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 June 30, 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:

July 24, 2007 – 29,761,657 Common Shares ($5 par value)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

-Assets-


	June 30,		December 31,
	2007		2006
	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	—	$	6,791
Accounts receivable:
Trade—net		163,204		135,011
Other		8,671		10,265
Inventories		98,791		103,002
Deferred income taxes		8,219		8,069
Accrued utility revenues		17,793		23,931
Costs and estimated earnings in excess of billings		41,555		38,384
Other		20,858		9,611
Assets of discontinued operations		—		289

Total current assets		359,091		335,353

Investments and other assets		31,113		29,946
Goodwill—net		99,158		98,110
Other intangibles—net		20,941		20,080

Deferred debits
Unamortized debt expense and reacquisition premiums		5,824		6,133
Regulatory assets and other deferred debits		46,923		50,419

Total deferred debits		52,747		56,552

Plant
Electric plant in service		940,043		930,689
Nonelectric operations		248,983		239,269

Total plant		1,189,026		1,169,958
Less accumulated depreciation and amortization		496,841		479,557

Plant—net of accumulated depreciation and amortization		692,185		690,401
Construction work in progress		71,506		28,208

Net plant		763,691		718,609


Total	$	1,326,741	$	1,258,650

See accompanying notes to consolidated financial statements

- 2 -

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


	June 30,		December 31,
	2007		2006
	(Thousands of dollars)
Current liabilities
Short-term debt	$	93,956	$	38,900
Current maturities of long-term debt		3,096		3,125
Accounts payable		105,256		120,195
Accrued salaries and wages		23,950		28,653
Accrued federal and state income taxes		14,237		2,383
Other accrued taxes		8,688		11,509
Other accrued liabilities		14,167		10,495
Liabilities of discontinued operations		—		197

Total current liabilities		263,350		215,457

Pensions benefit liability		43,599		44,035
Other postretirement benefits liability		32,990		32,254
Other noncurrent liabilities		22,175		18,866

Deferred credits
Deferred income taxes		112,906		112,740
Deferred investment tax credit		7,612		8,181
Regulatory liabilities		64,155		63,875
Other		997		281

Total deferred credits		185,670		185,077

Capitalization

Long-term debt, net of current maturities		254,140		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 — 29,759,979 and 2006 — 29,521,770		148,800		147,609
Premium on common shares		105,525		99,223
Retained earnings		253,686		245,005
Accumulated other comprehensive income (loss)		51		(1,067	)

Total common equity		508,062		490,770
Total capitalization		778,957		762,961

Total	$	1,326,741	$	1,258,650

See accompanying notes to consolidated financial statements

- 3 -

Otter Tail Corporation

Consolidated Statements of Income

(not audited)


	Three months ended					Six months ended
	June 30,					June 30,
	2007		2006			2007		2006
	(In thousands, except share					(In thousands, except share
	and per share amounts)					and per share amounts)
Operating revenues
Electric	$	70,498	$	73,440		$	160,351	$	155,928
Nonelectric		235,346		206,464			446,614		381,783

Total operating revenues		305,844		279,904			606,965		537,711

Operating expenses
Production fuel — electric		14,077		11,456			30,502		26,262
Purchased power — electric system use		11,021		17,664			37,032		36,400
Electric operation and maintenance expenses		26,651		28,049			53,526		51,456
Cost of goods sold — nonelectric (excludes depreciation; included below)		176,973		156,363			341,632		288,757
Other nonelectric expenses		31,377		29,306			62,135		55,554
Depreciation and amortization		12,947		12,379			26,040		24,603
Property taxes — electric		2,527		2,551			5,053		5,169

Total operating expenses		275,573		257,768			555,920		488,201

Operating income		30,271		22,136			51,045		49,510

Other income		340		659			613		1,087
Interest charges		5,026		5,100			9,894		9,544

Income from continuing operations before income taxes		25,585		17,695			41,764		41,053
Income taxes — continuing operations		9,482		6,558			15,253		15,061

Net income from continuing operations		16,103		11,137			26,511		25,992
Discontinued operations
(Loss) income from discontinued operations net of taxes of $0; ($41); $0 and $28 for the respective periods		—		(79	)		—		26
Net gain on disposition of discontinued operations — net of taxes of $0; $224; $0 and $224 for the respective periods		—		336			—		336

Net income from discontinued operations		—		257			—		362

Net income		16,103		11,394			26,511		26,354
Preferred dividend requirements		184		184			368		368

Earnings available for common shares	$	15,919	$	11,210		$	26,143	$	25,986


Basic earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.54	$	0.37		$	0.88	$	0.87
Discontinued operations	$	—	$	0.01		$	—	$	0.01

	$	0.54	$	0.38		$	0.88	$	0.88

Diluted earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.53	$	0.37		$	0.88	$	0.86
Discontinued operations	$	—	$	0.01		$	—	$	0.01

	$	0.53	$	0.38		$	0.88	$	0.87

Average number of common shares outstanding — basic		29,685,745		29,392,963			29,594,499		29,359,474
Average number of common shares outstanding — diluted		29,940,868		29,766,040			29,843,953		29,751,718

Dividends per common share	$	0.2925	$	0.2875		$	0.5850	$	0.5750

See accompanying notes to consolidated financial statements

- 4 -

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)


	Six months ended
	June 30,
	2007			2006
	(Thousands of dollars)
Cash flows from operating activities
Net income	$	26,511		$	26,354
Adjustments to reconcile net income to net cash provided by operating activities:
Net gain from sale of discontinued operations		—			(336	)
Income from discontinued operations		—			(26	)
Depreciation and amortization		26,040			24,603
Deferred investment tax credit		(568	)		(573	)
Deferred income taxes		1,016			1,134
Change in deferred debits and other assets		2,492			383
Discretionary contribution to pension plan		(2,000	)		(4,000	)
Change in noncurrent liabilities and deferred credits		6,450			2,492
Allowance for equity (other) funds used during construction		—			(391	)
Change in derivatives net of regulatory deferral		(1,620	)		1,918
Stock compensation expense		1,097			1,320
Other — net		(390	)		629
Cash (used for) provided by current assets and current liabilities:
Change in receivables		(24,558	)		(14,827	)
Change in inventories		6,323			(18,004	)
Change in other current assets		(4,136	)		(25,648	)
Change in payables and other current liabilities		(28,190	)		(7,411	)
Change in interest and income taxes payable		11,858			10,107

Net cash provided by (used in) continuing operations		20,325			(2,276	)
Net cash provided by discontinued operations		—			926

Net cash provided by (used in) operating activities		20,325			(1,350	)


Cash flows from investing activities
Capital expenditures		(66,824	)		(33,949	)
Proceeds from disposal of noncurrent assets		7,043			1,048
Acquisitions—net of cash acquired		(6,750	)		—
Increases in other investments		(5,230	)		(1,171	)

Net cash used in investing activities — continuing operations		(71,761	)		(34,072	)
Net proceeds from the sales of discontinued operations		—			1,847

Net cash used in investing activities		(71,761	)		(32,225	)


Cash flows from financing activities
Change in checks written in excess of cash		4,649			4,186
Net short-term borrowings		55,056			43,032
Proceeds from issuance of common stock, net of issuance expenses		5,805			1,017
Payments for retirement of common stock		(295	)		(463	)
Proceeds from issuance of long-term debt		124			105
Debt issuance expenses		(123	)		(293	)
Payments for retirement of long-term debt		(1,543	)		(1,691	)
Dividends paid		(17,711	)		(17,298	)

Net cash provided by financing activities — continuing operations		45,962			28,595
Net cash provided by financing activities — discontinued operations		—			—

