SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended       March 31, 2010

OR

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

Commission file number 0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota		27-0383995
(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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:

April 30, 2010 — 35,932,089 Common Shares ($5 par value)

 

 

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets — March 31, 2010 and December 31, 2009 (not audited)			2 & 3
Consolidated Statements of Income — Three Months Ended March 31, 2010 and 2009 (not audited)			4
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2010 and 2009 (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			27-40
Item 3. Quantitative and Qualitative Disclosures About Market Risk			41-42
Item 4. Controls and Procedures			42
Part II. Other Information
Item 1. Legal Proceedings			43-44
Item 1A. Risk Factors			44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			44
Item 6. Exhibits			44
Signatures			44
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets
(not audited)

		March 31,				December 31,
(in thousands)		2010				2009
ASSETS
Current Assets
Cash and Cash Equivalents		$	—			$	4,432
Accounts Receivable:
Trade—Net			117,485				95,747
Other			9,714				10,883
Inventories			96,839				86,515
Deferred Income Taxes			11,420				11,457
Accrued Utility and Cost-of-Energy Revenues			11,328				15,840
Costs and Estimated Earnings in Excess of Billings			82,792				61,835
Income Taxes Receivable			50,668				48,049
Other			25,253				15,265
Total Current Assets			405,499				350,023
Investments			10,274				9,889
Other Assets			26,865				26,098
Goodwill			106,778				106,778
Other Intangibles—Net			33,530				33,887
Deferred Debits
Unamortized Debt Expense and Reacquisition Premiums			10,065				10,676
Regulatory Assets and Other Deferred Debits			124,680				118,700
Total Deferred Debits			134,745				129,376
Plant
Electric Plant in Service			1,313,478				1,313,015
Nonelectric Operations			375,624				362,088
Total			1,689,102				1,675,103
Less Accumulated Depreciation and Amortization			617,000				599,839
Plant—Net of Accumulated Depreciation and Amortization			1,072,102				1,075,264
Construction Work in Progress			26,168				23,363
Net Plant			1,098,270				1,098,627
Total		$	1,815,961			$	1,754,678

See accompanying notes to consolidated financial statements.

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)

		March 31,				December 31,
(in thousands, except share data)		2010				2009
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt		$	110,499			$	7,585
Current Maturities of Long-Term Debt			916				59,053
Accounts Payable			93,954				83,724
Accrued Salaries and Wages			16,576				21,057
Accrued Taxes			9,510				11,304
Derivative Liabilities			21,573				14,681
Other Accrued Liabilities			12,237				9,638
Total Current Liabilities			265,265				207,042
Pensions Benefit Liability			96,259				95,039
Other Postretirement Benefits Liability			38,121				37,712
Other Noncurrent Liabilities			23,270				22,697
Commitments (note 9)
Deferred Credits
Deferred Income Taxes			162,949				155,306
Deferred Tax Credits			46,981				47,660
Regulatory Liabilities			64,681				64,274
Other			530				562
Total Deferred Credits			275,141				267,802
Capitalization
Long-Term Debt, Net of Current Maturities			436,078				436,170
Class B Stock Options of Subsidiary			1,220				1,220
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value; Outstanding 2010 and 2009 — 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, 2010—35,838,353 Shares; 2009—35,812,280 Shares			179,192				179,061
Premium on Common Shares			249,375				250,398
Retained Earnings			237,223				243,352
Accumulated Other Comprehensive Loss			(683	)			(1,315	)
Total Common Equity			665,107				671,496
Total Capitalization			1,117,905				1,124,386
Total		$	1,815,961			$	1,754,678

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Income
(not audited)

		Three Months Ended
		March 31,
(in thousands, except share and per-share amounts)		2010				2009
Operating Revenues
Electric		$	91,014			$	88,479
Nonelectric			171,172				188,760
Total Operating Revenues			262,186				277,239
Operating Expenses
Production Fuel — Electric			20,909				18,659
Purchased Power — Electric System Use			12,056				17,373
Electric Operation and Maintenance Expenses			28,322				26,930
Cost of Goods Sold — Nonelectric (excludes depreciation; included below)			131,912				152,961
Other Nonelectric Expenses			30,771				30,634
Product Recall and Testing Costs			—				1,766
Depreciation and Amortization			19,751				17,817
Property Taxes — Electric			2,474				2,490
Total Operating Expenses			246,195				268,630
Operating Income			15,991				8,609
Other Income			136				667
Interest Charges			9,030				6,270
Income Before Income Taxes			7,097				3,006
Income Tax Expense (Benefit)			2,380				(1,382	)
Net Income			4,717				4,388
Preferred Dividend Requirements			184				184
Earnings Available for Common Shares		$	4,533			$	4,204
Average Number of Common Shares Outstanding—Basic			35,720,571				35,324,736
Average Number of Common Shares Outstanding—Diluted			35,939,759				35,488,640
Earnings Per Common Share:
Basic		$	0.13			$	0.12
Diluted		$	0.13			$	0.12
Dividends Per Common Share		$	0.2975			$	0.2975

