dba Otter Tail Power Company, and U.S. Bank National Association entered into a First Amendment to Credit Agreement dated as of April 13, 2007 (the Amendment), amending the Credit Agreement dated as of September 1, 2006 (the Credit Agreement). The Amendment increases the commitment under the Credit Agreement from $25 million to $50 million. The Amendment contains no other changes to the Credit Agreement. The Credit Agreement creates an unsecured revolving credit facility that the Company can draw on to support the working capital needs and other capital requirements of the Company’s electric operations.

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, 2007 and 2006

Consolidated operating revenues were $301.1 million for the three months ended March 31, 2007 compared with $257.8 million for the three months ended March 31, 2006. Operating income was $20.8 million for the three months ended March 31, 2007 compared with $27.4 million for the three months ended March 31, 2006. The Company recorded diluted earnings per share from continuing operations of $0.34 for the three months ended March 31, 2007 compared to $0.50 for the three months ended March 31, 2006.

Following is a more detailed analysis of our operating results by business segment for the quarters ended March 31, 2007 and 2006, followed by our outlook for the remainder of 2007 and a discussion of changes in our consolidated financial position during the quarter ended March 31, 2007.

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, 2007 and 2006 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:


(in thousands)	March 31, 2007		March 31, 2006

Operating revenues:
Electric	$	127	$	96
Nonelectric		1,030		748
Cost of goods sold		367		320
Other nonelectric expenses		790		524

Electric


	Three months ended
	March 31,									%
(in thousands)	2007			2006			Change			Change

Retail sales revenues	$	81,176		$	73,359		$	7,817			10.7
Wholesale revenues		4,234			5,658			(1,424	)		(25.2	)
Net marked-to-market loss		(31	)		(909	)		878			96.6
Other revenues		4,601			4,476			125			2.8

Total operating revenues	$	89,980		$	82,584		$	7,396			9.0
Production fuel		16,425			14,806			1,619			10.9
Purchased power — system use		26,011			18,736			7,275			38.8
Other operation and maintenance expenses		26,875			23,407			3,468			14.8
Depreciation and amortization		6,670			6,357			313			4.9
Property taxes		2,526			2,618			(92	)		(3.5	)

Operating income	$	11,473		$	16,660		$	(5,187	)		(31.1	)

The main contributor to the increase in retail revenues between the quarters was a $6.3 million increase in Fuel Clause Adjustment (FCA) revenues related to an $8.8 million increase in fuel and purchased power costs incurred to serve retail customers. The remaining $1.5 million increase in retail revenues was due to a 3.8% increase in retail megawatt-hour (mwh) sales resulting from a 10.4% increase in heating degree-days between the quarters. FCA

revenues in the first quarter of 2006 included the reversal of a $1.9 million refund provision established in December 2005. The refund provision related to Midwest Independent Transmission System Operator (MISO) costs subject to collection through the FCA in Minnesota. In December 2005, the Minnesota Public Utilities Commission (MPUC) issued an order denying recovery of certain MISO-related costs through the FCA and requiring a refund of amounts previously collected. In February 2006, the MPUC reconsidered its order and eliminated the refund requirement.

Wholesale electric revenues from company-owned generation were $6.0 million for the quarter ended March 31, 2007 compared with $5.4 million for the quarter ended March 31, 2006. Wholesale revenues from company-owned generation increased as a result of a 137% increase in the price per mwh sold despite a 52.5% decrease in wholesale mwh sales from company-owned generation. Net losses from the resale of purchased power combined with net mark-to-market losses on forward energy contracts were $1.8 million for the quarter ended March 31, 2007 compared with $0.6 million for the quarter ended March 31, 2006. In the first quarter of 2007, net losses from energy trading activities were the result of a $1.7 million ($1.0 million net-of-tax) charge to earnings for the expected reallocation of MISO revenue sufficiency guarantee (RSG) charges to day-ahead virtual supply offers going back to April 25, 2006, as a result of a March 15, 2007 Federal Energy Regulatory Commission (FERC) order.