Net cash provided by financing activities		45,962			28,595

Effect of foreign exchange rate fluctuations on cash		(1,317	)		(450	)

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)	$	9,178		$	8,624
Income taxes	$	1,138		$	4,867

Cash paid during the year from discontinued operations for:
Interest	$	—		$	91
Income taxes	$	—		$	423

See accompanying notes to consolidated financial statements

- 5 -

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated results of operations for the periods presented. The consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes as of and for the years ended December 31, 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-month and six-month periods ended June 30, 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:


	June 30,			December 31,
(in thousands)	2007			2006

Costs incurred on uncompleted contracts	$	242,540		$	257,370
Less billings to date		(261,206	)		(284,273	)
Plus estimated earnings recognized		41,387			35,955

	$	22,721		$	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:


	June 30,			December 31,
(in thousands)	2007			2006

Costs and estimated earnings in excess of billings on uncompleted contracts	$	41,555		$	38,384
Billings in excess of costs and estimated earnings on uncompleted contracts		(18,834	)		(29,332	)

	$	22,721		$	9,052

Inventories

Inventories consist of the following:


	June 30,		December 31,
(in thousands)	2007		2006

Finished goods	$	40,534	$	46,477
Work in process		5,350		5,663
Raw material, fuel and supplies		52,907		50,862

	$	98,791	$	103,002

Goodwill and Other Intangible Assets

Goodwill increased $1,048,000 in the second quarter of 2007 as a result of the acquisition of Pro Engineering, LLC (Pro Engineering) by BTD Manufacturing, Inc. (BTD) in May 2007.

The following table summarizes the components of the Company’s intangible assets at June 30, 2007 and December 31, 2006:


	June 30, 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	$	2,637	$	1,984	$	653	$	2,198	$	1,813	$	385
Customer relationships		10,833		1,241		9,592		10,574		1,016		9,558
Other intangible assets including contracts		2,787		1,589		1,198		2,083		1,291		792

Total	$	16,257	$	4,814	$	11,443	$	14,855	$	4,120	$	10,735


Non-amortized intangible assets:
Brand/trade name	$	9,498	$	—	$	9,498	$	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 $687,000 for the six months ended June 30, 2007 compared to $555,000 for the six months ended June 30, 2006. The estimated annual amortization expense for these intangible assets for the next five years is $1,230,000 for 2007, $900,000 for 2008, $795,000 for 2009, $621,000 for 2010 and $516,000 for 2011.

Comprehensive Income


	Three months ended					Six months ended
	June 30,					June 30,
(in thousands)	2007		2006			2007			2006

Net income	$	16,103	$	11,394		$	26,511		$	26,354
Other comprehensive income (net-of-tax)
Foreign currency translation gain		942		618			1,046			564
Amortization of unrecognized losses and costs related to postretirement benefit programs		44		—			88			—
Unrealized gain (loss) on available-for-sale securities		2		(4	)		(17	)		(12	)

Total other comprehensive income		988		614			1,117			552

Total comprehensive income	$	17,091	$	12,008		$	27,628		$	26,906

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 No. 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 June 30, 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 U.S. federal income tax return and various state and foreign 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 June 30, 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.

On May 15, 2007 BTD acquired the assets of Pro Engineering for $4.8 million in cash. Pro Engineering specializes in providing metal parts stampings to customers in the Midwest. The acquisition of Pro Engineering by BTD provides expanded growth opportunities for both companies.

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

Below, are condensed balance sheets, at the dates of the respective business combinations, disclosing the preliminary allocation of the purchase price assigned to each major asset and liability category of Aviva and Pro Engineering:


			Pro
(in thousands)	Aviva		Engineering

Assets
Current assets	$	2,083	$	1,956
Goodwill		—		1,048
Other intangible assets		870		396
Fixed assets		—		1,600

Total assets	$	2,953	$	5,000


Liabilities
Current liabilities	$	988	$	215
Noncurrent liabilities		—		—

Total liabilities	$	988	$	215


Cash paid	$	1,965	$	4,785

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 various periods up to 15 years. Other intangible assets related to the Pro Engineering acquisition include $51,000 for a nonamortizable brand name and $345,000 in intangible assets being amortized over various periods up to 20 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						Six months ended
	June 30,						June 30,
	2007			2006			2007			2006

United States of America		95.9	%		97.2	%		96.2	%		97.1	%
Canada		2.1	%		1.7	%		1.6	%		1.6	%
All other countries (none greater than 1%)		2.0	%		1.1	%		2.2	%		1.3	%

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 and six months ended June 30, 2007 and 2006 and total assets by business segment as of June 30, 2007 and December 31, 2006 are presented in the following tables:

Operating Revenue


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2007			2006			2007			2006

Electric	$	70,572		$	73,518		$	160,552		$	156,102
Plastics		39,525			52,685			77,344			90,790
Manufacturing		104,786			81,631			191,011			149,888
Health services		32,452			32,833			65,415			64,909
Food ingredient processing		18,403			9,811			37,898			19,161
Other business operations		41,260			30,379			77,056			58,658
Intersegment eliminations		(1,154	)		(953	)		(2,311	)		(1,797	)

Total	$	305,844		$	279,904		$	606,965		$	537,711

Interest Expense


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2007			2006			2007			2006

Electric	$	2,388		$	2,553		$	4,891		$	5,130
Plastics		323			359			508			476
Manufacturing		2,180			1,841			3,984			3,212
Health services		255			261			460			470
Food ingredient processing		42			117			133			197
Other business operations		5,102			4,995			9,935			9,316
Intersegment eliminations		(5,264	)		(5,026	)		(10,017	)		(9,257	)

Total	$	5,026		$	5,100		$	9,894		$	9,544

Income Taxes


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2007			2006			2007			2006

Electric	$	2,679		$	1,748		$	5,905		$	6,985
Plastics		2,281			3,126			4,141			6,206
Manufacturing		3,660			2,772			5,205			4,298
Health services		528			393			1,222			660
Food ingredient processing		710			(321	)		949			(962	)
Other business operations		(376	)		(1,160	)		(2,169	)		(2,126	)

Total	$	9,482		$	6,558		$	15,253		$	15,061

Earnings Available for Common Shares from Continuing Operations


	Three months ended					Six months ended
	June 30,					June 30,
(in thousands)	2007		2006			2007			2006

Electric	$	4,892	$	3,349		$	10,630		$	12,623
Plastics		3,398		5,023			6,226			9,599
Manufacturing		5,335		4,160			7,874			6,405
Health services		708		520			1,656			841
Food ingredient processing		1,543		(1,416	)		1,992			(2,426	)
Other business operations*		43		(683	)		(2,235	)		(1,418	)

Total	$	15,919	$	10,953		$	26,143		$	25,624


*		Other business operations includes corporate general and administrative expenses net-of-tax of $1,349,000 and $1,748,000 for the three months ended June 30, 2007 and 2006, respectively, and $3,873,000 and $3,623,000 for the six months ended June 30, 2007 and 2006, respectively.

Total Assets


	June 30,		December 31,
(in thousands)	2007		2006

Electric	$	715,912	$	689,653
Plastics		89,115		80,666
Manufacturing		262,988		219,336
Health services		66,484		66,126
Food ingredient processing		94,369		94,462
Other business operations		97,873		108,118
Discontinued operations		—		289

Total	$	1,326,741	$	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 internal estimate of the net impact of MISO reallocating RSG charges in response to the FERC order on rehearing. In May 2007, MISO informed affected market participants of the impact of reallocating charges based on its interpretation of the FERC order on rehearing. Based on MISO’s interpretation of the order on rehearing, the Company estimates the reallocation of charges will not have a significant impact on earnings previously recognized by the Company. Accordingly, the Company revised its first quarter estimated charge of $1.7 million ($1.0 million net-of-tax) to zero in the second quarter of 2007.