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows
(not audited)

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Cash Flows from Operating Activities
Net Income		$	4,717			$	4,388
Adjustments to Reconcile Net Income to Net Cash (Used in) Provided
by Operating Activities:
Depreciation and Amortization			19,751				17,817
Deferred Tax Credits			(679	)			(538	)
Deferred Income Taxes			6,691				5,487
Change in Deferred Debits and Other Assets			27				569
Change in Noncurrent Liabilities and Deferred Credits			2,346				1,916
Allowance for Equity Funds Used During Construction			—				(91	)
Change in Derivatives Net of Regulatory Deferral			(1,622	)			(809	)
Stock Compensation Expense — Equity Awards			610				837
Other—Net			(52	)			195
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables			(20,518	)			18,482
Change in Inventories			(10,038	)			4,072
Change in Other Current Assets			(23,550	)			9,864
Change in Payables and Other Current Liabilities			1,171				(33,430	)
Change in Interest Payable and Income Taxes Receivable/Payable			(1,594	)			(6,878	)
Net Cash (Used in) Provided by Operating Activities			(22,740	)			21,881
Cash Flows from Investing Activities
Capital Expenditures			(17,676	)			(26,756	)
Proceeds from Disposal of Noncurrent Assets			619				840
Net (Increase) in Other Investments			(1,001	)			(2,834	)
Net Cash Used in Investing Activities			(18,058	)			(28,750	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash			3,251				—
Net Short-Term Borrowings			102,914				14,149
Proceeds from Issuance of Common Stock			55				7
Common Stock Issuance Expenses			(79	)			(17	)
Payments for Retirement of Common Stock			(262	)			(160	)
Proceeds from Issuance of Long-Term Debt			95				1
Short-Term and Long-Term Debt Issuance Expenses			(87	)			(71	)
Payments for Retirement of Long-Term Debt			(58,350	)			(982	)
Dividends Paid and Other Distributions			(10,938	)			(10,718	)
Net Cash Provided by Financing Activities			36,599				2,209
Effect of Foreign Exchange Rate Fluctuations on Cash			(233	)			207
Net Change in Cash and Cash Equivalents			(4,432	)			(4,453	)
Cash and Cash Equivalents at Beginning of Period			4,432				7,565
Cash and Cash Equivalents at End of Period		$	—			$	3,112

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 financial statements 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, 2009, 2008 and 2007 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Because of seasonal and other factors, the earnings for the three months ended March 31, 2010 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 of the notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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 Otter Tail Power Company’s (OTP’s) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 815-10-45-9. 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 23.9% for the three months ended March 31, 2010 and 29.2% for the three months ended March 31, 2009. 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 and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at any point in time during a contract, a projected loss for the entire contract is estimated and recognized.

The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

		March 31,				December 31,
(in thousands)		2010				2009
Costs Incurred on Uncompleted Contracts		$	328,954			$	400,577
Less Billings to Date			(295,379	)			(400,711	)
Plus Estimated Earnings Recognized			42,885				59,202
		$	76,460			$	59,068

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

		March 31,				December 31,
(in thousands)		2010				2009
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts		$	82,792			$	61,835
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts			(6,332	)			(2,767	)
		$	76,460			$	59,068

Costs and Estimated Earnings in Excess of Billings at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer, were $75,740,000 as of March 31, 2010 and $54,977,000 as of December 31, 2009. This amount is related to costs incurred on wind towers in the process of completion on major contracts under which the customer is not billed until towers are completed and ready for shipment.

Retainage
Accounts Receivable include amounts billed by the Company’s subsidiaries under contracts that have been retained by customers pending project completion of $7,846,000 on March 31, 2010 and $9,215,000 on December 31, 2009.

