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, 2008

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

For the transition period from                     to                     

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

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

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

866-410-8780

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

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:

 

 

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets — June 30, 2008 and December 31, 2007 (not audited)			2 & 3
Consolidated Statements of Income — Three and Six Months Ended June 30, 2008 and 2007 (not audited)			4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2008 and 2007 (not audited)			5
Notes to Consolidated Financial Statements (not audited)			6-26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26-46
Item 3. Quantitative and Qualitative Disclosures About Market Risk			46-49
Item 4. Controls and Procedures			49
Part II. Other Information
Item 1. Legal Proceedings			49-50
Item 1A. Risk Factors			50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			50
Item 4. Submission of Matters to a Vote of Securities Holders			51
Item 6. Exhibits			51
Signatures			51
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

(not audited)

		June 30,				December 31,
		2008				2007
		(Thousands of dollars)
Current Assets
Cash and Cash Equivalents		$	—			$	39,824
Accounts Receivable:
Trade—Net			154,456				151,446
Other			17,527				14,934
Inventories			112,233				97,214
Deferred Income Taxes			7,216				7,200
Accrued Utility and Cost-of-Energy Revenues			13,402				32,501
Costs and Estimated Earnings in Excess of Billings			70,578				42,234
Other			30,531				15,299
Total Current Assets			405,943				400,652
Investments			9,200				10,057
Other Assets			25,139				24,500
Goodwill			107,228				99,242
Other Intangibles—Net			36,470				20,456
Deferred Debits
Unamortized Debt Expense and Reacquisition Premiums			6,537				6,986
Regulatory Assets and Other Deferred Debits			40,157				38,837
Total Deferred Debits			46,694				45,823
Plant
Electric Plant in Service			1,051,644				1,028,917
Nonelectric Operations			306,755				257,590
Total Plant			1,358,399				1,286,507
Less Accumulated Depreciation and Amortization			528,725				506,744
Plant—Net of Accumulated Depreciation and Amortization			829,674				779,763
Construction Work in Progress			96,806				74,261
Net Plant			926,480				854,024
Total		$	1,557,154			$	1,454,754

See accompanying notes to consolidated financial statements

Otter Tail Corporation

Consolidated Balance Sheets
(not audited)

		June 30,				December 31,
		2008				2007
		(Thousands of dollars)
Current Liabilities
Short-Term Debt		$	186,600			$	95,000
Current Maturities of Long-Term Debt			3,376				3,004
Accounts Payable			148,317				141,390
Accrued Salaries and Wages			23,997				29,283
Accrued Taxes			9,194				11,409
Other Accrued Liabilities			20,566				13,873
Total Current Liabilities			392,050				293,959
Pensions Benefit Liability			40,637				39,429
Other Postretirement Benefits Liability			30,979				30,488
Other Noncurrent Liabilities			21,448				23,228
Deferred Credits
Deferred Income Taxes			109,099				105,813
Deferred Tax Credits			17,790				16,761
Regulatory Liabilities			63,439				62,705
Other			316				275
Total Deferred Credits			190,644				185,554
Capitalization
Long-Term Debt, Net of Current Maturities			341,630				342,694
Class B Stock Options of Subsidiary			1,255				1,255
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value; Outstanding 2008 and 2007 — 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 2008 — 30,124,709 and 2007 — 29,849,789			150,624				149,249
Premium on Common Shares			114,669				108,885
Retained Earnings			256,867				263,332
Accumulated Other Comprehensive Income			851				1,181
Total Common Equity			523,011				522,647
Total Capitalization			881,396				882,096
Total		$	1,557,154			$	1,454,754

See accompanying notes to consolidated financial statements

Otter Tail Corporation

(not audited)

		Three months ended								Six months ended
		June 30,									June 30,
		2008				2007				2008				2007
		(In thousands, except share								(In thousands, except share
		and per share amounts)								and per share amounts)
Operating Revenues
Electric		$	68,577			$	70,498			$	166,083			$	160,351
Nonelectric			255,023				235,346				457,754				446,614
Total Operating Revenues			323,600				305,844				623,837				606,965
Operating Expenses
Production Fuel — Electric			14,808				14,077				34,712				30,502
Purchased Power — Electric System Use			10,156				11,021				29,142				37,032
Electric Operation and Maintenance Expenses			27,757				26,651				54,500				53,526
Cost of Goods Sold — Nonelectric (depreciation included below)			204,235				176,973				369,458				341,632
Other Nonelectric Expenses			36,242				31,377				70,989				62,135
Plant Closure Costs			1,412				—				1,412				—
Depreciation and Amortization			16,124				12,947				31,037				26,040
Property Taxes — Electric			2,563				2,527				5,187				5,053
Total Operating Expenses			313,297				275,573				596,437				555,920
Operating Income			10,303				30,271				27,400				51,045
Other Income			626				340				1,588				613
Interest Charges			7,043				5,026				13,754				9,894
Income Before Income Taxes			3,886				25,585				15,234				41,764
Income Taxes			369				9,482				3,487				15,253
Net Income			3,517				16,103				11,747				26,511
Preferred Dividend Requirements			184				184				368				368
Earnings Available for Common Shares		$	3,333			$	15,919			$	11,379			$	26,143
Earnings Per Common Share:
Basic		$	0.11			$	0.54			$	0.38			$	0.88
Diluted		$	0.11			$	0.53			$	0.38			$	0.88
Average Number of Common Shares Outstanding:
Basic			29,993,484				29,685,745				29,905,782				29,594,499
Diluted			30,300,207				29,940,868				30,198,967				29,843,953
Dividends Per Common Share		$	0.2975			$	0.2925			$	0.5950			$	0.5850

See accompanying notes to consolidated financial statements

Otter Tail Corporation

Consolidated Statements of Cash Flows
(not audited)