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:


	June 30,			December 31,
(in thousands)	2007			2006

Regulatory assets:
Unrecognized transition obligation, prior service costs and actuarial losses on pension and other postretirement benefits	$	35,037		$	36,736
Accrued cost-of-energy revenue		6,986			10,735
Deferred income taxes		10,331			11,712
Reacquisition premiums		2,545			2,694
Deferred conservation program costs		420			1,036
MISO schedule 16 and 17 deferred administrative costs		709			541
Accumulated ARO accretion/depreciation adjustment		296			249
Plant acquisition costs		129			151

Total regulatory assets	$	56,453		$	63,854


Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	59,142		$	58,496
Deferred income taxes		4,865			5,228
Gain on sale of division office building		148			151

Total regulatory liabilities	$	64,155		$	63,875

Net regulatory asset (liability) position	$	(7,702	)	$	(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 15.1 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 2.9 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 six months of 2007 the Company issued 226,241 common shares for stock options exercised, 15,200 restricted common shares and 807 common shares for director’s compensation, 3,850 common shares for restricted stock unit awards that vested in April 2007 and 600 restricted common shares for employee compensation. During the same period, the Company retired 8,409 common shares for tax withholding purposes related to restricted shares that vested in March and April 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 three and six month periods ended June 30, 2007 and 2006:


Three months ended June 30,	Options Outstanding	Range of Exercise Prices

2007	—	N/A
2006	222,000	$28.67 — $31.34


Six months ended June 30,	Options Outstanding	Range of Exercise Prices

2007	—	N/A
2006	216,000	$29.74 — $31.34

Share-based Payments

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.

The Company has six share-based payment programs. As of June 30, 2007 the total remaining unrecognized compensation expense related to stock-based compensation was approximately $3.2 million (before income taxes), which will be amortized over a weighted-average period of 2.4 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three and six months ended June 30, 2007 and 2006 are presented in the table below:


	Three months ended				Six months ended
	June 30,				June 30,
(in thousands)	2007		2006		2007		2006

1999 Employee Stock Purchase Plan	$	64	$	60	$	127	$	120
Stock options granted under the Incentive Plan		22		68		90		136
Restricted stock granted to directors		96		170		247		241
Restricted stock granted to employees		208		151		412		442
Restricted stock units granted to employees		109		289		178		289
Stock performance awards granted to executive officers		221		395		441		535

Totals	$	720	$	1,133	$	1,495	$	1,763

Short-term and Long-term Borrowings

Short-term Debt— 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 increased 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 the Company’s electric operations. This line of credit expires on September 1, 2007 and is expected to be renewed. Borrowings under this line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. This line of credit contains terms that are substantially the same as those under the Company’s $150 million line of credit. As of June 30, 2007, $29.4 million was borrowed under the Credit Agreement.

Long-term Debt— In February 2007, we entered into a note purchase agreement with Cascade Investment L.L.C. (Cascade) pursuant to which the Company agreed to issue to Cascade, in a private placement transaction, $50 million aggregate principal amount of the Company’s senior notes due November 30, 2017. Cascade owned approximately 8.6% of the Company’s outstanding common stock as of March 31, 2007. The notes will bear interest at a rate of 5.778% per annum, subject to adjustment in the event certain ratings assigned to the Company’s long-term senior unsecured indebtedness are downgraded below specific levels prior to the closing of the note purchase. The terms of the note purchase agreement are substantially similar to the terms of the note purchase

agreement entered into in connection with the issuance of the Company’s $90 million 6.63% senior notes due December 1, 2011. The closing is expected to occur on December 3, 2007 subject to the satisfaction of certain conditions to closing, 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 The Company’s $50 million 6.375% senior debentures due December 1, 2007.

Class B Stock Options of Subsidiary

As of June 30, 2007 there were 958 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $743,000, of which 200 options were “in-the-money” with a combined exercise price of $30,000. In April 2007, 100 options were forfeited as a result of a voluntary termination.

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						Six months ended
	June 30,						June 30,
(in thousands)	2007			2006			2007			2006

Service cost—benefit earned during the period	$	1,263		$	1,210		$	2,526		$	2,420
Interest cost on projected benefit obligation		2,733			2,544			5,466			5,088
Expected return on assets		(3,223	)		(3,065	)		(6,446	)		(6,130	)
Amortization of prior-service cost		185			186			370			372
Amortization of net actuarial loss		309			378			618			756

Net periodic pension cost	$	1,267		$	1,253		$	2,534		$	2,506

The Company made a $2.0 million discretionary contribution to its pension plan in the six months ended June 30, 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				Six months ended
	June 30,				June 30,
(in thousands)	2007		2006		2007		2006

Service cost—benefit earned during the period	$	157	$	107	$	313	$	213
Interest cost on projected benefit obligation		362		325		725		651
Amortization of prior-service cost		17		18		34		36
Recognized net actuarial loss		135		118		270		236

Net periodic pension cost	$	671	$	568	$	1,342	$	1,136

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						Six months ended
	June 30,						June 30,
(in thousands)	2007			2006			2007			2006

Service cost—benefit earned during the period	$	315		$	334		$	630		$	668
Interest cost on projected benefit obligation		698			637			1,396			1,274
Amortization of transition obligation		187			187			374			374
Amortization of prior-service cost		(52	)		(76	)		(103	)		(152	)
Amortization of net actuarial loss		129			133			258			266
Effect of Medicare Part D expected subsidy		(410	)		(293	)		(820	)		(586	)

Net periodic postretirement benefit cost	$	867		$	922		$	1,735		$	1,844

Discontinued Operations

In June 2006, OTESCO, the Company’s energy services company, sold its natural 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 natural gas marketing operations be classified and reported separately as discontinued operations. The results of discontinued operations for the three and six months ended June 30, 2006 are summarized as follows:


	Three months ended			Six months ended
(in thousands)	June 30, 2006			June 30, 2006

Operating revenues	$	7,263		$	28,234
(Loss) income before income taxes		(120	)		54
Gain on Disposition — pretax		560			560
Income tax expense		183			252

At 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. These assets and liabilities were disposed of or settled in the second quarter of 2007.

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

RESULTS OF OPERATIONS

Comparison of the Three Months Ended June 30, 2007 and 2006

Consolidated operating revenues were $305.8 million for the three months ended June 30, 2007 compared with $279.9 million for the three months ended June 30, 2006. Operating income was $30.3 million for the three months ended June 30, 2007 compared with $22.1 million for the three months ended June 30, 2006. The Company recorded diluted earnings per share from continuing operations of $0.53 for the three months ended June 30, 2007 compared to $0.37 for the three months ended June 30, 2006 and total diluted earnings per share from continuing and discontinued operations of $0.53 for the three months ended June 30, 2007 compared to $0.38 for the three months ended June 30, 2006. Earnings from discontinued operations for the three months ended June 30, 2006 included $0.01 per share from a gain on the sale by OTESCO, the Company’s energy services company, of its natural gas marketing operations.