Sales of Receivables
DMI has a three-year, $40 million receivables purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement expires in March 2011. Accounts receivable sold totaled $10,800,000 in the first three months of 2010 compared with $38,800,000 in the first three months of 2009. Discounts, fees and commissions charged to operating expenses in the consolidated statements of income were $32,000 in the first three months of 2010 compared with $175,000 in the first three months of 2009. In compliance with guidance under ASC 860-20, Sales of Financial Assets, 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 guidance under ASC 605-50, Customer Payments and Incentives. 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 charged to revenue for the three month periods ended March 31, 2010 and 2009 were $60,000 and $145,000, respectively.

Supplemental Disclosures of Cash Flow Information

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Decreases in Accounts Payable Related to Capital Expenditures		$	(62	)		$	(2,191	)

Fair Value Measurements
The Company applies authoritative accounting guidance under ASC 820 which provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. ASC 820-10-35 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 hierarchy and examples of each level follow:

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 and may include complex and subjective models and forecasts.

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 March 31, 2010 and December 31, 2009:

March 31, 2010 (in thousands)		Level 1				Level 2				Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash		$	1,614			$	—
Forward Energy Contracts							11,200
Investments of Captive Insurance Company:
Corporate Debt Securities			8,358
U.S. Government Debt Securities			251
Total Assets		$	10,223			$	11,200
Liabilities:
Forward Energy Contracts		$	—			$	21,573
Total Liabilities		$	—			$	21,573

December 31, 2009 (in thousands)		Level 1				Level 2				Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash		$	731			$	—
Forward Energy Contracts							8,321
Investments of Captive Insurance Company:
Corporate Debt Securities			7,795
U.S. Government Debt Securities			253
Total Assets		$	8,779			$	8,321
Liabilities:
Forward Energy Contracts		$	—			$	14,681
Total Liabilities		$	—			$	14,681

Inventories
Inventories consist of the following:

		March 31,				December 31,
(in thousands)		2010				2009
Finished Goods		$	46,896			$	42,784
Work in Process			6,229				3,824
Raw Material, Fuel and Supplies			43,714				39,907
Total Inventories		$	96,839			$	86,515

Other Intangible Assets
The following table summarizes the components of the Company’s intangible assets at March 31, 2010 and December 31, 2009:

		Gross Carrying				Accumulated				Net Carrying				Amortization
March 31, 2010 (in thousands)		Amount				Amortization				Amount				Periods
Amortized Intangible Assets:
Covenants Not to Compete		$	1,854			$	1,747			$	107			3 — 5 years
Customer Relationships			26,982				4,013				22,969			15 — 25 years
Other Intangible Assets Including Contracts			2,319				1,752				567			5 — 30 years
Total		$	31,155			$	7,512			$	23,643
Nonamortized Intangible Assets:
Brand/Trade Name		$	9,887			$	—			$	9,887
December 31, 2009 (in thousands)
Amortized Intangible Assets:
Covenants Not to Compete		$	2,190			$	2,047			$	143			3 — 5 years
Customer Relationships			26,956				3,696				23,260			15 — 25 years
Other Intangible Assets Including Contracts			2,358				1,757				601			5 — 30 years
Total		$	31,504			$	7,500			$	24,004
Nonamortized Intangible Assets:
Brand/Trade Name		$	9,883			$	—			$	9,883

The amortization expense for these intangible assets was $383,000 for the three months ended March 31, 2010 compared with $417,000 for the three months ended March 31, 2009. The estimated annual amortization expense for these intangible assets for the next five years is $1,444,000 for 2010, $1,332,000 for 2011, $1,312,000 for 2012, $1,308,000 for 2013 and $1,308,000 for 2014.

Comprehensive Income

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Net Income		$	4,717			$	4,388
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gain (Loss)			488				(424	)
Amortization of Unrecognized Losses and Costs Related to Postretirement Benefit Programs			105				15
Unrealized Gain (Loss) on Available-for-Sale Securities			39				(55	)
Total Other Comprehensive Income (Loss)			632				(464	)
Total Comprehensive Income		$	5,349			$	3,924

New Accounting Standards

Consolidation of Variable Interest Entities—In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the ASC are effective for interim and annual periods beginning after November 15, 2009. The Company implemented the guidance on January 1, 2010 and the implementation did not have a material impact on its consolidated financial statements.

Accounting Standards Update (ASU) No. 2010-06 Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements, issued by the FASB in January 2010, updates the ASC to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the ASC contained in ASU No. 2010-06 were effective for interim and annual periods beginning after December 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after December 15, 2010. The implementation of applicable guidance from ASU No. 2010-06 on January 1, 2010 did not have a material impact on the Company’s consolidated financial statements, but did require additional fair value disclosures in footnotes to interim financial statements, similar to disclosures required with year-end financial statements.