		Six months ended
		June 30,
		2008				2007
		(Thousands of dollars)
Cash Flows from Operating Activities
Net Income		$	11,747			$	26,511
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization			31,037				26,040
Deferred Tax Credits			(782	)			(568	)
Deferred Income Taxes			5,959				1,016
Change in Deferred Debits and Other Assets			(2,627	)			2,492
Discretionary Contribution to Pension Plan			—				(2,000	)
Change in Noncurrent Liabilities and Deferred Credits			752				6,450
Allowance for Equity (Other) Funds Used During Construction			(801	)			—
Change in Derivatives Net of Regulatory Deferral			(655	)			(1,620	)
Stock Compensation Expense			1,908				1,097
Other—Net			316				(390	)
Cash Provided by (Used for) Current Assets and Current Liabilities:
Change in Receivables			(1,904	)			(24,558	)
Change in Inventories			(10,082	)			6,323
Change in Other Current Assets			(17,520	)			(4,136	)
Change in Payables and Other Current Liabilities			16,244				(28,190	)
Change in Interest and Income Taxes Payable			1,348				11,858
Net Cash Provided by Operating Activities			34,940				20,325
Cash Flows from Investing Activities
Capital Expenditures			(117,785	)			(66,824	)
Proceeds from Disposal of Noncurrent Assets			3,517				7,043
Acquisitions—Net of Cash Acquired			(41,674	)			(6,750	)
Decreases (Increases) in Other Investments			(376	)			(5,230	)
Net Cash Used in Investing Activities			(156,318	)			(71,761	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash			3,636				4,649
Net Short-Term Borrowings			91,600				55,056
Proceeds from Issuance of Common Stock, Net of Issuance Expenses			5,176				5,805
Payments for Retirement of Common Stock			(91	)			(295	)
Proceeds from Issuance of Long-Term Debt			1,137				124
Debt Issuance Expenses			(19	)			(123	)
Payments for Retirement of Long-Term Debt			(1,829	)			(1,543	)
Dividends Paid			(18,212	)			(17,711	)
Net Cash Provided by Financing Activities			81,398				45,962
Effect of Foreign Exchange Rate Fluctuations on Cash			156				(1,317	)
Net Change in Cash and Cash Equivalents			(39,824	)			(6,791	)
Cash and Cash Equivalents at Beginning of Period			39,824				6,791
Cash and Cash Equivalents at End of Period		$	—			$	—

See accompanying notes to consolidated financial statements

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated results of operations for the periods presented. The consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes as of and for the years ended December 31, 2007, 2006 and 2005 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007. Because of seasonal and other factors, the earnings for the three-month and six-month periods ended June 30, 2008 should not be taken as an indication of earnings for all or any part of the balance of the year.

The following notes are numbered to correspond to numbers on the notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

1. Summary of Significant Accounting Policies

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 recognition 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 Company’s consolidated revenues recorded under the percentage-of-completion method were 33.6% for the three months ended June 30, 2008 compared with 30.0% for the three months ended June 30, 2007 and 31.0% for the six months ended June 30, 2008 compared with 27.6% for the six months ended June 30, 2007. The method used to determine the progress of completion is based on the ratio of labor hours incurred to total estimated labor hours 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)		2008				2007
Costs Incurred on Uncompleted Contracts		$	406,701			$	286,358
Less Billings to Date			(404,020	)			(292,692	)
Plus Estimated Earnings Recognized			54,767				38,275
		$	57,448			$	31,941

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)		2008				2007
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts		$	70,578			$	42,234
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts			(13,130	)			(10,293	)
		$	57,448			$	31,941

Sales of Receivables

In March 2008, DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer, entered into a three-year $40 million receivable purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation (GECC) on a revolving basis. Accounts receivable totaling $56.1 million have been sold in 2008. Discounts of $0.2 million for the six months ended June 30, 2008 were charged to operating expenses in the consolidated statements of income. In compliance with SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, sales of accounts receivable are reflected as a reduction of accounts receivable in the consolidated balance sheets and the proceeds are included in the cash flows from operating activities in the consolidated statements of cash flows.

Marketing and Sales Incentive Costs

ShoreMaster, Inc. (ShoreMaster), the Company’s waterfront equipment manufacturer, provides dealer floor plan financing assistance for certain dealer purchases of ShoreMaster products for certain set time periods based on the timing and size of a dealer’s order. ShoreMaster recognizes the estimated cost of projected interest payments related to each financed sale as a liability and a reduction of revenue at the time of sale, based on historical experience of the average length of time floor plan debt is outstanding, in accordance with Emerging Issues Task Force Issue No. 01-9, Accounting for Consideration Given by a Vendor to a Customer (Including a Reseller of a Vendor’s Products). The liability is reduced when interest is paid. To the extent current experience differs from previous estimates the accrued liability for financing assistance costs is adjusted accordingly. Financing assistance costs of $240,000 were charged to revenue for both the three- and six-month periods ended June 30, 2008.

Supplemental Disclosures of Cash Flow Information

		Six Months Ended
		June 30,
(in thousands)		2008				2007
Increases (Decreases) in Accounts Payable and Other Liabilities Related to Capital Expenditures		$	(21,419	)		$	238
Cash Paid During the Period for:
Interest (net of amount capitalized)		$	11,924			$	9,178
Income Taxes		$	1,136			$	1,138

Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS No. 157, Fair Value Measurements, for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of financial transmission rights.

The following table presents, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2008:

(in thousands)		Level 1				Level 2				Level 3				Total
Assets:
Investments of Nonqualified Retirement Savings Retirement Plan		$	180			$	10,995							$	11,175
Cash Surrender Value of Keyman Life Insurance Policies — Net of Policy Loans							10,528								10,528
Forward Energy Contracts							11,287								11,287
Investments of Captive Insurance Company:
Corporate Debt Securities			3,850												3,850
U.S. Government Debt Securities			2,041												2,041
Forward Foreign Currency Exchange Contracts			15												15
Total Assets		$	6,086			$	32,810							$	38,896
Liabilities:
Forward Energy Contracts		$				$	10,015							$	10,015
Total Liabilities		$				$	10,015							$	10,015
Net Assets		$	6,086			$	22,795							$	28,881

Inventories

Inventories consist of the following:

		June 30,				December 31,
(in thousands)		2008				2007
Finished Goods		$	48,046			$	38,952
Work in Process			8,541				5,218
Raw Material, Fuel and Supplies			55,646				53,044
		$	112,233			$	97,214

Goodwill and Other Intangible Assets

As a result of the acquisition of Miller Welding & Iron Works, Inc. (Miller Welding) by BTD Manufacturing, Inc. (BTD) in May 2008, Goodwill increased $7,986,000, Covenants Not to Compete increased by $100,000, Customer Relationships increased by $16,100,000 and Brand/Trade Name increased by $400,000. In the second quarter of 2008, ShoreMaster, Inc. (ShoreMaster) eliminated $282,000 of Covenants Not to Compete that were fully amortized.

The following table summarizes the components of the Company’s other intangible assets at June 30, 2008 and December 31, 2007:

		June 30, 2008												December 31, 2007
		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		$	2,456			$	1,947			$	509			$	2,637			$	2,113			$	524
Customer Relationships			26,979				1,823				25,156				10,879				1,469				9,410
Other Intangible Assets Including Contracts			2,784				1,866				918				2,785				1,775				1,010
Total		$	32,219			$	5,636			$	26,583			$	16,301			$	5,357			$	10,944
Nonamortized Intangible Assets:
Brand/Trade Name		$	9,887			$	—			$	9,887			$	9,512			$	—			$	9,512

Intangible assets with finite lives are being amortized on a straight-line basis over average lives ranging from 3 to 25 years. The amortization expense for these intangible assets was $563,000 for the six months ended June 30, 2008 compared to $687,000 for the six months ended June 30, 2007. The estimated annual amortization expense for these intangible assets for the next five years is $1,448,000 for 2008, $1,633,000 for 2009, $1,461,000 for 2010, $1,332,000 for 2011 and $1,312,000 for 2012.