Following is a more detailed analysis of our operating results by business segment for the three and six month periods ended June 30, 2007 and 2006, followed by our outlook for the remainder of 2007 and a discussion of changes in our consolidated financial position during the six months ended June 30, 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 June 30, 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:


	Three months ended		Three months ended
(in thousands)	June 30, 2007		June 30, 2006

Operating revenues:
Electric	$	74	$	78
Nonelectric		1,080		875
Cost of goods sold		389		448
Other nonelectric expenses		765		505

Electric


	Three months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Retail sales revenues	$	55,501	$	61,805	$	(6,304	)		(10.2	)
Wholesale revenues		6,674		6,638		36			0.5
Net marked-to-market gain		3,429		1,260		2,169			172.1
Other revenues		4,968		3,815		1,153			30.2

Total operating revenues	$	70,572	$	73,518	$	(2,946	)		(4.0	)
Production fuel		14,077		11,456		2,621			22.9
Purchased power – system use		11,021		17,664		(6,643	)		(37.6	)
Other operation and maintenance expenses		26,651		28,049		(1,398	)		(5.0	)
Depreciation and amortization		6,250		6,447		(197	)		(3.1	)
Property taxes		2,527		2,551		(24	)		(0.9	)

Operating income	$	10,046	$	7,351	$	2,695			36.7

The main contributor to the decrease in retail revenues was a $9.0 million decrease in Fuel Clause Adjustment (FCA) revenues. The offsetting $2.7 million increase in retail revenues was due to a 2.6% increase in retail megawatt-hour (mwh) sales resulting from a 22.4% increase in heating degree days and a 9.1% increase in cooling degree days between the quarters. Industrial mwh sales increased 5.2% between the quarters mainly due to increased consumption by pipeline customers as higher oil prices have led to an increase in the volume of product being transported from Canada and the Williston basin.

Wholesale electric revenues from company-owned generation were $3.5 million for the quarter ended June 30, 2007 compared with $6.4 million for the quarter ended June 30, 2006. The decrease in wholesale revenues from company-owned generation resulted from a 43.1% decrease in wholesale mwh sales as more company-owned generation was used to serve retail load in the second quarter of 2007 compared with the second quarter of 2006. Advance purchases of electricity in anticipation of coal supply constraints at Big Stone and Hoot Lake plants in the second quarter of 2006 freed up more generation for wholesale sales when coal supplies improved in May 2006. Net revenues from energy trading activities, including net mark-to-market gains on forward energy contracts, were $6.6 million for the quarter ended June 30, 2007 compared with $1.5 million for the quarter ended June 30, 2006. The $5.1 million

increase in revenue from energy trading activities reflects a $4.2 million increase in profits from purchased power resold and net settlements of forward energy contracts, a $2.2 million increase in net mark-to-market gains on forward energy contracts and a $0.3 million increase in net profits from virtual transactions, offset by a $1.6 million decrease in profits related to the purchase and sale of financial transmission rights. In the first quarter of 2007, net gains from energy trading activities included a $1.7 million ($1.0 million net-of-tax) charge to earnings based on the estimated impact of a March 15, 2007 Federal Energy Regulatory Commission (FERC) order related to Midwest Independent Transmission Operator (MISO) revenue sufficiency guarantee (RSG) charges on virtual supply transactions going back to April 25, 2006. In May 2007, MISO informed affected market participants of the impact of reallocating charges based on its interpretation of the FERC order. Based on MISO’s interpretation of the order, the Company estimates the reallocation of charges will not have a significant impact on earnings previously recognized by the Company. Accordingly, the Company revised its first quarter estimated charge of $1.7 million (1.0 million net-of-tax) to zero in the second quarter of 2007.

The increase in other electric operating revenues for the three months ended June 30, 2007 compared to the three months ended June 30, 2006 was mainly due to an increase in payments for the use of the utility’s transmission facilities by other electric utility companies.

The increase in fuel costs for the three months ended June 30, 2007 compared with the three months ended June 30, 2006 reflects a 22.8% increase in mwhs generated combined with a 0.1% increase in the cost of fuel per mwh generated. Generation used for retail electric sales increased 41.1% while generation for wholesale electric sales decreased 43.1% between the quarters. The increase in mwhs generated is due to greater plant availability in the second quarter of 2007 compared with the second quarter of 2006. In the second quarter of 2006, Coyote Station was off-line for five weeks for scheduled maintenance and Big Stone Plant experienced a one-week maintenance shutdown.

The decrease in purchased power – system use (to serve retail customers) is due to a 46.1% decrease in mwhs purchased, partially offset by a 15.7% increase in the cost per mwh purchased. Advance purchases of electricity in anticipation of coal supply constraints at Big Stone and Hoot Lake plants and the scheduled five-week maintenance shutdown of Coyote Station in the second quarter of 2006 were the reasons for the higher level of mwh purchases for system use in the second quarter 2006 compared with the second quarter of 2007.

The decrease in other operation and maintenance expenses for the three months ended June 30, 2007 compared with the three months ended June 30, 2006 is due mainly to a reduction in contracted services and materials and supplies expenses related to the five-week scheduled maintenance shutdown at Coyote Station and the one-week maintenance shutdown of Big Stone Plant in the second quarter of 2006.

Plastics


	Three months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	39,525	$	52,685	$	(13,160	)		(25.0	)
Cost of goods sold		31,007		41,442		(10,435	)		(25.2	)
Operating expenses		1,753		2,058		(305	)		(14.8	)
Depreciation and amortization		764		678		86			12.7

Operating income	$	6,001	$	8,507	$	(2,506	)		(29.5	)

Operating revenues for the plastics segment decreased as result of a 16.1% decrease in the price per pound of pipe sold combined with a 10.6% decrease in pounds of pipe sold between the quarters. The decrease in pipe prices and cost of goods sold reflect the effect of a 21.0% decrease in polyvinyl chloride (PVC) resin prices between the periods. The decrease in plastics segment operating expenses reflects a decrease in sales and employee incentives directly related to the decreases in sales and operating income between the quarters. The increase in depreciation and amortization expense is the result of $5.5 million in capital expenditures in 2006, mainly for production equipment.

Manufacturing


	Three months ended
	June 30,						%
(in thousands)	2007		2006		Change		Change

Operating revenues	$	104,786	$	81,631	$	23,155		28.4
Cost of goods sold		81,188		63,256		17,932		28.3
Operating expenses		9,108		6,890		2,218		32.2
Depreciation and amortization		3,283		2,710		573		21.1

Operating income	$	11,207	$	8,775	$	2,432		27.7

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

	•		Revenues at DMI Industries, Inc. (DMI) increased $14.8 million as a result of ramped up production levels at Fort Erie compared with initial start-up levels beginning in May 2006.

	•		Revenues at ShoreMaster, Inc. (ShoreMaster) increased $5.9 million between the quarters due to increased production at the Galva Foam location and higher residential sales during the peak selling season. The Aviva Sports product line, acquired by ShoreMaster in February 2007, contributed $1.3 million to the increase in revenues.

	•		Revenues at BTD Manufacturing, Inc. (BTD) increased $2.1 million as a result of sales of higher priced products and services and the acquisition of Pro Engineering, LLC (Pro Engineering), a metal parts stamping business, in May 2007, which contributed $0.9 million in revenues in the second quarter of 2007. A 17.2% decrease in unit sales between the quarters at BTD’s other manufacturing facilities was offset by a 21.5% increase in the average price per unit sold.

	•		Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $0.3 million between the quarters as a result of a 6.5% increase in the average price per unit sold, which was mostly offset by a 4.6% decrease in the number of units sold between the quarters.

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

	•		DMI’s cost of goods sold increased $12.0 million between the quarters, including $9.5 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 ShoreMaster increased $3.5 million between the quarters as a result of increases in material and labor costs directly related to the increase in residential product sales and the acquisition of the Aviva Sports product line in February 2007.

	•		Cost of goods sold at BTD increased $1.5 million between the quarters as a result of increases in material and subcontractor costs and the acquisition of Pro Engineering in May 2007, offset by a decrease in costs at BTD’s other manufacturing facilities related to a decrease in unit sales between the quarters.

	•		Cost of goods sold at T.O. Plastics increased $0.9 million between the quarters, including $0.6 million in material cost increases and $0.3 million in increased manufacturing overhead costs.