The increase in fuel costs for the three months ended March 31, 2007 compared with the three months ended March 31, 2006 reflects a 17.6% increase in the cost of fuel per mwh generated partially offset by a 5.7% reduction in mwhs generated. Generation used for wholesale electric sales decreased 52.5% while generation for retail sales increased 2.3% between the periods. Fuel costs and fuel costs per mwh increased between the periods mainly due to increased generation from the Company’s natural gas- and fuel oil-fired combustion turbine peaking plants as a result of reduced availability of Coyote Station due to boiler tube leaks and Big Stone Plant due to poor performance of its Advanced Hybrid Particulate Collector (AHPC) system. Coyote Station and Big Stone Plant are the Company’s lowest cost generating units. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the FCA component of retail rates.

The increase in purchased power — system use is due to a 10.1% increase in mwhs purchased combined with a 26.1% increase in the cost per mwh purchased. The increase in mwh purchases for system use was directly related to the increase in retail mwh sales between the quarters. The increase in the cost per mwh of purchased power reflects a general increase in fuel and purchased power costs across the Mid-Continent Area Power Pool (MAPP) region as a result of higher demand due to colder weather in the first quarter of 2007 compared with the first quarter of 2006 combined with reduced availability of generation in the Upper-Missouri River Basin and from Manitoba Hydro and transmission constraints in Iowa in the first quarter of 2007.

The increase in other operation and maintenance expenses for the three months ended March 31, 2007 compared with the three months ended March 31, 2006 is mainly due to a decrease 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 2007 and an increase in labor costs as a result of wage increases. 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, 2007 compared with the three months ended March 31, 2006 as a result of a $20 million increase in electric plant in service in 2006.

Plastics


	Three months ended
	March 31,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	37,819	$	38,105	$	(286	)		(0.8	)
Cost of goods sold		30,648		28,180		2,468			8.8
Operating expenses		1,539		1,448		91			6.3
Depreciation and amortization		765		730		35			4.8

Operating income	$	4,867	$	7,747	$	(2,880	)		(37.2	)

Operating revenues for the plastics segment decreased mainly as result of a 26.6% decrease in the price per pound of pipe sold, offset by a 35.9% increase in pounds of pipe sold between the quarters. The decrease in revenue reflects the effect of a decrease in PVC resin prices between the periods. The increase in cost of goods sold was related to the increase in pounds of pipe sold. While the price per pound of pipe sold decreased by 26.6%, the cost per pound sold only decreased by 20.0%, resulting in a $2.8 million decrease in gross profit margins between the periods.

Manufacturing


	Three months ended
	March 31,						%
(in thousands)	2007		2006		Change		Change

Operating revenues	$	86,225	$	68,257	$	17,968		26.3
Cost of goods sold		69,246		54,399		14,847		27.3
Operating expenses		7,931		6,215		1,716		27.6
Depreciation and amortization		3,110		2,569		541		21.1

Operating income	$	5,938	$	5,074	$	864		17.0

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

	•		Revenues at DMI Industries, Inc. (DMI) increased $17.2 million as a result of increases in production and sales activity due in part to plant additions, including operations at the Ft. Erie facilities which commenced in May 2006, and continued improvements in productivity and capacity utilization.

	•		Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $1.1 million between the quarters despite a 19.5% decrease in unit sales, as a result of 35.8% increase in the average price per unit sold.

	•		Revenues at ShoreMaster, Inc. (ShoreMaster) increased $0.4 million between the quarters, mainly as a result of the acquisition of the Aviva Sports product line in February 2007.

	•		Revenues at BTD Manufacturing, Inc. (BTD) decreased $0.7 million mainly as a result of a 10.0% decrease in unit sales partially offset by a 7.0% increase in the average price per unit sold.

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

•

DMI’s cost of goods sold increased $14.5 million between the quarters, including $10.1 million in material costs increases. The increase in cost of goods sold is directly related to DMI’s increase in production and sales activity, including operations at the Ft. Erie facilities which commenced in May 2006.

	•		Cost of goods sold at T.O. Plastics increased $1.1 million, including $0.5 million in material cost increases and $0.5 million in increased manufacturing overhead and freight costs.

	•		Cost of goods sold at ShoreMaster remained relatively unchanged between the quarters.

	•		Cost of goods sold at BTD decreased $0.6 million between the quarters mainly due to decreases in shop supply and maintenance costs and indirect labor costs related to productivity improvements.

The increase in operating expenses in our manufacturing segment is due to the following:

	•		Operating expenses at DMI increased $0.7 million as a result of increases in labor and contracted services and expenses mainly related to operations of the Ft. Erie plant which commenced in May 2006.