Comprehensive Income

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Net Income		$	3,517			$	16,103			$	11,747			$	26,511
Other Comprehensive Income (net-of-tax)
Foreign Currency Translation Gain (Loss)			77				942				(375	)			1,046
Amortization of Unrecognized Losses and Costs Related to Postretirement Benefit Programs			37				44				80				88
Unrealized (Loss) Gain on Available-For-Sale Securities			(94	)			2				(35	)			(17	)
Total Other Comprehensive Income (Loss)			20				988				(330	)			1,117
Total Comprehensive Income		$	3,537			$	17,091			$	11,417			$	27,628

New Accounting Standards

SFAS No. 157, Fair Value Measurements, was issued by the Financial Accounting Standards Board (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 is 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. Adoption of SFAS No. 157 will result in additional footnote disclosures related to the use of fair value measurements in the areas of investments, derivatives, asset retirement obligations, goodwill and asset impairment evaluations, financial instruments and acquisitions. The Company adopted SFAS No. 157 on January 1, 2008 and required disclosures are included in this report on Form 10-Q.

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 adopted SFAS No. 159 on January 1, 2008. The adoption of this pronouncement had no effect on the Company’s consolidated financial statements because the Company had not opted, nor does it currently plan to opt, to apply fair value accounting to any financial instruments or other items that it is not currently required to account for at fair value.

SFAS No. 141 (revised 2007), Businesses Combinations (SFAS No. 141(R)), was issued by the FASB in December 2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, and will apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008—January 1, 2009 for the Company. SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). In addition to replacing the term “purchase method of accounting” with “acquisition method of accounting,” SFAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. This guidance will replace SFAS No. 141’s cost-allocation process, which requires the cost of an acquisition to be allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. SFAS No. 141’s guidance results in not recognizing some assets and liabilities at the acquisition date, and it also results in measuring some assets and liabilities at amounts other than their fair values at the acquisition date. For example, SFAS No. 141 requires the acquirer to include the costs incurred to effect an acquisition (acquisition-related costs) in the cost of the acquisition that is allocated to the assets acquired and the liabilities assumed. SFAS No. 141(R) requires those costs to be expensed as incurred. In addition, under SFAS No. 141, restructuring costs that the acquirer expects but is not obligated to incur are recognized as if they were a liability assumed at the acquisition date. SFAS No. 141(R) requires the acquirer to recognize those costs separately from the business combination.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133, was issued by the FASB in March 2008. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities to improve the transparency of financial reporting. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008—January 1, 2009 for the Company. Adoption of SFAS No. 161 will result in additional footnote disclosures related to the Company’s use of derivative instruments but those additional disclosures will not be extensive because the derivative instruments currently held by the Company are not designated as hedging instruments under this statement.

2. Business Combination and Segment Information

Acquisition

On May 1, 2008 BTD acquired the assets of Miller Welding of Washington, Illinois for $41.7 million in cash. Miller Welding, a custom job shop fabricator and finisher, recorded $26 million in revenue in 2007. Miller Welding manufactures and fabricates parts for off-road equipment, mining machinery, oil fields and offshore oil rigs, wind industry components, broadcast antennae and farm equipment, and serves several major equipment manufacturers in the Peoria, Illinois area and nationwide, including Caterpillar, Komatsu and Gardner Denver. This acquisition will provide opportunities for growth in new and existing markets for both BTD and Miller Welding, and complementing production capabilities will expand the scope and capacity of services offered by both companies.

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

(in thousands)
Assets
Current assets		$	8,855
Goodwill			7,986
Other Intangible Assets			16,600
Fixed Assets			8,994
Total Assets		$	42,435
Liabilities
Current Liabilities		$	761
Noncurrent Liabilities			—
Total Liabilities		$	761
Cash Paid		$	41,674

Other Intangible Assets related to the Miller Welding acquisition include $16,100,000 for Customer Relationships being amortized over 20 years, $400,000 for a Nonamortizable Trade Name and a $100,000 Covenant Not to Compete being amortized over three 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 (the electric utility). 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 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 Florida, Illinois, Minnesota, Missouri, North Dakota, Oklahoma, South Carolina 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 and other countries.

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. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and 6 Canadian provinces.

Corporate includes items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

The Company has a customer within the Manufacturing segment that accounted for approximately 11.0% of the Company’s consolidated revenues for the six months ended June 30, 2008. No other single external customer accounts for 10% or more of the Company’s revenues. Substantially all of the Company’s long-lived assets are within the United States except for a food ingredient processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower manufacturing plant in Fort Erie, Ontario, Canada.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
United States of America			97.2	%			95.9	%			96.6	%			96.2	%
Canada			1.5	%			2.1	%			1.4	%			1.6	%
All other countries (none greater than 1%)			1.3	%			2.0	%			2.0	%			2.2	%

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 for the business segments for three- and six-month periods ended June 30, 2008 and 2007 and total assets by business segment as of June 30, 2008 and December 31, 2007 are presented in the following tables:

Operating Revenue

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Electric		$	68,666			$	70,572			$	166,256			$	160,552
Plastics			40,645				39,525				62,995				77,344
Manufacturing			120,342				104,786				217,937				191,011
Health Services			30,740				32,452				60,005				65,415
Food Ingredient Processing			15,913				18,403				31,811				37,898
Other Business Operations			48,080				40,587				86,190				75,733
Corporate Revenues and Intersegment Eliminations			(786	)			(481	)			(1,357	)			(988	)
Total		$	323,600			$	305,844			$	623,837			$	606,965

Interest Expense

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008			2007
Electric		$	3,133			$	2,388			$	6,114			$	4,891
Plastics			327				323				468				508
Manufacturing			2,231				2,180				4,377				3,984
Health Services			176				255				355				460
Food Ingredient Processing			31				42				41				133
Other Business Operations			295				243				602				442
Corporate and Intersegment Eliminations			850				(405	)			1,797				(524	)
Total		$	7,043			$	5,026			$	13,754			$	9,894

Income Taxes

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Electric		$	(266	)		$	2,679			$	6,154			$	5,905
Plastics			429				2,280				854				4,140
Manufacturing			618				3,660				15				5,205
Health Services			(11	)			528				(426	)			1,222
Food Ingredient Processing			614				710				1,214				949
Other Business Operations			543				758				(617	)			817
Corporate			(1,558	)			(1,133	)			(3,707	)			(2,985	)
Total		$	369			$	9,482			$	3,487			$	15,253

Earnings Available for Common Shares

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
Electric		$	3,092			$	4,892			$	15,658			$	10,630
Plastics			652				3,398				1,272				6,226
Manufacturing			1,396				5,335				780				7,874
Health Services			(88	)			708				(779	)			1,656
Food Ingredient Processing			685				1,543				1,808				1,992
Other Business Operations			794				1,157				(971	)			1,234
Corporate			(3,198	)			(1,114	)			(6,389	)			(3,469	)
Total		$	3,333			$	15,919			$	11,379			$	26,143