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

	•		Operating expenses at DMI increased $0.9 million as a result of increases in labor and benefit, professional services and promotional expenses mainly related to operations at the Ft. Erie facilities which commenced in May 2006.

	•		ShoreMaster’s operating expenses increased $1.1 million as a result of increases in labor, benefit and professional service expenses mainly related to the acquisition of the Aviva Sports product line in February 2007.

	•		BTD’s operating expenses increased $0.2 million between the quarters as a result of increases in labor and professional service expenses.

	•		T.O. Plastics operating expenses increased by less than $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.

In January 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 that plant. The first phase became operational in April 2007. In May 2007, DMI announced plans to add a third wind tower manufacturing facility in Tulsa, Oklahoma. The plant is expected to be operational in 2008.

Health Services


	Three months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	32,452	$	32,833	$	(381	)		(1.2	)
Cost of goods sold		23,849		25,225		(1,376	)		(5.5	)
Operating expenses		6,111		5,568		543			9.8
Depreciation and amortization		1,021		879		142			16.2

Operating income	$	1,471	$	1,161	$	310			26.7

Health services operating revenues for the three months ended June 30, 2007 decreased slightly compared with the three months ended June 30, 2006. Revenues from equipment sales and servicing decreased $0.5 million between the quarters as a decrease in traditional dealership distribution of products was mostly offset by increases in manufacturer representative commissions on more manufacturer direct sales. Revenues from scanning and other related services increased $0.1 million between the quarters as a 2.7% decrease in the number of scans performed between the quarters was offset by a 2.6% increase in revenues per scan. The decrease in health services revenue was more than offset by the decrease in health services cost of goods sold due to the decrease in traditional dealership distribution of products. The $0.5 million increase in operating expenses is mainly due to higher labor and contracted service expenditures. The increase in depreciation and amortization expense is due to $4.7 million in capital expenditures in 2006.

Food Ingredient Processing


	Three months ended
	June 30,							%
(in thousands)	2007		2006			Change		Change

Operating revenues	$	18,403	$	9,811		$	8,592		87.6
Cost of goods sold		14,310		9,691			4,619		47.7
Operating expenses		790		790			—		—
Depreciation and amortization		999		948			51		5.4

Operating income (loss)	$	2,304	$	(1,618	)	$	3,922		242.4

The increase in food ingredient processing revenues reflects a 54.1% increase in pounds of product sold combined with a 21.7% increase in the price per pound sold. The increase in revenues was offset by a 47.7% increase in cost of goods sold. The cost per pound of product sold decreased 4.2% between the quarters. Approximately 8.0% of increased product sales are in Europe due, in part, to a poor European potato crop in 2006.

Other Business Operations


	Three months ended
	June 30,									%
(in thousands)	2007			2006			Change			Change

Operating revenues	$	41,260		$	30,379		$	10,881			35.8
Cost of goods sold		27,008			17,197			9,811			57.1
Operating expenses		14,380			14,505			(125	)		(0.9	)
Depreciation and amortization		630			717			(87	)		(12.1	)

Operating loss	$	(758	)	$	(2,040	)	$	1,282			62.8

Corporate general and administrative expenses included in the operating losses from other business operations were $3.1 million and $3.2 million for the three months ended June 30, 2007 and 2006, respectively. Net operating income from other business operations before corporate general and administrative expenses was $2.3 million and $1.2 million for the three months ended June 30, 2007 and 2006, respectively.

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

	•		Revenues at Foley Company increased $6.3 million in the second quarter of 2007 compared to the second quarter of 2006 due to an increase in the volume of jobs in progress between the quarters.

	•		Revenues at Midwest Construction Services, Inc. (MCS) increased $4.1 million between the quarters as a result of an increase in volume of jobs in progress.

	•		Revenues at E.W. Wylie Corporation (Wylie) increased $0.3 million between the quarters mainly due to a 2.4% increase in total miles driven by company-operated and owner-operated trucks. Miles driven by company-operated trucks increased 7.6% while miles driven by owner-operated trucks decreased 5.2% between the quarters.

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

	•		Foley Company’s cost of goods sold increased $6.5 million mainly in the areas of subcontractor and labor costs as a result of the increased volume of work performed between the quarters.

	•		Cost of goods sold at MCS increased $3.3 million mainly due to increases in material, labor and subcontractor costs related to the increase in volume of work performed between the quarters.

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

	•		Wylie’s operating expenses increased by $0.3 million between the quarters mainly as a result of increases in labor and fuel expenses related to the increase in miles driven by company-operated trucks between the periods. Wylie’s depreciation expense decreased $0.1 million between the quarters as a result of leasing rather than buying replacement equipment.

	•		Foley Company’s operating expenses decreased $0.1 million between the quarters as a result of decreases in compensation costs.

	•		At MCS, general and administrative expenses decreased $0.1 million between the quarters.

Income Taxes – Continuing Operations

The $2.9 million (44.6%) increase in income taxes — continuing operations between the quarters is directly related to a $7.9 million (44.6%) increase in income from continuing operations before income taxes for the three months ended June 30, 2007 compared with the three months ended June 30, 2006. The effective tax rate for continuing operations was 37.1% for both the three month periods ended June 30, 2007 and 2006.

Discontinued Operations

In June 2006, OTESCO, the Company’s energy services company, sold its natural 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 natural gas marketing operations be classified and reported separately as discontinued operations.

The results of discontinued operations for the three months ended June 30, 2006 are summarized as follows:


	Three months ended
(in thousands)	June 30, 2006

Loss before income taxes	$	(120	)
Gain on disposition – pretax		560
Income tax expense		183

Net income	$	257

Comparison of the Six Months Ended June 30, 2007 and 2006

Consolidated operating revenues were $607.0 million for the six months ended June 30, 2007 compared with $537.7 million for the six months ended June 30, 2006. Operating income was $51.0 million for the six months ended June 30, 2007 compared with $49.5 million for the six months ended June 30, 2006. The Company recorded diluted earnings per share from continuing operations of $0.88 for the six months ended June 30, 2007 compared to $0.86 for the six months ended June 30, 2006 and total diluted earnings per share from continuing and discontinued operations of $0.88 for the six months ended June 30, 2007 compared to $0.87 for the six months ended June 30, 2006. Earnings from discontinued operations for the six months ended June 30, 2006 included $0.01 per share from a gain on the sale of OTESCO’s natural gas marketing operations.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the six month periods ended June 30, 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:


	Six months ended		Six months ended
(in thousands)	June 30, 2007		June 30, 2006

Operating revenues:
Electric	$	201	$	174
Nonelectric		2,110		1,623
Cost of goods sold		756		768
Other nonelectric expenses		1,555		1,029

Electric


	Six months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Retail sales revenues	$	136,677	$	135,164	$	1,513			1.1
Wholesale revenues		10,908		12,296		(1,388	)		(11.3	)
Net marked-to-market gain		3,398		351		3,047			868.1
Other revenues		9,569		8,291		1,278			15.4

Total operating revenues	$	160,552	$	156,102	$	4,450			2.9
Production fuel		30,502		26,262		4,240			16.1
Purchased power – system use		37,032		36,400		632			1.7
Other operation and maintenance expenses		53,526		51,456		2,070			4.0
Depreciation and amortization		12,920		12,804		116			0.9
Property taxes		5,053		5,169		(116	)		(2.2	)

Operating income	$	21,519	$	24,011	$	(2,492	)		(10.4	)

The main contributor to the increase in retail revenues was a 3.3% increase in retail mwh sales in the six months ended June 30, 2007 compared with the six months ended June 30, 2006, primarily due to a 12.6% increase in heating degree days and a 9.1% increase in cooling degree days between the periods. The impact of the 3.3% increase in retail mwh sales on revenues was partially offset by a $2.7 million decrease in FCA revenues between the periods. The decrease in FCA revenues includes changes in the Minnesota FCA true-up from $4.2 million receivable in the first six months of 2006 to $0.7 million refundable in the first six months of 2007, and a February 2006 reversal of a $1.9 million refund provision established in December 2005, offset by a $4.1 million increase in FCA revenues for recovery of increased fuel and purchased power costs between the periods.