	•		ShoreMaster’s operating expenses increased $0.6 million as a result of increases in labor, sales commissions and marketing expenditures, of which approximately $0.3 million relates to the acquisition of the Aviva Sports product line in February 2007.

	•		An increase in labor-related costs contributed to a $0.3 million increase in BTD’s operating expenses between the quarters.

	•		T.O. Plastics operating expenses increased $0.1 million between the quarters.

Depreciation expense increased between the periods mainly as a result of capital additions at DMI’s Ft. Erie plant in 2006.

On January 29, 2007, DMI announced plans to expand wind tower production capacity at its Ft. Erie plant by 30%.The two-phase expansion project will also allow DMI to manufacture larger tower sections at the plant. The first phase became operational in April 2007. On May 2, 2007, DMI announced plans to add a third wind tower manufacturing facility near Tulsa, Oklahoma. If approvals and permits are obtained, the plant is expected to be operational in 2008.

Health Services


	Three months ended
	March 31,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	32,963	$	32,076	$	887			2.8
Cost of goods sold		24,383		24,822		(439	)		(1.8	)
Operating expenses		5,806		5,514		292			5.3
Depreciation and amortization		962		957		5			0.5

Operating income	$	1,812	$	783	$	1,029			131.4

The increase in health services operating revenues for the three months ended March 31, 2007 compared with the three months ended March 31, 2006 includes increases of $0.6 million from equipment sales and servicing and $0.3 million from scanning and other related services. Revenue per scan increased 14.2% while the number of scans completed decreased 14.0% between the quarters. Cost of goods sold decreased $0.4 million between the quarters primarily as a result of higher commissions earned by the health services segment on sales made by Philips in the health services segment service territory compared with equipment sales made directly by the health services segment. The $0.3 million increase in operating expenses is mainly due to higher labor expenses.

Food Ingredient Processing


	Three months ended
	March 31,							%
(in thousands)	2007		2006			Change		Change

Operating revenues	$	19,495	$	9,350		$	10,145		108.5
Cost of goods sold		16,993		9,318			7,675		82.4
Operating expenses		752		685			67		9.8
Depreciation and amortization		969		919			50		5.4

Operating income (loss)	$	781	$	(1,572	)	$	2,353		149.7

The increase in food ingredient processing revenues reflects a 70.3% increase in pounds of product sold combined with a 22.4% increase in the price per pound sold. The increase in revenues was only partially offset by a 7.1% increase in the cost per pound of product sold. A poor European potato crop in 2006 also contributed to the increases in product sales and prices between the quarters.

Other Business Operations


	Three months ended
	March 31,									%
(in thousands)	2007			2006			Change			Change

Operating revenues	$	35,796		$	28,279		$	7,517			26.6
Cost of goods sold		23,756			15,995			7,761			48.5
Operating expenses		15,520			12,910			2,610			20.2
Depreciation and amortization		617			692			(75	)		(10.8	)

Operating loss	$	(4,097	)	$	(1,318	)	$	(2,779	)		(210.8	)

Corporate general and administrative expenses included in the operating losses from other business operations were $4.2 million and $3.1 million for the quarters ended March 31, 2007 and 2006, respectively. Net operating income from other business operations before corporate general and administrative expenses was $0.1 million and $1.8 million for the quarters ended March 31, 2007 and 2006, respectively.

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

	•		Revenues at Midwest Construction Services, Inc. (MCS) increased $3.7 million between the quarters as a result of an increase in work in progress.

	•		Revenues at Foley Company increased $3.4 million in the first quarter of 2007 compared to the first quarter of 2006 due to an increase in the volume of jobs in progress.

	•		Revenues at E.W. Wylie Corporation (Wylie) increased $0.3 million between the quarters mainly due to a 7.3% increase in miles driven by owner-operated and company-operated trucks. Miles driven by owner-operated trucks increased 13.9% while miles driven by company-operated trucks increased 3.5% between the quarters. Wylie’s increased revenues also reflect a slight increase in fuel costs recovered through fuel surcharges between the quarters.

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

	•		Cost of goods sold at MCS increased $4.1 million between the quarters mostly as a result of increases in material and subcontractor costs on higher-cost contracts.