Total Assets

		June 30,				December 31,
(in thousands)		2008				2007
Electric		$	848,287			$	813,565
Plastics			97,746				77,971
Manufacturing			332,699				274,780
Health Services			63,132				64,824
Food Ingredient Processing			98,056				91,966
Other Business Operations			77,564				72,258
Corporate			39,670				59,390
Total		$	1,557,154			$	1,454,754

3. Rate and Regulatory Matters

Minnesota

General Rate Case—The electric utility filed a general rate case in Minnesota on October 1, 2007 requesting an interim rate increase of 5.4% effective November 30, 2007 and a final total rate increase of approximately 11%. The electric utility included a proposal to credit asset-based wholesale margins through the Fuel Clause Adjustment (FCA), so the final overall customer impact would be an increase of approximately 6.7%. The electric utility revised its proposal to credit asset-based wholesale margins through base rates, and made other adjustments to its request reducing its overall requested increase to 6.3%.

In an order issued by the Minnesota Public Utilities Commission (MPUC) on August 1, 2008 the electric utility was granted an increase in Minnesota retail electric rates of approximately 2.9%, compared with a requested increase of approximately 6.7%. Otter Tail Power Company will refund Minnesota customers the difference between interim rates and final rates, with interest. The refund will commence within 120 days after the final order is no longer subject to appeal. After the refund is commenced, it must be completed within 90 days. Amounts refundable totaling $2.2 million have been recorded as a liability on the Company’s consolidated balance sheet as of June 30, 2008. The MPUC approved a rate of return on equity of 10.43% on a capital structure with 50.0% equity. The electric utility disagrees with certain aspects of the MPUC decision and plans to request reconsideration of those decision items.

The electric utility reversed and deferred recognition of $1.5 million in rate case-related costs in June 2008 that are subject to amortization and recovery over three years under new rates as ordered by the MPUC.

Capacity Expansion 2020 (CapX 2020) Mega Certificate of Need—On August 16, 2007 the eleven CapX 2020 utilities asked the MPUC to determine the need for three 345-kilovolt (kv) transmission lines. Evidentiary hearings for the Certificate of Need for the three CapX 2020 345-kv transmission line projects began in July 2008 and continued into August 2008. The MPUC is expected to decide if the lines meet regulatory need requirements by early 2009. Portions of the lines would also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. The MPUC would determine routes for the new lines in separate proceedings. After regulatory need is established and routing decisions are completed (expected in 2009 or 2010), construction will begin. The lines would be expected to be completed three or four years later. Great River Energy and Xcel Energy are leading these projects, and Otter Tail Power Company and eight other utilities are involved in permitting, building and financing. Otter Tail Power Company is directly involved in two of these three projects and serves as the lead utility in a fourth Group 1 project, the Bemidji-Grand Rapids 230-kv line which has an expected in-service date of 2012-2013.

The electric utility filed a Certificate of Need for the fourth project on March 17, 2008. The Department of Commerce Office of Energy Security (OES) staff completed briefing papers regarding the Bemidji/Grand Rapids route permit application. The OES staff recommended to the MPUC that: (1) the route permit application be found to be complete, (2) the need determination not be sent to a contested case but be handled informally by MPUC review, and (3) the Certificate of Need and route permit proceedings be combined as requested. The MPUC met on June 26, 2008 to act on the OES staff recommendation. The MPUC agreed that the Certificate of Need and route permit applications were complete. The commissioners asked the CapX 2020 utilities to add a section to the Certificate of Need application addressing how the new Minnesota Conservation Improvement Programs (CIP) statutes will affect the need for the project. Because no one has intervened in the Certificate of Need proceeding, the MPUC will handle the Certificate of Need application as an uncontested case. The scoping hearing is scheduled for August 11-14, 2008. These hearings will combine the Certificate of Need and route permit scoping processes and will include federal agencies’ environmental scoping processes as well. The MPUC is expected to decide if this line is needed in the third or fourth quarter of 2008 and issue the route permit in 2009.

Renewable Energy Standards, Conservation and Renewable Resource Riders—In February 2007, the Minnesota legislature passed a renewable energy standard requiring the electric utility to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 12% by 2012; 17% by 2016; 20% by 2020 and 25% by 2025. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. The electric utility has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. The electric utility’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

Under the Next Generation Energy Act passed by the Minnesota legislature in May 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover charges incurred to satisfy the requirements of the renewable energy standards. The MPUC is now authorized to approve a rate schedule rider to recover the costs of qualifying renewable energy projects to supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can now be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval in an integrated resource plan or Certificate of Need proceeding before the MPUC. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses. The electric utility has requested approval of a renewable resource rider that would allow recovery of eligible and prudently incurred costs for its qualifying renewable energy project investments. The proposed rider would cover the Minnesota jurisdictional portion of such eligible costs. The electric utility received MPUC approval of its proposed rider on August 7, 2008. As of June 30, 2008 the electric utility had recorded a regulatory asset of $1,523,000 related to the deferred recognition of the Minnesota portion of renewable resource costs incurred in the first six months of 2008, pending approval and implementation of the proposed rider.

In addition, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new electric transmission facilities. The MPUC may approve a tariff to recover the Minnesota jurisdictional costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need proceeding or certified by the MPUC as a Minnesota priority transmission project or investment and expenditures made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers. Such transmission cost recovery riders would allow a return on investments at the level approved in a utility’s last general rate case. The electric utility is also preparing to file a proposed rider to recover its share of costs of transmission infrastructure upgrades projects. The electric utility currently expects to file its transmission cost recovery tariff in 2008.

North Dakota

On May 21, 2008 the North Dakota Public Service Commission (NDPSC) approved the electric utility’s request for a Renewable Resource Cost Recovery Rider to enable the electric utility to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. The Renewable Resource Adjustment of 0.193 cents per kilowatt-hour was included on North Dakota customers’ electric service statements beginning in June 2008. The first renewable energy project for which the electric utility will receive cost recovery is its 40.5 megawatt ownership share of the Langdon Wind Energy Center, which became commercially operational in January 2008. The electric utility may also recover through this rider costs associated with other new renewable energy projects as they are completed.

Unlike renewable resource costs eligible for recovery in Minnesota, the electric utility had not been deferring recognition of its renewable resource costs eligible for recovery under the North Dakota Renewable Resource Cost Recovery Rider but has been charging those costs to operating expense since January 2008. After approval of the rider, the electric utility accrued revenue related to its investment in renewable energy and for renewable energy costs incurred since January 2008 that are eligible for recovery through the North Dakota Renewable Resource Cost Recovery Rider. The Company’s June 30, 2008 consolidated balance sheet includes a regulatory asset of $1,361,000 for revenues that are eligible for recovery through the North Dakota Renewable Resource Cost Recovery Rider but that had not been billed to North Dakota customers as of June 30, 2008.