Wholesale electric revenues from company-owned generation were $9.5 million for the six months ended June 30, 2007 compared with $11.8 million for the six months ended June 30, 2006. The decrease in wholesale revenues from company-owned generation resulted from a 47.6% decrease in wholesale mwh sales as more company-owned generation was used to serve retail load in the first six months of 2007 compared with the same period in 2006. Advance purchases of electricity in anticipation of coal supply constraints at Big Stone and Hoot Lake plants in the second quarter of 2006 freed up more generation for wholesale sales when coal supplies improved in May 2006. Net revenues from energy trading activities, including net mark-to-market gains on forward energy contracts, were $4.8 million for the six months ended June 30, 2007 compared with $0.9 million for the six months ended June 30, 2006. The $3.9 million increase in revenue from energy trading activities reflects a $4.5 million increase in profits from purchased power resold and net settlements of forward energy contracts and a $3.0 million increase in net mark-to-market gains on forward energy contracts, offset by a $2.6 million decrease in net profits from virtual transactions and a $1.0 million decrease in profits related to the purchase and sale of financial transmission rights.

The increase in other electric operating revenues for the six months ended June 30, 2007 compared to the six months ended June 30, 2006 was mainly due to an increase in payments for the use of the utility’s transmission facilities by other electric utility companies.

The increase in fuel costs for the six months ended June 30, 2007 compared with the six months ended June 30, 2006 reflects a 6.0% increase in mwhs generated combined with a 9.6% increase in the cost of fuel per mwh generated. Generation used for retail electric sales increased 17.4% while generation for wholesale electric sales decreased 47.6% between the periods. The increase in mwhs generated is due to greater plant availability in the first six months of 2007 compared with the first six months of 2006. In the second quarter of 2006, Coyote Station was off-line for five weeks of scheduled maintenance and Big Stone Plant experienced a one-week maintenance shutdown.

The increase in purchased power – system use (to serve retail customers) is due to a 27.9% increase in the cost per mwh purchased partially offset by a 20.5% decrease in mwhs purchased for system use. Advance purchases of electricity in anticipation of coal supply constraints at Big Stone and Hoot Lake plants and the scheduled five-week maintenance shutdown of Coyote Station in the second quarter of 2006 were the reasons for the higher level of mwh purchases for system use in the first six months of 2006 compared with the first six months of 2007.

The increase in other operation and maintenance expenses for the six months ended June 30, 2007 compared with the six months ended June 30, 2006 reflects increased labor costs related to wage and salary increases averaging approximately 3.8% between the periods.

Plastics


	Six months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	77,344	$	90,790	$	(13,446	)		(14.8	)
Cost of goods sold		61,655		69,622		(7,967	)		(11.4	)
Operating expenses		3,292		3,506		(214	)		(6.1	)
Depreciation and amortization		1,529		1,408		121			8.6

Operating income	$	10,868	$	16,254	$	(5,386	)		(33.1	)

Operating revenues for the plastics segment decreased as result of a 20.6% decrease in the price per pound of pipe sold, partially offset by a 7.6% increase in pounds of pipe sold between the periods. The decrease in pipe prices and cost of goods sold reflects the effect of a 21.7% decrease in PVC resin prices between the periods. The decrease in plastics segment operating expenses reflects a decrease in sales and employee incentives directly related to the decreases in sales and operating income between the periods. The increase in depreciation and amortization expense is the result of $5.5 million in capital expenditures in 2006, mainly for production equipment.

Manufacturing


	Six months ended
	June 30,						%
(in thousands)	2007		2006		Change		Change

Operating revenues	$	191,011	$	149,888	$	41,123		27.4
Cost of goods sold		150,434		117,655		32,779		27.9
Operating expenses		17,039		13,105		3,934		30.0
Depreciation and amortization		6,393		5,279		1,114		21.1

Operating income	$	17,145	$	13,849	$	3,296		23.8

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

	•		Revenues at DMI increased $31.9 million as a result of ramped up production levels at Fort Erie compared with initial start-up levels beginning in May 2006.

	•		Revenues at ShoreMaster increased $6.3 million between the periods due to increased production at the Galva Foam location and higher residential sales during the peak selling season. The Aviva Sports product line, acquired by ShoreMaster in February 2007, contributed $2.3 million to the increase in revenues.

	•		Revenues at T.O. Plastics increased $1.5 million between the periods as a result of a 21.2% increase in the average price per unit sold, partially offset by a 12.6% decrease in the number of units sold between the periods.

•

Revenues at BTD increased $1.4 million mainly as a result of the May 2007 acquisition of Pro Engineering, which contributed $0.9 million to 2007 revenues. A 13.7% decrease in unit sales between the periods at BTD’s other manufacturing facilities was offset by a 14.1% 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 $26.2 million between the periods, including $19.5 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 ShoreMaster increased $3.6 million between the periods as a result of increases in material and labor costs directly related to the increase in residential product sales and the acquisition of the Aviva Sports product line in February 2007.

	•		Cost of goods sold at T.O. Plastics increased $2.0 million, including $1.1 million in material cost increases and $0.8 million in increased manufacturing overhead costs.

	•		Cost of goods sold at BTD increased $1.0 million between the periods as a result of increases in material and subcontractor costs and the acquisition of Pro Engineering in May 2007, offset by a decrease in costs at BTD’s other manufacturing facilities related to a decrease in unit sales between the periods.

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

	•		Operating expenses at DMI increased $1.5 million as a result of increases in labor and benefit, professional services and promotional expenses mainly related to operations at the Ft. Erie facilities which commenced in May 2006.

	•		ShoreMaster’s operating expenses increased $1.6 million as a result of increases in labor, benefit and professional service expenses mainly related to the acquisition of the Aviva Sports product line in February 2007.

	•		BTD’s operating expenses increased $0.5 million between the periods as a result of increases in labor and professional service expenses.

	•		T.O. Plastics operating expenses increased by less than $0.3 million between the periods mainly as a result of increases in labor and contracted service expenditures.

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

Health Services


	Six months ended
	June 30,							%
(in thousands)	2007		2006		Change			Change

Operating revenues	$	65,415	$	64,909	$	506			0.8
Cost of goods sold		48,232		50,047		(1,815	)		(3.6	)
Operating expenses		11,917		11,082		835			7.5
Depreciation and amortization		1,983		1,836		147			8.0

Operating income	$	3,283	$	1,944	$	1,339			68.9

Health services operating revenues for the six months ended June 30, 2007 increased slightly compared with the six months ended June 30, 2006 as increases in equipment sales and increases in manufacturer representative commissions on manufacturer direct sales were mostly offset by a decrease in traditional dealership distribution of products. An 8.3% decrease in the number of scans performed between the periods was offset by an 8.0% increase in revenues per scan. The decrease in health services cost of goods sold is directly related to a decrease in traditional dealership distribution of products. The $0.8 million increase in operating expenses is mainly due to higher labor and contracted service expenditures. The increase in depreciation and amortization expense is due to $4.7 million in capital expenditures in 2006.