2. 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 by the Company’s subsidiary, OTP. In addition, OTP is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

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

Manufacturing consists of businesses in the following manufacturing activities: production of wind towers, contract machining, metal parts stamping and fabrication, and production of waterfront equipment, material and handling trays and horticultural containers. These businesses have manufacturing facilities in Florida, Illinois, Minnesota, Missouri, North Dakota, Oklahoma 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, water, 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 four Canadian provinces.

The Company’s electric operations, including wholesale power sales, are operated by its wholly owned subsidiary, OTP, and its energy services operation is operated by a separate wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar).

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 one customer within the manufacturing segment that accounted for 13.6% of the Company’s consolidated revenues in 2009. No other single external customer accounts for 10% or more of the Company’s consolidated 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
		March 31,
		2010				2009
United States of America			96.5	%			98.4	%
Canada			2.6	%			0.7	%
All Other Countries (none greater than 1%)			0.9	%			0.9	%

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 month periods ended March 31, 2010 and 2009 and total assets by business segment as of March 31, 2010 and December 31, 2009 are presented in the following tables:

Operating Revenue

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Electric		$	91,086			$	88,541
Plastics			23,087				13,530
Manufacturing			78,578				96,019
Health Services			25,171				28,167
Food Ingredient Processing			18,915				20,086
Other Business Operations			26,302				31,895
Corporate Revenues and Intersegment Eliminations			(953	)			(999	)
Total		$	262,186			$	277,239

Interest Expense

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Electric		$	5,254			$	4,011
Plastics			363				200
Manufacturing			2,466				1,279
Health Services			245				96
Food Ingredient Processing			37				10
Other Business Operations			236				120
Corporate and Intersegment Eliminations			429				554
Total		$	9,030			$	6,270

Income Taxes

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Electric		$	4,898			$	1,771
Plastics			494				(1,647	)
Manufacturing			(265	)			(804	)
Health Services			(432	)			(13	)
Food Ingredient Processing			727				725
Other Business Operations			(1,426	)			(206	)
Corporate			(1,616	)			(1,208	)
Total		$	2,380			$	(1,382	)

Earnings Available for Common Shares

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Electric		$	7,621			$	8,342
Plastics			781				(2,458	)
Manufacturing			(157	)			(1,090	)
Health Services			(691	)			(73	)
Food Ingredient Processing			1,404				1,447
Other Business Operations			(2,164	)			(325	)
Corporate			(2,261	)			(1,639	)
Total		$	4,533			$	4,204

Total Assets

		March 31,				December 31,
(in thousands)		2010				2009
Electric		$	1,125,511			$	1,119,822
Plastics			79,591				70,380
Manufacturing			340,159				306,011
Health Services			63,845				58,164
Food Ingredient Processing			91,412				88,478
Other Business Operations			66,731				59,915
Corporate			48,712				51,908
Total		$	1,815,961			$	1,754,678

3. Rate and Regulatory Matters

Minnesota

General Rate Case—In an order issued by the Minnesota Public Utilities Commission (MPUC) on August 1, 2008 OTP was granted an increase in Minnesota retail electric rates of $3.8 million, or approximately 2.9%, which went into effect in February 2009. 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% was in effect from November 30, 2007 through January 31, 2009. Amounts refundable totaling $3.9 million had been recorded as a liability on the Company’s consolidated balance sheet as of December 31, 2008. An additional $0.5 million refund liability was accrued in January 2009. OTP refunded Minnesota customers the difference between interim and final rates, with interest, in March 2009. In June 2008, OTP deferred recognition of $1.5 million in rate case-related regulatory assessments and fees of outside experts and attorneys that are subject to amortization and recovery over a three-year period beginning in February 2009.