North Dakota legislation also provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The electric utility has not yet determined whether it will request recovery of such costs under the automatic adjustment mechanism or in its next general rate case filing.

The electric utility intends to file general rate cases requesting rate increases in both North Dakota and South Dakota in 2008.

Federal

Transmission Practices Audit—The Federal Energy Regulatory Commission’s (FERC) Office of Enforcement, formerly referred to as the Division of Operation Audits of the Office of Market Oversight and Investigations commenced an audit of the electric utility’s transmission practices in 2005 for the period January 1, 2003 through August 31, 2005. The purpose of the audit was to determine whether the electric utility’s transmission practices were in compliance with the FERC’s applicable rules, regulations and tariff requirements and whether the implementation of the electric utility’s waivers from the requirements of Order No. 889 and Order No. 2004 appropriately restricted access to transmission information that would benefit the electric utility’s off-system sales. FERC staff identified two of the electric utility’s transmission practices that it believed were out of compliance. The electric utility believes its actions were in compliance with the MISO tariff but rather than litigate, it entered into a Stipulated Settlement Agreement with FERC staff resolving all issues related to the audit. The FERC approved the settlement agreement on May 29, 2008.

FERC order (IN08-6-000) resolves alleged network transmission service violations by the electric utility of the Open Access Transmission and Energy Markets Tariff (OATT) of the MISO. The electric utility agreed to pay $547,000 plus interest of $141,000 to the Low Income Home Energy Assistance Program administered by the three states served by the electric utility. This amount represents profits earned by the electric utility on transactions FERC staff believes incorrectly utilized network transmission service under MISO’s OATT. Enforcement staff did not seek to impose a compliance monitoring plan on the electric utility because the MISO’s Day 2 market is now operational and its member utilities no longer schedule transmission within the system.

Big Stone II Project

On June 30, 2005 the electric utility and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. The three primary agreements are the Participation Agreement, the Operation and Maintenance Agreement and the Joint Facilities Agreement. Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency are parties to all three agreements. In September 2007, Great River Energy and Southern Minnesota Municipal Power Agency withdrew from the project. The five remaining project participants decided to downsize the proposed plant’s nominal generating capacity from 630 megawatts to between 500 and 580 megawatts. New procedural schedules have been established in the various project-related proceedings, which will take into consideration the optimal plant configuration decided on by the remaining participants. NorthWestern Corporation, one of the co-owners of the existing Big Stone Plant, is an additional party to the Joint Facilities Agreement.

The electric utility and the coalition of six other electric providers filed an application for a Certificate of Need for the Minnesota portion of the Big Stone II transmission line project on October 3, 2005 and filed an application for a Route Permit for the Minnesota portion of the Big Stone II transmission line project with the MPUC on December 9, 2005. Evidentiary hearings were conducted in December 2006 and all parties submitted legal briefs. The Administrative Law Judges (ALJs) on August 15, 2007 recommended approval of the Certificate of Need subject to potential conditions. The electric utility and project participants addressed the ALJs’ recommended potential conditions in an August 31, 2007 proposed settlement agreement with the Minnesota Department of Commerce that was entered into the record of the Certificate of Need/Route Permit dockets. The MPUC had not acted on the applications or the proposed settlement agreement when Great River Energy and Southern Minnesota Municipal Power Agency withdrew from the project. On October 19, 2007 the MPUC requested that the ALJs recommence proceedings in the matter and that the remaining project participants file testimony describing and supporting a revised Big Stone II project. The remaining five participants filed testimony on November 13, 2007. On December 3, 2007 the ALJs issued an order refining the scope of the additional proceedings. Evidentiary hearings were held on January 23-25, 2008.

On May 9, 2008 the ALJs issued their report—reversing their previous recommendation—recommending that the MPUC deny the petition for a Certificate of Need and related route permits for the proposed transmission lines. On May 19, 2008 the five Big Stone II participating utilities filed exceptions to the ALJs’ Report and Recommendation with the MPUC. The MPUC heard oral arguments on the Big Stone II transmission Certificate of Need application on June 3, 2008. In a 3-2 vote on June 5, 2008, the MPUC deferred a decision on the Big Stone II transmission Certificate of Need. The MPUC will develop a process whereby MPUC-appointed experts will render opinions on the modeling data utilized by the Big Stone II participating utilities for construction costs, potential carbon dioxide regulation costs, natural gas costs, and other matters pertinent to the application. The electric utility currently expects a decision on the transmission Certificate of Need application in late 2008 or 2009.

The electric utility’s integrated resource plan (IRP) includes generation from Big Stone II beginning in 2013 to accommodate load growth and to replace expiring purchased power contracts and older coal-fired base-load generation units scheduled for retirement. On June 5, 2008 the MPUC also deferred approval of the electric utility’s 2006-2020 IRP, which was originally filed in 2005.

A filing in North Dakota for an advanced determination of prudence of Big Stone II was made by the electric utility in November 2006. Evidentiary hearings were held in June 2007. The NDPSC decision was delayed because of the change in ownership of the project. The ALJ in the matter held supplemental hearings in April 2008. The Company expects the NDPSC to issue a decision in the third quarter of 2008.

The Big Stone II participating utilities have filed a contested case proceeding with the South Dakota Board of Minerals and Environment to acquire required air permits for Big Stone II. A decision by the Board is expected in 2008.

As of June 30, 2008 the electric utility has capitalized $9.8 million in costs related to the planned construction of Big Stone II. 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.

Holding Company Reorganization

The Company’s Board of Directors has authorized a holding company reorganization of the Company. Following the completion of the holding company reorganization, Otter Tail Power Company, which is currently operated as a division of Otter Tail Corporation, will be operated as a wholly owned subsidiary of the new parent holding company to be named Otter Tail Corporation. In connection with the reorganization, each outstanding Otter Tail Corporation common share will be automatically converted into one common share of the new holding company, and each outstanding Otter Tail Corporation cumulative preferred share will be automatically converted into one cumulative preferred share of the new holding company having the same terms. The holding company reorganization is subject to approval by Minnesota, North Dakota and South Dakota regulatory agencies and by the FERC, consents from various third parties and certain other conditions, and is expected to become effective on January 1, 2009.