	•		Foley Company’s cost of goods sold increased $3.7 million, including increases of $2.2 million in labor and benefit costs and $1.5 million in subcontractor and material costs, as a result of increased construction activity and jobs in progress.

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

	•		Corporate operating expenses in this segment increased $1.6 million as a result of higher labor and professional service costs.

	•		Wylie’s operating expenses increased $0.5 million between the quarters, mainly as a result of increases in fuel, equipment rental and contractor expenses.

	•		Foley Company’s operating expenses increased $0.4 million between the quarters.

Income Taxes — Continuing Operations

The $2.7 million (32.1%) decrease in income taxes — continuing operations between the quarters is primarily the result of a $7.2 million (30.7%) decrease in income from continuing operations before income taxes for the three months ended March 31, 2007 compared with the three months ended March 31, 2006. The effective tax rate for continuing operations for the three months ended March 31, 2007 was 35.7% compared to 36.4% for the three months ended March 31, 2006.

Discontinued Operations

In June 2006, OTESCO, the Company’s energy services company, sold its gas marketing operations for $0.5 million in cash. Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets requires that OTESCO’s gas marketing operations be classified and reported separately as discontinued operations.

The results of discontinued operations for the three months ended March 31, 2006 are summarized as follows:


	Three months ended
(in thousands)	March 31, 2006

Income before income taxes	$	174
Income tax expense		69

Net income	$	105

2007 EXPECTATIONS

The statements in this section are based on our current outlook for 2007 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 anticipate 2007 diluted earnings per share from continuing operations to be in a range from $1.60 to $1.80. Contributing to the earnings guidance for 2007 are the following items:

	•		We expect earnings in the range of $19.0 million to $22.5 million in the electric segment in 2007. This change from the original guidance is impacted by lower than expected margins on virtual supply transactions in 2007 relating to the FERC order requiring RSG charges on virtual supply transactions going back to April 25, 2006. This order is expected to have a downward impact on margins from virtual supply transactions for the remainder of 2007.

	•		We expect our plastics segment’s performance to be in the range of $5.5 million to $8.0 million in 2007 because of stronger than expected first quarter performance.

	•		We expect continued enhancements in productivity and capacity utilization, strong backlogs and an announced expansion of DMI’s Ft. Erie, Ontario facility that will increase the facility’s production capacity by 30% to result in increased net income in our manufacturing segment in 2007.

	•		We expect moderate net income growth in our health services segment in 2007.

	•		We expect our food ingredient processing business (IPH) to generate net income in the range of $2.0 million to $4.0 million in 2007.

	•		We expect our other business operations segment to have lower earnings in 2007 compared with 2006 due to an expected return to more normal unallocated corporate cost levels. Our construction companies are expected to have a strong 2007 given current backlogs.

FINANCIAL POSITION

For the period 2007 through 2011, we estimate funds internally generated net of forecasted dividend payments will be sufficient to repay currently outstanding short-term debt and to meet scheduled debt retirements (excluding the scheduled retirement of the $50 million 6.375% senior debentures due December 1, 2007, which is scheduled to be refinanced under a note purchase agreement between the Company and Cascade Investment L.L.C. (Cascade) discussed below). 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 2007 through 2011 given the expansion plans related to our electric segment to fund the construction of the proposed new Big Stone II generating station at the Big Stone Plant site and the construction of the Langdon Wind Project discussed below, in the event we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to complete acquisitions or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.

On March 29, 2007 Otter Tail Power Company and Minnkota Power Cooperative announced that they had entered into an agreement with FPL Energy to develop the Langdon Wind Project, a 159 megawatt (MW) wind farm to be constructed south of Langdon, North Dakota, with an expected completion date in late 2007 or early 2008. Otter Tail Power Company’s participation in the project includes the ownership of 27 wind turbines rated at 1.5 MW each and a 25-year power purchase agreement with Langdon Wind, LLC to purchase the electricity generated from

13 other wind turbines at the site. Contracts related to construction of the 27 wind towers and turbines to be owned by Otter Tail Power Company will increase our 2007 purchase obligations by $86.5 million.

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.

We have a $150 million 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 that expires on April 26, 2009. 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 this 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. 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, 2007, $67.5 million of the Company’s $150 million line of credit was in use and $18.3 million was restricted from use to cover outstanding letters of credit.