Capacity Expansion 2020 (CapX 2020) Mega Certificate of Need (CON) —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 CON for the three CapX 2020 345-kV transmission line projects began in July 2008 and continued into August 2008. On April 16, 2009 the MPUC approved the CON for the three 345-kV Group 1 CapX 2020 line projects (Fargo-St. Cloud, Brookings-Southeast Twin Cities, and Twin Cities-LaCrosse). The MPUC then voted to impose conditions pertaining to reserving line capacity for renewable energy sources on the Brookings line project. The MPUC reconsidered the original order regarding the conditions. The MPUC slightly modified the conditions on the Brookings line. As part of the CON approval, the MPUC accepted a CapX 2020 request to build the 345-kV lines for double-circuit capability to have two 345-kV transmission circuits on each structure. The current plan is to string only one circuit. The MPUC CON orders were appealed to the Minnesota Court of Appeals on October 9, 2009 and the appellate court’s determination is expected to be made in the fall of 2010. Route permit applications were filed in Minnesota for the Brookings project in late December 2008. The route permit for the Monticello to St. Cloud portion of the Fargo project was filed in April 2009 and is anticipated to be received in mid-2010. The Minnesota route permit for the St. Cloud to Fargo portion of the Fargo Project was filed on October 1, 2009. Portions of the projects would also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. After regulatory need is established and routing decisions are completed, construction will begin. The lines would be expected to be completed over a period of two to four years. Great River Energy and Xcel Energy are leading these projects, and OTP and eight other utilities are involved in permitting, building and financing. OTP is directly involved in two of these three 345-kV projects.

OTP serves as the lead utility in a fourth CapX 2020 Group 1 project, the Bemidji-Grand Rapids 230-kV line, which has an expected in-service date of 2012-2013. OTP filed an application for a CON for this fourth project on March 17, 2008. The Department of Commerce Office of Energy Security (MNOES) staff completed briefing papers regarding the Bemidji-Grand Rapids route permit application. The MNOES 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 CON and route permit proceedings be combined as requested. The MPUC met on June 26, 2008 to act on the MNOES staff recommendation. The MPUC agreed that the CON and route permit applications were complete. The MNOES subsequently recommended a determination that need for the line has been established. An environmental report for the CON was issued in April 2009. CON hearings were conducted on May 20 and May 21, 2009 and a summary of comments was issued on June 8, 2009. The CON was issued on July 9, 2009 and the written order received on July 14, 2009. The MNOES issued a draft environmental impact statement (EIS) in April 2010. Route hearings were held April 21-23, 2010. The MPUC is expected to determine the route for this line and, if appropriate, issue a route permit in the fall of 2010. A federal EIS also will be needed for this project.

Renewable Energy Standards, Conservation, Renewable Resource Riders and Transmission Riders—The state of Minnesota has a renewable energy standard which requires OTP 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. OTP has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. OTP has sufficient renewable energy resources available and in service to comply with the required 2016 level of the Minnesota renewable energy standard. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standards. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that 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. 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.

In an order issued on August 15, 2008, the MPUC approved OTP’s proposal to implement a Renewable Resource Cost Recovery Rider for its Minnesota jurisdictional portion of investment in qualifying renewable energy facilities. The rider enables OTP to recover from its Minnesota retail customers its investments in owned renewable energy facilities and provides for a return on those investments. The Minnesota Renewable Resource Adjustment (MNRRA) of $0.0019 per kilowatt-hour (kwh) was included on Minnesota customers’ electric service statements beginning in September 2008, reflecting cost recovery for OTP’s twenty-seven 1.5 megawatt (MW) wind turbines and collector system at the Langdon Wind Energy Center, which became fully operational in January 2008.

The MPUC approved OTP’s petition for a 2009 MNRRA in July 2009, which increased the MNRRA rate to provide cost recovery for its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008. This approval increased the 2009 MNRRA to $0.00415 per kwh for the recovery of $6.6 million through March 31, 2010—$4.0 million from August through December 2009 and $2.6 million from January through March 2010. The approval also granted OTP authority to recover over a 48-month period beginning in April 2010 accrued renewable resource recovery revenues that had not previously been recovered. OTP has recognized a regulatory asset of $5.9 million for revenues that are eligible for recovery through the rider but have not been billed to Minnesota customers as of March 31, 2010. On January 12, 2010, the MPUC issued an order finding OTP’s Luverne Wind Farm project eligible for cost recovery through the MNRRA. The 2010 annual MNRRA cost recovery filing was made on December 31, 2009 with a requested effective date of April 1, 2010. The MNOES has taken the position that OTP’s internal costs should be excluded from recovery under the MNRRA. OTP filed reply comments in opposition to the MNOES’s position. As of the date of this report on Form 10-Q, the MPUC has not rendered a decision on OTP’s petition for a 2010 MNRRA.