4. 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)		2008				2007
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pension and Other Postretirement Benefits		$	25,691			$	26,933
Deferred Income Taxes			8,252				8,733
Accrued Cost-of-Energy Revenue			3,572				19,452
Reacquisition Premiums			3,546				3,745
Minnesota Renewable Resource Rider Recoverable Costs			1,523				—
Minnesota General Rate Case Recoverable Expenses			1,460				—
North Dakota Renewable Resource Rider Accrued Revenue			1,361				—
MISO Schedule 16 and 17 Deferred Administrative Costs — ND			704				576
MISO Schedule 16 and 17 Deferred Administrative Costs — MN			664				855
Accumulated ARO Accretion/Depreciation Adjustment			449				345
Other Regulatory Assets			53				625
Deferred Marked-to-Market Losses			—				771
Total Regulatory Assets		$	47,275			$	62,035
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs		$	58,765			$	57,787
Deferred Income Taxes			4,532				4,502
Gain on Sale of Division Office Building			142				145
Deferred Marked-to-Market Gains			—				271
Total Regulatory Liabilities		$	63,439			$	62,705
Net Regulatory Liability Position		$	16,164			$	670

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. These unrecognized benefit costs were required to be recognized as components of Accumulated Other Comprehensive Income in equity under SFAS No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, adopted in December 2006, but were determined to be eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

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 and Cost-of-Energy Revenues will be recovered over the next 14 months.

Reacquisition Premiums included in Unamortized Debt Expense are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 24.3 years.

The deferred Minnesota Renewable Resource Rider Recoverable Costs are expected to be recovered from September 2008 through December 2009.

Minnesota General Rate Case Recoverable Expenses will be recovered over a 36-month period from the time revised rates established by the recent Minnesota general rate case go into effect.

North Dakota Renewable Resource Rider Accrued Revenue relates to revenues earned on qualifying 2008 renewable resource costs incurred to serve North Dakota customers prior to the rider being implemented in June 2008. The North Dakota Renewable Resource Rider Accrued Revenue is expected to be recovered over 18 months, from July 2008 through December 2009.

MISO Schedule 16 and 17 Deferred Administrative Costs — ND were excluded from recovery through the FCA in North Dakota in an August 2007 order issued by the NDPSC. The NDPSC ordered the electric utility 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 electric utility’s next general rate case in North Dakota scheduled to be filed in November or December of 2008.

MISO Schedule 16 and 17 Deferred Administrative Costs — MN will be recovered over the next 29 months.

Other Regulatory Assets will be amortized over the next 2.2 years.

All Deferred Marked-to-Market Losses and Gains were related to forward purchases of energy scheduled for delivery in January and February of 2008.

The Accumulated Reserve for Estimated Removal Costs is reduced for actual removal costs incurred.

The remaining regulatory assets and liabilities are being recovered from, or will be paid to, electric customers over the next 30 years.

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

5. Forward Contracts Classified as Derivatives

As of June 30, 2008 the electric utility had recognized, on a pretax basis, $1,272,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. 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. For certain contracts, prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. Prices are benchmarked to forward price curves and indices acquired from a third party price forecasting service. The fair value measurements of these forward energy contracts fall into level 2 of the fair value hierarchy set forth in SFAS No. 157.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity on the Company’s consolidated balance sheet as of June 30, 2008 and the change in the Company’s consolidated balance sheet position from December 31, 2007 to June 30, 2008:

(in thousands)		June 30, 2008
Current Asset — Marked-to-Market Gain		$	11,287
Current Liability — Marked-to-Market Loss			(10,015	)
Net Fair Value of Marked-to-Market Energy Contracts		$	1,272

		Year-to-Date
(in thousands)		June 30, 2008
Fair Value at Beginning of Year		$	632
Amount Realized on Contracts Entered into in 2007 and Settled in 2008			(204	)
Changes in Fair Value of Contracts Entered into in 2007			493
Net Fair Value of Contracts Entered into in 2007 at End of Period			921
Changes in Fair Value of Open Contracts Entered into in 2008			351
Net Fair Value End of Period		$	1,272

The Canadian operations of IPH records its sales and carries its receivables in U.S. dollars but pays its expenses for goods and services consumed in Canada in Canadian dollars. The payment of its bills in Canada requires the periodic exchange of U.S. currency for Canadian currency. In order to lock in acceptable exchange rates and hedge its exposure to future fluctuations in foreign currency exchange rates between the U.S. dollar and the Canadian dollar, IPH’s Canadian subsidiary entered into forward contracts for the exchange of U.S. dollars into Canadian dollars on March 20, 2008 to cover approximately 50% of its monthly expenditures for the last nine months of 2008. Each contract is for the exchange of $400,000 USD for the amount of Canadian dollars stated in each contract, for a total exchange of $3,600,000 USD for $3,695,280 CAD. Each of these contracts can be settled incrementally during the month the contract is scheduled for settlement, but for practical reasons and to reduce settlement fees each contract will most likely be settled in one or two exchanges.

These open contracts are derivatives subject to mark-to-market accounting. IPH does not enter into these contracts for speculative purposes or with the intent of early settlement, but for the purpose of locking in acceptable exchange rates and hedging its exposure to future fluctuations in exchange rates with the intent of settling these contracts during their stated settlement periods and using the proceeds to pay its Canadian liabilities when they come due. These contracts will not qualify for hedge accounting treatment because the timing of their settlements will not coincide with the payment of specific bills or existing contractual obligations.

The foreign currency exchange forward contracts outstanding as of June 30, 2008 were valued and marked to market on June 30, 2008 based on quoted exchange values of similar contracts that could be purchased on June 30, 2008. Based on those values, IPH’s Canadian subsidiary recorded a derivative asset and mark-to-market net gain of $15,000 as of, and for the three month period ended, June 30, 2008. The fair value measurements of these forward energy contracts fall into level 1 of the fair value hierarchy set forth in SFAS No. 157.

6. Common Shares and Earnings Per Share

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2007 through June 30, 2008:

Common Shares Outstanding, December 31, 2007			29,849,789
Issuances:
Stock Options Exercised			191,774
Executive Officer Stock Performance Awards			62,625
Restricted Stock Issued to Nonemployee Directors			20,000
Restricted Stock Issued to Employees			19,371
Vesting of Restricted Stock Units			3,850
Retirements:
Shares Withheld for Individual Income Tax Requirements			(22,700	)
Common Shares Outstanding, June 30, 2008			30,124,709

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.

For the three- and six-month periods ended June 30, 2008 and 2007 there were no outstanding stock options which had exercise prices greater than the average market price. Therefore, all outstanding options were included in the calculation of diluted earnings per share for the respective periods.

7. Share-Based Payments

The Company has six share-based payment programs.

On April 14, 2008 the Company’s Board of Directors granted 26,050 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan) payable in common shares on April 8, 2012, the date the units vest. The grant date fair value of each restricted stock unit was $30.81 per share. Also on April 14, 2008 the Company’s Board of Directors approved the award of 600 restricted stock units to be granted effective July 1, 2008 for another key employee under the Incentive Plan payable in common shares on July 1, 2011, the date the units vest. The grant date fair value of these restricted stock units will be determined under a Monte Carlo valuation method based on the market value of the Company’s common stock on July 1, 2008.

On April 14, 2008 the Company’s Board of Directors granted 20,000 shares of restricted stock to the Company’s nonemployee directors, 17,600 shares of restricted stock to the Company’s executive officers and 1,771 shares of restricted stock to a key employee under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2009 through 2012 and are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was $35.345 per share, the average market price on the date of grant.