On April 13, 2007, Otter Tail Corporation, dba Otter Tail Power Company, and U.S. Bank National Association entered into a First Amendment to Credit Agreement dated as of April 13, 2007 (the Amendment), amending the Credit Agreement dated as of September 1, 2006 (the Credit Agreement). The Amendment increases the commitment under the Credit Agreement from $25 million to $50 million. The Amendment contains no other changes to the Credit Agreement. The Credit Agreement is an unsecured revolving credit facility that can be drawn on to support the working capital needs and other capital requirements of our electric operations. This line of credit expires on September 1, 2007. Borrowings under this line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of our senior unsecured debt. This line of credit contains terms that are substantially the same as those under our $150 million line of credit. As of March 31, 2007, $6.6 million was borrowed under the Credit Agreement.

In February 2007, we entered into a note purchase agreement with Cascade pursuant to which we agreed to issue to Cascade, in a private placement transaction, $50 million aggregate principal amount of our senior notes due November 30, 2017. Cascade is our largest shareholder, owning approximately 8.7% of our outstanding common stock as of December 31, 2006. The notes will bear interest at a rate of 5.778% per annum, subject to adjustment in the event certain ratings assigned to our long-term senior unsecured indebtedness are downgraded below specific levels prior to the closing of the note purchase. The terms of the note purchase agreement are substantially similar to the terms of the note purchase agreement entered into in connection with the issuance of our $90 million 6.63% senior notes due December 1, 2011. The closing is expected to occur on December 3, 2007 subject to the satisfaction of certain conditions to closing, including: (i) no event or events will have occurred since December 31, 2005 that have had or would reasonably be expected to have a material adverse effect on the Company and its subsidiaries taken as a whole; (ii) certain senior executives will remain in their current positions; (iii) there will have been no change in control or impermissible sale of assets; (iv) the ratio of the Company’s consolidated debt to earnings before interest, taxes, depreciation and amortization as of September 30, 2007 will be less than 3.5 to 1; (v) certain waivers will have been obtained; and (vi) certain other customary conditions of closing will have been satisfied. The Company has the right to terminate the note purchase agreement by giving at least 30 days’ prior written notice to Cascade and paying a termination fee of $1 million. The proceeds of this financing will be used to redeem our $50 million 6.375% senior debentures due December 1, 2007.

Our lines of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under our financing agreements as of March 31, 2007.

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

Our securities ratings at March 31, 2007 were:


	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 $15.6 million for the three months ended March 31, 2007 compared with $23.1 million for the three months ended March 31, 2006. The $7.5 million decrease in cash used in operating activities from continuing operations mainly reflects an $8.2 million decrease in cash used for working capital items from $49.6 million in the first quarter of 2006 to $41.4 million in the first quarter of 2007.

Major uses of funds for working capital items in the first three months of 2007 were an increase in other current assets of $23.0 million, an increase in receivables of $15.6 million and a decrease in payables and other current liabilities of $11.3 million, offset by an increase in interest and income taxes payable of $5.8 million and a decrease in inventories of $2.8 million. The increase in other current assets includes increases of: (1) $8.6 million in costs in excess of billings at DMI mainly related to wind tower production to fill a large order that extends through 2007 under contract terms that specify the customer, who has a strong senior unsecured debt rating, will not be billed until the units are shipped, (2) $6.8 million in prepaid insurance across all companies related to the payment of 2007 annual premiums and (3) $4.7 million in unbilled revenue at the electric utility related to increases in fuel and purchased power costs in the first quarter of 2007. The $15.6 million increase in receivables includes $11.5 million from our plastics segment related to increased sales in the first quarter of 2007 compared to the fourth quarter of 2006 and $6.8 million at DMI related to increasing sales of wind towers, offset by a $3.0 million seasonal reduction in receivables at our electric utility company. The decrease in payables and other current liabilities includes a $7.8 million reduction in DMI’s trade accounts payable and billings in excess of costs and a $2.6 million reduction in health services’ trade accounts payable. The increase in interest and income taxes payable, which is normal in the first quarter of our fiscal year, reflects a $2.1 million increase in interest payable and a $3.7 million increase in income taxes payable as a result of the timing of interest and estimated tax payments.