Food Ingredient Processing


	Six months ended
	June 30,							%
(in thousands)	2007		2006			Change		Change

Operating revenues	$	37,898	$	19,161		$	18,737		97.8
Cost of goods sold		31,303		19,010			12,293		64.7
Operating expenses		1,542		1,475			67		4.5
Depreciation and amortization		1,968		1,866			102		5.5

Operating income (loss)	$	3,085	$	(3,190	)	$	6,275		196.7

The increase in food ingredient processing revenues reflects a 62.2% increase in pounds of product sold combined with a 21.9% increase in the price per pound sold. The increase in revenues was only partially offset by a 64.7% increase in cost of goods sold. The cost per pound of product sold increased 1.5% between the periods. Approximately 8.0% of increased product sales are in Europe due, in part, to a poor European potato crop in 2006.

Other Business Operations


	Six months ended
	June 30,									%
(in thousands)	2007			2006			Change			Change

Operating revenues	$	77,056		$	58,658		$	18,398			31.4
Cost of goods sold		50,764			33,191			17,573			52.9
Operating expenses		29,900			27,415			2,485			9.1
Depreciation and amortization		1,247			1,410			(163	)		(11.6	)

Operating loss	$	(4,855	)	$	(3,358	)	$	(1,497	)		(44.6	)

Corporate general and administrative expenses included in the operating losses from other business operations were $7.3 million and $6.3 million for the six months ended June 30, 2007 and 2006, respectively. Net operating income from other business operations before corporate general and administrative expenses was $2.4 million and $3.0 million for the six months ended June 30, 2007 and 2006, respectively.

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

	•		Revenues at Foley Company increased $9.7 million in the first six months of 2007 compared to the first six months of 2006 due to an increase in the volume of jobs in progress between the periods.

	•		Revenues at MCS increased $7.7 million between the periods as a result of an increase in volume of jobs in progress.

	•		Revenues at Wylie increased $0.5 million between the periods mainly due to a 4.8% increase in miles driven by owner-operated and company-operated trucks. Miles driven by company-operated trucks increased 5.6% and miles driven by owner-operated trucks increased 3.5% between the periods.

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

	•		Foley Company’s cost of goods sold increased $10.3 million mainly in the areas of subcontractor and labor costs as a result of the increased volume of work performed between the periods.

	•		Cost of goods sold at MCS increased $7.3 million mainly due to increases in material, subcontractor and labor costs related to the increase in volume of jobs in progress between the periods.

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

	•		Corporate operating expenses in this segment increased $1.4 million as a result of higher labor, insurance and equipment rental costs.

	•		Wylie’s operating expenses increased $0.8 million between the periods, mainly as a result of increases in fuel, equipment rental and labor expenses. Wylie’s depreciation expense decreased $0.2 million between the periods as a result of leasing rather than buying replacement equipment.

	•		Foley Company’s operating expenses increased $0.3 million between the periods.

Income Taxes – Continuing Operations

The $0.2 million (1.3%) increase in income taxes — continuing operations between the periods is primarily the result of a $0.7 million (1.7%) increase in income from continuing operations before income taxes for the six months ended June 30, 2007 compared with the six months ended June 30, 2006. The effective tax rate for continuing operations for the six months ended June 30, 2007 was 36.5% compared to 36.7% for the six months ended June 30, 2006.

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 six months ended June 30, 2006 are summarized as follows:


	Six months ended
(in thousands)	June 30, 2006

Income before income taxes	$	54
Gain on disposition – pretax		560
Income tax expense		252

Net income	$	362

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 $24.0 million in our electric segment in 2007, an increase from prior guidance of $19.0 million to $22.5 million.

	•		We expect our plastics segment’s performance to be in the range of $6.0 million to $8.5 million in 2007, an increase from prior guidance of $5.5 million to $8.0 million, because of stronger than expected performance in the first six months of 2007.

	•		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 production 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 $2.5 million to $4.5 million in 2007, an increase from prior guidance of $2.0 million to $4.0 million.

	•		We expect our other business operations segment to have lower earnings in 2007 compared with 2006 due to an expected return to more normal 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 fund a portion of planned capital expenditures 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, the construction of the Langdon Wind Project discussed below, other wind and transmission projects, 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 June 30, 2007, $64.6 million of the Company’s $150 million line of credit was in use and $15.7 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 increased 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 and is expected to be renewed. 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 June 30, 2007, $29.4 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 owned approximately 8.6% of our outstanding common stock as of March 31, 2007. 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. We have the right to terminate the note purchase agreement by giving at least 30 days’ prior written notice to Cascade and paying a termination fee of $1 million. The proceeds of this financing will be used to redeem our $50 million 6.375% senior debentures due December 1, 2007.

Our lines of credit, $90 million 6.63% senior notes and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under our financing agreements as of June 30, 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 June 30, 2007 were:


	Moody’s
	Investors		Standard
	Service		& Poor’s

Senior unsecured debt		A3	BBB+
Preferred stock	Baa2		BBB-
Outlook	Stable		Stable

In July 2007, Moody’s changed its outlook on Otter Tail Corporation from stable to negative, citing risks of recovery associated with planned capital expenditures in the electric segment as a major factor contributing to its outlook change. 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 provided by operating activities of continuing operations was $20.3 million for the six months ended June 30, 2007 compared with cash used in operating activities of continuing operations of $2.3 million for the six months ended June 30, 2006. The $22.6 million increase in cash provided by operating activities of continuing operations

mainly reflects a $17.1 million decrease in cash used for working capital items from $55.8 million in the first six months of 2006 to $38.7 million in the first six months of 2007. The increase in cash provided by operating activities of continuing operations also includes increases in noncurrent liabilities and deferred credits of $4.0 million and a $2.0 million decrease in discretionary contributions to the Company’s funded pension plan between the periods.

Major uses of funds for working capital items in the first six months of 2007 were a decrease in payables and other current liabilities of $28.2 million, an increase in receivables of $24.6 million and an increase in other current assets of $4.1 million, offset by an increase in interest and income taxes payable of $11.9 million and a decrease in inventories of $6.3 million. The decrease in payables and other current liabilities includes a $15.1 million reduction in DMI’s billings in excess of costs and trade accounts payable, a $4.9 million reduction in accrued bonuses across all companies and reductions in trade accounts payable of $3.0 million in the health services segment, $2.2 million at our electric utility company, $1.6 million in our plastics segment, and $1.3 million at Foley Company. The $24.6 million increase in receivables includes $14.6 million at DMI related to increased sales of wind towers and $10.6 million from our plastics segment related to increased sales in the second quarter of 2007 compared to the fourth quarter of 2006. The increase in other current assets includes increases in costs in excess of billings of $2.9 million 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, and $1.4 million at MCS related to a normal seasonal increase in construction activity in the North Central region of the United States. The increase in interest and income taxes payable reflects an $11.9 million increase in income taxes payable as a result of the timing of estimated tax payments, which is normal in the first half of our fiscal year. The decrease in inventories reflects reductions in finished goods inventory of $2.4 million at IPH, $2.0 million at our plastic pipe companies and $1.7 million at T.O. Plastics.

Net cash used in investing activities of continuing operations was $71.8 million for the six months ended June 30, 2007 compared with $34.1 million for the six months ended June 30, 2006. Cash used for capital expenditures increased by $32.9 million between the periods. Cash used for capital expenditures at the electric utility increased by $24.8 million between the periods mainly related to initiation of the Langdon Wind Project in the second quarter of 2007 and replacement of the flue-gas treatment system at Big Stone Plant. Cash used for capital expenditures at DMI increased $8.6 million between the periods mainly due to the purchase of property for a new wind tower manufacturing facility to be constructed in Tulsa, Oklahoma. The Company completed two acquisitions during the first six months of 2007 for a combined purchase price of $6.8 million. The Company made no acquisitions in 2006. The net increase in proceeds from the disposal of noncurrent assets and cash used for other investments of $1.9 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 six months of 2007.