On April 14, 2008 the Company’s Board of Directors granted performance share awards to the Company’s executive officers under the Incentive Plan. Under these awards, the Company’s executive officers could earn up to an aggregate of 114,800 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance period of January 1, 2008 through December 31, 2010. The aggregate target share award is 57,400 shares. Actual payment may range from zero to 200% of the target amount. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The grant date fair value of the common shares projected to be awarded was $37.59 per share, as determined under a Monte Carlo valuation method.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three- and six-month periods ended June 30, 2008 and 2007 are presented in the table below:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2008				2007				2008				2007
1999 Employee Stock Purchase Plan		$	65			$	64			$	135			$	127
Stock Options Granted Under the 1999 Stock Incentive Plan			—				22				—				90
Restricted Stock Granted to Directors			132				96				240				247
Restricted Stock Granted to Employees			121				208				239				412
Restricted Stock Units Granted to Employees			144				109				238				178
Stock Performance Awards Granted to Executive Officers			784				221				1,124				441
Totals		$	1,246			$	720			$	1,976			$	1,495

As of June 30, 2008 the remaining unrecognized compensation expense related to stock-based compensation was approximately $7.8 million (before income taxes) which will be amortized over a weighted-average period of 2.5 years.

9. Commitments and Contingencies

Ashtabula Wind Center

On April 30, 2008 Otter Tail Power Company announced plans to invest $121 million related to the construction of 48 megawatts of wind energy generation at the proposed Ashtabula Wind Center site in Barnes County, North Dakota. Contractual commitments related to this project have increased the electric utility’s commitments under contracts in connection with construction programs reported in note 9 of Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007 by $80.3 million in 2008.

Sales of Receivables

DMI entered into a three year $40 million receivable purchase agreement in March 2008, whereby designated customer accounts receivable may be sold to GECC on a revolving basis. As of June 30, 2008, DMI had sold $56.1 million of accounts receivable to GECC to mitigate accounts receivable concentration risk. Any obligations of DMI to GECC that may be incurred under the receivables purchase agreement are guaranteed by Varistar Corporation, DMI’s parent company. As of June 30, 2008, $19.4 million of accounts receivable sold to GECC were outstanding.

Dealer Floor Plan Financing

Under ShoreMaster’s floor plan financing agreement with GE Commercial Distribution Finance Corporation (CDF), ShoreMaster is required to repurchase new and unused inventory repossessed from ShoreMaster’s dealers by CDF to satisfy the dealer’s obligations to CDF. ShoreMaster has agreed to unconditionally guarantee to CDF all

current and future liabilities which any dealer owes to CDF under this agreement. Any amounts due under this guaranty will be payable despite impairment or unenforceability of CDF’s security interest with respect to inventory that may prevent CDF from repossessing the inventory. The aggregate total of amounts owed by dealers to CDF under this agreement was $5.4 million on June 30, 2008. ShoreMaster has incurred no losses under this agreement. The Company believes current available cash and cash generated from operations provide sufficient funding in the event there is a requirement to perform under this agreement.

Sierra Club Complaint

On June 10, 2008, the Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) against the Company and two other co-owners of Big Stone Generating Station (Big Stone). The complaint alleges certain violations of the Prevention of Significant Deterioration and New Source Performance Standards (NSPS) provisions of the Clean Air Act and certain violations of the South Dakota State Implementation Plan (South Dakota SIP). The action further alleges the defendants modified and operated Big Stone without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleges the defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club seeks both declaratory and injunctive relief to bring the defendants into compliance with the Clean Air Act and the South Dakota SIP and to require the defendants to remedy the alleged violations. The Sierra Club also seeks unspecified civil penalties, including a beneficial mitigation project. The Company believes these claims are without merit and that Big Stone has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. The ultimate outcome of these matters cannot be determined at this time.

The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of June 30, 2008 will not be material.

11. Class B Stock Options of Subsidiary

As of June 30, 2008 there were 933 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $691,000, of which 753 options were “in-the-money” with a combined exercise price of $316,000.

12. 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)		2008				2007				2008				2007
Service Cost—Benefit Earned During the Period		$	1,275			$	1,263			$	2,550			$	2,526
Interest Cost on Projected Benefit Obligation			2,800				2,733				5,600				5,466
Expected Return on Assets			(3,550	)			(3,223	)			(7,100	)			(6,446	)
Amortization of Prior-Service Cost			175				185				350				370
Amortization of Net Actuarial Loss			125				309				250				618
Net Periodic Pension Cost		$	825			$	1,267			$	1,650			$	2,534

The Company did not make a contribution to its pension plan in the six months ended June 30, 2008 and is not required to make a contribution in 2008.

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)		2008				2007				2008				2007
Service Cost—Benefit Earned During the Period		$	173			$	157			$	346			$	313
Interest Cost on Projected Benefit Obligation			384				362				768				725
Amortization of Prior-Service Cost			16				17				32				34
Amortization of Net Actuarial Loss			120				135				240				270
Net Periodic Pension Cost		$	693			$	671			$	1,386			$	1,342

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)		2008				2007				2008				2007
Service Cost—Benefit Earned During the Period		$	300			$	315			$	600			$	630
Interest Cost on Projected Benefit Obligation			725				698				1,450				1,396
Amortization of Transition Obligation			187				187				374				374
Amortization of Prior-Service Cost			50				(52	)			100				(103	)
Amortization of Net Actuarial Loss			125				129				250				258
Effect of Medicare Part D Expected Subsidy			(400	)			(410	)			(800	)			(820	)
Net Periodic Postretirement Benefit Cost		$	987			$	867			$	1,974			$	1,735

19. Subsequent Events

In an order issued by the MPUC on August 1, 2008 Otter Tail Power Company was granted an increase in Minnesota retail electric rates of approximately 2.9%, compared with a requested increase of approximately 6.7%. The MPUC approved a rate of return on equity of 10.43% on a capital structure with 50.0% equity. An interim rate increase of 5.4% went into effect on November 30, 2007. Otter Tail Power Company will refund Minnesota customers the difference between interim rates and final rates, with interest. Amounts refundable totaling $2.2 million have been recorded as a liability on the Company’s consolidated balance sheet as of June 30, 2008. On July 30, 2008 Otter Tail Corporation, dba Otter Tail Power Company replaced its credit agreement with U.S. Bank National Association, which provided for a $75 million line of credit, with a new credit agreement providing for a $170 million line of credit with an accordion feature whereby the line can be increased to $250 million. The prior credit agreement was subject to renewal on September 1, 2008. The new credit agreement (the Electric Utility Credit Agreement) is between Otter Tail Corporation, dba Otter Tail Power Company and JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association and Merrill Lynch Bank USA, as Banks, U.S. Bank National Association, as a Bank and as agent for the Banks, and Bank of America, N.A., as a Bank and as Syndication Agent. The Electric Utility Credit Agreement is an unsecured revolving credit facility that the electric utility can draw on to support the working capital needs and other capital requirements of its operations. 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. The Electric Utility Credit Agreement contains a number of restrictions on the business of

the electric utility, including restrictions on its ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Electric Utility Credit Agreement is subject to renewal on July 30, 2011.