Net cash used in investing activities of continuing operations was $25.5 million for the three months ended March 31, 2007 compared with $16.7 million for the three months ended March 31, 2006. Cash used for capital

expenditures increased by $8.4 million between the quarters. Cash used for capital expenditures at the electric utility increased by $8.0 million including a $5.3 million advance payment for turbines for the Langdon Wind Project, and $2.3 million for replacement of the AHPC flue-gas treatment system at Big Stone Plant. The Company’s subsidiary, ShoreMaster, acquired the Aviva Sports product line for $2.0 million in cash in the first quarter of 2007. The Company made no acquisitions in the first quarter of 2006. The net increase in proceeds from the disposal of noncurrent assets and cash used for other investments of $1.5 million is mainly due to the sales of short-term investments and the reinvestment of proceeds from those sales by the Company’s captive insurance company in the first quarter of 2007.

Net cash provided by financing activities was $34.1 million for the three months ended March 31, 2007 compared with net cashed provided by financing activities of $33.5 million the three months ended March 31, 2006. Proceeds from the issuance of common stock increased $1.9 million due to an increase in the number of stock options exercised in the first quarter of 2007 compared with the first quarter of 2006. The increase in cash from the issuance of common stock was offset by a $1.2 million decrease in cash from short-term borrowings and checks written in excess of cash, and a $0.2 million increase in common dividends paid as a result of increases in the dividend rate and the number of common shares outstanding between the quarters. During the first quarter of 2007 the Company issued 127,931 common shares for stock options exercised and 500 common shares for director’s compensation and retired 64 common shares for tax withholding purposes related to restricted shares that vested in March 2007.

Due to the approval of additional capital expenditures in the first quarter of 2007, we have revised our estimated capital expenditures by segment for 2007 and the years 2007 through 2011 from those presented on page 25 of our 2006 Annual Report to Shareholders as presented in the following table:


(in millions)	2007		2007-2011

Electric	$	215	$	680
Plastics		5		19
Manufacturing		38		78
Health services		2		12
Food ingredient processing		3		17
Other business operations		1		6

Total	$	264	$	812

Current estimated capital expenditures for our share of Big Stone II are $320 million.

There were changes in our contractual obligations in the first quarter of 2007 from those reported under the caption “Capital Requirements” on page 25 of our 2006 Annual Report to Shareholders. These include an increase in “purchase obligations” related to the Langdon Wind Project of approximately $86.5 million in 2007 and increases in “capacity and energy requirements” related to the 25-year power purchase agreement to purchase electricity generated from 13 other turbines at the same site beginning in late 2007 or early 2008. The increase in “capacity and energy requirements” is estimated to be $5.4 million in 2008 and 2009 combined, $5.4 million in 2010 and 2011 combined and $56.7 million in the years beyond 2011.

We do not have any off-balance-sheet arrangements or any material 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, uncertain tax positions, collectability of trade accounts receivable, self-insurance programs, valuation of forward energy contracts, unbilled electric revenues, unscheduled power exchanges, MISO electric market residual load adjustments, service contract maintenance costs, percentage-of-completion and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the Board of Directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 30 through 32 of our 2006 Annual Report to Shareholders. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2007, except for the adoption of Financial Accounting Standards Board Interpretation (FIN) No. 48 on January 1, 2007.

Goodwill Impairment

We currently have $24.2 million of goodwill and a $3.2 million nonamortizable trade name recorded on our balance sheet related to the acquisition of IPH in 2004. If operating margins do not improve according to our projections, the reductions in anticipated cash flows from this business may indicate that its fair value is less than its book value resulting in an impairment of goodwill and nonamortizable intangible assets and a corresponding charge against earnings.

We evaluate goodwill for impairment on an annual basis and as conditions warrant. As of December 31, 2006 an assessment of the carrying values of our goodwill indicated no impairment.

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 federal and state legislation, regulations and actions that may have a negative impact on our business and results of operations.

•		Future operating results of the electric segment will be impacted by the outcome of a rate case to be filed in Minnesota in late 2007.

•		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 further reduced as the MISO market becomes more efficient.

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

•		Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

•		Wholesale sales of electricity from excess generation could be reduced by reductions in coal shipments to the Big Stone and Hoot Lake plants due to supply constraints or rail transportation problems beyond our control.

•		Our electric segment has capitalized $6.5 million in costs related to the planned construction of a second electric generating unit at its Big Stone Plant site as of March 31, 2007. Should approvals of permits not be received on a timely basis, the project could be at risk. If the project is abandoned for permitting or other reasons these capitalized costs and others incurred in future periods may be subject to expense and may not be recoverable.