Net cash provided by financing activities was $46.0 million for the six months ended June 30, 2007 compared with net cash provided by financing activities of $28.6 million for the six months ended June 30, 2006. Cash proceeds from short-term borrowings and checks written in excess of cash increased by $12.5 million between the periods mainly to fund the increase in capital expenditures. Proceeds from the issuance of common stock increased $4.8 million due to an increase in the number of stock options exercised in the first six months of 2007 compared with the first six months of 2006. In the first six months of 2007 the Company issued 226,241 common shares for stock options exercised, 15,200 restricted common shares and 807 common shares for director’s compensation, 3,850 common shares for restricted stock unit awards that vested in April 2007 and 600 restricted common shares for employee compensation. During the same period, the Company retired 8,409 common shares for tax withholding purposes related to restricted shares that vested in March and April 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:


			2007-
(in millions)	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. This estimate of our portion of the costs assumes an in service date in 2012 with the best available information. Any change in schedule for the project could increase our portion of the costs.

There were changes in our contractual obligations in the first six months 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 “other 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. Also, in August 2007, the Company entered into a three-year agreement to lease new rail cars for the shipment of coal to Hoot Lake Plant. The new lease will result in an increase in “operating lease obligations” of $0.4 million in 2007, $2.1 million in 2008 and 2009 combined and $0.7 million in 2010.

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 six months ended June 30, 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 continue to 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 costs currently included in the Fuel Clause Adjustment (FCA) in retail rates may be excluded from recovery through the FCA but may be subject to recovery through rates established in a general rate case. Further, all, or portions of, gross margins on asset-based wholesale electric sales may become subject to refund through the FCA as a result of 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 affected 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 $7.25 million in costs related to the planned construction of a second electric generating unit at its Big Stone Plant site as of June 30, 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 and changes in our debt rating 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 June 30, 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 33% of IPH sales are outside the United States and the Canadian operations of IPH pays its operating expenses in Canadian dollars.

The majority of our consolidated long-term debt has fixed interest rates. The interest rate on variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of June 30, 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 June 30, 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 June 30, 2007 the electric utility had recognized, on a pretax basis, $1,452,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties or brokers used by the electric utility’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange. Prices are benchmarked to regional hub prices as published in Megawatt Daily and forward price curves and indices acquired from a third party price forecasting service. Of the forward energy contracts that are marked to market as of June 30, 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 June 30, 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 June 30, 2007 and the change in our consolidated balance sheet position from December 31, 2006 to June 30, 2007:


(in thousands)	June 30, 2007

Current asset – marked-to-market gain	$	7,822
Current liability – marked-to-market loss		(6,370	)

Net fair value of marked-to-market gas contracts	$	1,452


	Year-to-date
(in thousands)	June 30, 2007

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

Net fair value of contracts entered into in 2006 at end of period		—
Changes in fair value of open contracts entered into in 2007		1,452

Net fair value end of period	$	1,452

The $1,452,000 recognized but unrealized net gains on the forward energy purchases and sales marked to market on June 30, 2007 is expected to be realized on physical settlement as scheduled over the following quarters in the amounts listed:


	3rd Quarter		4th Quarter		1st Quarter
(in thousands)	2007		2007		2008		Total

Net gain	$	902	$	335	$	215	$	1,452

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 June 30, 2007 was $2.4 million. As of June 30, 2007 we had a net credit risk exposure of $8.6 million from 14 counterparties with investment grade credit ratings. We had no exposure at June 30, 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 $8.6 million credit risk exposure includes net amounts due to the electric utility on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after June 30, 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 June 30, 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 June 30, 2007.

During the fiscal quarter ended June 30, 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		Average price paid
Calendar Month	shares purchased		per share

April 2007		8,345	$	35.09
May 2007		—		—
June 2007		—		—

Total		8,345

Item 4. Submission of Matters to a Vote of Security Holders

The Annual Meeting of Shareholders of the Company was held on April 9, 2007, to consider and act upon the following matters: (1) to elect three nominees to the Board of Directors with terms expiring in 2010, and (2) to ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2007. All nominees for directors as listed in the proxy statement were elected. The names of each other director whose term of office continued after the meeting are as follows: Karen M. Bohn, Dennis R. Emmen, Edward J. McIntyre, Nathan I. Partain and Joyce Nelson Schuette. On April 9, 2007, the Board of Directors of the Company elected John D. Erickson, the Company’s President and Chief Executive Officer, to serve as a member of the Board of Directors. Mr. Erickson filled the vacancy created by the resignation of Kenneth L. Nelson, which was effective at the conclusion of the Company’s 2007 Annual Meeting of Shareholders. Mr. Erickson will serve for the remainder of that term, which expires at the time of the Company’s 2008 Annual Meeting of Shareholders.

The voting results are as follows:


	Shares		Shares Voted		Broker
Election of Directors	Voted For		Withheld Authority		Non-Votes
Arvid R. Liebe		24,715,694		508,521		-0-
John C. MacFarlane		24,754,279		469,936		-0-
Gary J. Spies		24,742,644		481,571		-0-

Voted

Broker

Voted For

Against

Abstain

Non-Votes

Ratification of Deloitte & Touche LLP as Independent Registered Public Accounting Firm

24,731,495

290,604

202,116

-0-

Item 6. Exhibits

	4.1		First Amendment to Credit Agreement dated as of April 13, 2007 between Otter Tail Corporation dba Otter Tail Power Company and U.S. Bank National Association (amending the Credit Agreement dated as of September 1, 2006 between Otter Tail Corporation dba Otter Tail Power Company and U.S. Bank National Association) (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed April 18, 2007)

	10.1		Amendment No. 4 to Participation Agreement, dated as of June 8, 2007, by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners, amending the Participation Agreement, dated as of June 30, 2005, by and among the Owners (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed June 19, 2007)

	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: August 7, 2007

EXHIBIT INDEX


Exhibit Number		Description

	4.1	First Amendment to Credit Agreement dated as of April 13, 2007 between Otter Tail Corporation dba Otter Tail Power Company and U.S. Bank National Association (amending the Credit Agreement dated as of September 1, 2006 between Otter Tail Corporation dba Otter Tail Power Company and U.S. Bank National Association) (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed April 18, 2007)

	10.1	Amendment No. 4 to Participation Agreement, dated as of June 8, 2007, by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners, amending the Participation Agreement, dated as of June 30, 2005, by and among the Owners (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed June 19, 2007)

	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


	Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets – June 30, 2007 and December 31, 2006 (not audited)		2 & 3
Consolidated Statements of Income — Three and Six Months Ended June 30, 2007 and 2006 (not audited)		4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2007 and 2006 (not audited)		5
Notes to Consolidated Financial Statements (not audited)		6-17
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17-36
Item 3. Quantitative and Qualitative Disclosures About Market Risk		37-38
Item 4. Controls and Procedures		39
Part II. Other Information
Item 1. Legal Proceedings		39
Item 1A. Risk Factors		39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 4. Submission of Matters to a Vote of Security Holders		40
Item 6. Exhibits		41
Signatures		41
302 Certification of Chief Executive Officer
302 Certification of Chief Financial Officer
906 Certification of Chief Executive Officer
906 Certification of Chief Financial Officer


/s/ John D. Erickson John D. Erickson
President and Chief Executive Officer


/s/ Kevin G. Moug Kevin G. Moug
Chief Financial Officer and Treasurer

	1.		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2.		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


		/s/ John D. Erickson John D. Erickson
		President and Chief Executive Officer
		August 7, 2007