On August 7, 2008 the MPUC approved the electric utility’s request for a Renewable Resource Cost Recovery Rider that will enable the company to recover from its Minnesota retail customers its investments in renewable energy facilities. The effects of the approval of the rider on the Company’s consolidated financial statements will be recorded in the third quarter of 2008 after the electric utility receives a final order with implementation guidance from the MPUC.

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

RESULTS OF OPERATIONS

Following is an analysis of our operating results by business segment for the three and six months ended June 30, 2008 and 2007, followed by our outlook for the remainder of 2008 and a discussion of changes in our consolidated financial position during the six months ended June 30, 2008.

Comparison of the Three Months Ended June 30, 2008 and 2007

Consolidated operating revenues were $323.6 million for the three months ended June 30, 2008 compared with $305.8 million for the three months ended June 30, 2007. Operating income was $10.3 million for the three months ended June 30, 2008 compared with $30.3 million for the three months ended June 30, 2007. The Company recorded diluted earnings per share of $0.11 for the three months ended June 30, 2008 compared to $0.53 for the three 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, 2008 and 2007 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, 2008				June 30, 2007
Operating Revenues:
Electric		$	89			$	74
Nonelectric			697				407
Cost of Goods Sold			599				393
Other Nonelectric Expenses			187				88

Electric

		Three Months Ended
		June 30,												%
(in thousands)		2008				2007				Change				Change
Retail Sales Revenues		$	57,389			$	55,501			$	1,888				3.4
Wholesale Revenues			6,221				6,674				(453	)			(6.8	)
Net Marked-to-Market (Loss) Gain			(31	)			3,429				(3,460	)			(100.9	)
Other Revenues			5,087				4,968				119				2.4
Total Operating Revenues		$	68,666			$	70,572			$	(1,906	)			(2.7	)
Production Fuel			14,808				14,077				731				5.2
Purchased Power — System Use			10,156				11,021				(865	)			(7.8	)
Other Operation and Maintenance Expenses			27,757				26,651				1,106				4.1
Depreciation and Amortization			7,806				6,250				1,556				24.9
Property Taxes			2,563				2,527				36				1.4
Operating Income		$	5,576			$	10,046			$	(4,470	)			(44.5	)

The increase in retail revenues reflects $1.5 million in North Dakota Renewable Resource Cost Recovery Rider revenue recorded in the second quarter of 2008 as a result of North Dakota Public Service Commission (NDPSC) approval of the electric utility’s request for a Renewable Resource Cost Recovery Rider in May 2008. The increase in retail revenues also reflects a 2.7% increase in retail kilowatt-hour (kwh) sales related to a 24% increase in heating degree days between the quarters. A 5.4% interim rate increase in Minnesota retail rates in connection with the electric utility’s application for a general rate increase contributed approximately $1.5 million to retail revenues, but it was more than offset by a $2.2 million refund accrual resulting from the decision of the Minnesota Public Utilities Commission (MPUC) to grant a final general rate increase of only 2.9%. The refund accrual relates to interim rates in effect since November 30, 2007.

Wholesale electric revenues from company-owned generation were $4.9 million for the quarter ended June 30, 2008 compared with $3.5 million for the quarter ended June 30, 2007 as a result of a 37.5% increase in kwh sales and a 3.1% increase in the price per kwh sold. A slight increase in kwhs generated from company-owned resources resulted in more generation being available to meet wholesale market demands. Plant availability, demand, load distribution and economic dispatch across the entire Midwest Independent Transmission System Operator (MISO) region are all factors that drive wholesale prices of electricity. Net gains from energy trading contracts settled in the second quarter of 2008 were $1.3 million compared with $3.2 million in the second quarter of 2007. Trading volumes were higher but profit margins on trades were significantly lower in the second quarter of 2008 compared to the second quarter of 2007. Additionally, second quarter 2007 energy trading revenues included the reversal of a $1.7 million refund accrual recorded in the first quarter of 2007.

The $3.5 million decrease in net marked-to-market gains on forward energy contracts reflects lower margins on trades in the second quarter of 2008 compared with the second quarter 2007 and second quarter 2008 reductions of marked-to-market gains recognized on open forward energy contracts in the first quarter of 2008.

Production fuel costs increased 5.2% despite a 2.8% decrease in kwhs generated as a result of an 8.2% increase in the cost of fuel per kwh generated. Generation for retail sales decreased 2.1% while generation used for wholesale electric sales increased 37.5% between the quarters. The increase in fuel costs per kwh is directly related to higher diesel fuel prices which result in increased costs to operate coal mines and to transport coal by rail. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the Fuel Clause Adjustment (FCA) component of retail rates. The electric utility’s 27 new wind turbines at the Langdon Wind Energy Center provided 4.5% of total kwh generation in the second quarter of 2008.

The decrease in purchased power — system use is due to a 13.5% reduction in kwhs purchased partially offset by a 6.5% increase in the cost per kwh purchased. The increase in the cost per mwh of purchased power reflects a general increase in fuel and purchased power costs across the Mid-Continent Area Power Pool region as a result of higher demand due to colder weather in the second quarter of 2008 compared with the second quarter of 2007.

Electric operating and maintenance expenses increased mainly as a result of expenses incurred in the second quarter of 2008 to repair and maintain the Hoot Lake Plant Unit 2 generator turbine. Depreciation expenses increased as a result of recent capital additions, including 27 new wind turbines at the Langdon Wind Energy Center.

Plastics

		Three Months Ended
		June 30,												%
(in thousands)		2008				2007				Change				Change
Operating Revenues		$	40,645			$	39,525			$	1,120				2.8
Cost of Goods Sold			36,685				31,007				5,678				18.3
Operating Expenses			1,829				1,753				76				4.3
Depreciation and Amortization			723				764				(41	)			(5.4	)
Operating Income		$	1,408			$	6,001			$	(4,593	)			(76.5	)

Operating revenues for the plastics segment increased as result of a 1.1% increase in pounds of pipe sold combined with a 1.9% increase in the price per pound of pipe sold between the quarters. The increase in cost of goods sold reflects a 16.8% increase in resin prices per pound of pipe sold.

Manufacturing

		Three Months Ended
		June 30,												%
(in thousands)		2008				2007				Change				Change
Operating Revenues		$	120,342			$	104,786			$	15,556				14.8
Cost of Goods Sold			99,377				81,188				18,189				22.4
Operating Expenses			10,213				9,108				1,105				12.1
Plant Closure Costs			1,412				—				1,412				—
Depreciation and Amortization			4,876				3,283				1,593				48.5
Operating Income		$	4,464			$	11,207			$	(6,743	)			(60.2	)