•		Our manufacturer of wind towers operates in a market that has been dependent on the Federal Production Tax Credit. This tax credit is currently in place through December 31, 2008. Should this tax credit not be 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.

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

•		Our plan to grow our nonelectric businesses could be limited by state law.

•		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.

•		The price and availability of raw materials could affect the revenue and earnings of our manufacturing segment.

•		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, many of which are located in the Gulf Coast regions, and a limited supply of resin. The loss of a key vendor or an interruption or delay in the supply of PVC resin could result in reduced sales or increased costs for this 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.

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

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

•		A significant failure or an inability to properly bid or perform on projects by our construction businesses could lead to adverse financial results.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At March 31, 2007 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 34% 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, 2007 we had $10.4 million of long-term debt subject to variable interest rates. Assuming no change in our financial structure, if variable interest rates were to average one percentage point higher or lower than the average variable rate on March 31, 2007, annualized interest expense and pre-tax earnings would change by approximately $104,000.

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

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

The electric utility has market, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of March 31, 2007 the electric utility had recognized, on a pretax basis, $17,000 in net unrealized losses on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties or brokers used by the electric utility’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange. Prices are benchmarked to regional hub prices as published in Megawatt Daily and forward price curves and indices acquired from a third party price forecasting service. Of the forward energy contracts that are marked to market as of March 31, 2007, all of the forward sales of electricity had offsetting purchases in terms of volumes and delivery periods.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales and financial transactions in the MISO Day 2 markets that employ volumetric limits and loss limits and Value at Risk (VaR) limits to adequately manage the risks associated with these activities. Exposure to price risk on any open positions as of March 31, 2007 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, 2007 and the change in our consolidated balance sheet position from December 31, 2006 to March 31, 2007:


(in thousands)	March 31, 2007

Current asset — marked-to-market gain	$	1,946
Current liability — marked-to-market loss		(1,963	)

Net fair value of marked-to-market gas contracts	$	(17	)


	Year-to-date
(in thousands)	March 31, 2007

Fair value at beginning of year	$	203
Amount realized on contracts entered into in 2006 and settled in 2007		(159	)
Changes in fair value of contracts entered into in 2006		—

Net fair value of contracts entered into in 2006 at end of period		44
Changes in fair value of contracts entered into in 2007		(61	)

Net fair value end of period	$	(17	)

The $17,000 recognized but unrealized net losses on the forward energy purchases and sales marked to market on March 31, 2007 is expected to be realized on physical settlement as scheduled over the following quarters in the amounts listed:


	2nd Quarter		3rd Quarter
(in thousands)	2007		2007			Net

Net gain	$	83	$	(100	)	$	(17	)

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, 2007 was $342,000. As of March 31, 2007 we had a net credit risk exposure of $1.2 million from 9 counterparties with investment grade credit ratings. We had no exposure at March 31, 2007 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 $1.2 million credit risk exposure includes net amounts due to the electric utility on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after March 31, 2007. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

IPH has market risk associated with the price of fuel oil and natural gas used in its potato dehydration process as IPH may not be able increase prices for its finished products to recover increases in fuel costs. In the third quarter of 2006, IPH entered into forward natural gas contracts on the New York Mercantile Exchange market to hedge its exposure to fluctuations in natural gas prices related to approximately 50% of its anticipated natural gas needs through March 2007 for its Ririe, Idaho and Center, Colorado dehydration plants. These forward contracts were derivatives subject to mark-to-market accounting but they did not qualify for hedge accounting treatment. IPH includes net changes in the market values of these forward contracts in net income as components of cost of goods sold in the period of recognition. Of the $371,000 in unrealized marked-to-market losses on forward natural gas contracts IPH had outstanding on December 31, 2006, $62,000 was reversed and $309,000 was realized on settlement in the first quarter of 2007.

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 (the Exchange Act)) as of March 31, 2007, 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, 2007.

During the fiscal quarter ended March 31, 2007, 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 have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 29 of the Company’s 2006 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, 2006.

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
Calendar Month	shares purchased		Average price paid per share

January 2007		—		—
February 2007		—		—
March 2007		64	$	31.89

Total		64

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.

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, 2007

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

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