In addition to the Renewable Resource Cost Recovery Rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a CON proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or otherwise deemed eligible by the MPUC. Such transmission cost recovery riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s request for approval of a transmission cost recovery rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010. Beginning February 1, 2010, OTP’s transmission rider rate is reflected on Minnesota customer electric service statements at $0.00039 per kwh plus $0.035 per kW for large general service customers and $0.00007 per kwh for controlled service customers, $0.00025 per kwh for lighting customers, and $0.00057 per kwh for all other customers. As of March 31, 2010 OTP had accrued $0.3 million in revenues that are eligible for recovery through the rider but have not been billed. In a request for a revenue increase under general rates filed with the MPUC on April 2, 2010, OTP has requested recovery of its transmission investments currently being recovered through OTP’s Minnesota transmission rider rate. The transmission investments will continue to be recovered through OTP’s Minnesota transmission rider rate until the MPUC makes a decision on OTP’s general rate case.

North Dakota

General Rate Case—On November 3, 2008 OTP filed a general rate case in North Dakota requesting an overall revenue increase of approximately $6.1 million, or 5.1%, and an interim rate increase of approximately 4.1%, or $4.8 million annualized, that went into effect on January 2, 2009. In an order issued by the North Dakota Public Service Commission (NDPSC) on November 25, 2009 OTP was granted an increase in North Dakota retail electric rates of $3.6 million or approximately 3.0%, which went into effect in December 2009. The NDPSC order authorizing an interim rate increase requires OTP to refund North Dakota customers the difference between final and interim rates, with interest. OTP established a refund reserve for revenues collected under interim rates that exceeded the final rate increase. The refund reserve balance was $0.9 million as of December 31, 2009, which was refunded to North Dakota customers in January 2010. OTP deferred recognition of $0.5 million in rate case-related filing and administrative costs that are subject to amortization and recovery over a three year period beginning in January 2010.

Renewable Resource Cost Recovery Rider—On May 21, 2008 the NDPSC approved OTP’s request for a Renewable Resource Cost Recovery Rider to enable OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. The North Dakota Renewable Resource Cost Recovery Rider Adjustment (NDRRA) of $0.00193 per kwh was included on North Dakota customers’ electric service statements beginning in June 2008, and reflects cost recovery for OTP’s twenty-seven 1.5 MW wind turbines and collector system at the Langdon Wind Energy Center, which became fully operational in January 2008. The rider also allows OTP to recover costs associated with other new renewable energy projects as they are completed. OTP included investment costs and expenses related to its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008 in its 2009 annual request to the NDPSC to increase the amount of the NDRRA. An NDRRA of $0.0051 per kwh was approved by the NDPSC on January 14, 2009 and went into effect beginning with billing statements sent on February 1, 2009.

In a proceeding that was combined with OTP’s general rate case, the NDPSC reviewed whether to move the costs of the projects currently being recovered through the NDRRA into base rate cost recovery and whether to make changes to the rider. A settlement of the general rate case and the NDRRA reduced the NDRRA to $0.00369 for the period from December 1, 2009 until the effective date for the next annual NDRRA filing, requested to be April 1, 2010. Because the 2008 annual NDRRA filing was combined with the general rate case proceedings (concluded in November 2009), the 2009 annual filing to establish the 2010 NDRRA (which includes cost recovery for OTP’s investment in its Luverne Wind Farm project) was delayed until December 31, 2009, with a requested effective date of April 1, 2010. As of the date of this report on Form 10-Q, the NDPSC had not rendered a decision on OTP’s petition for a 2010 NDRRA.

OTP had not been deferring recognition of its renewable resource costs eligible for recovery under the NDRRA but had been charging those costs to operating expense since January 2008. After approval of the rider in May 2008, OTP accrued revenues related to its investment in renewable energy and for renewable energy costs incurred since January 2008 that are eligible for recovery through the NDRRA. Terms of the approved settlement provide for the recovery of accrued but unbilled NDRRA revenues over a period of 48 months beginning in January 2010. The Company’s March 31, 2010 consolidated balance sheet includes a regulatory asset of $0.9 million for revenues that are eligible for recovery through the NDRRA but have not been billed to North Dakota customers.

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. OTP requested recovery of such costs in its general rate case filed in November 2008, and was granted recovery of such costs by the NDPSC in its November 25, 2009 order.

CapX 2020 Request for Advance Determination of Prudence—On October 5, 2009 OTP filed an application for an advance determination of prudence with the NDPSC for its proposed participation in three of the four Group 1 projects (Fargo-St. Cloud, Brookings-Southeast Twin Cities, and Bemidji-Grand Rapids). An administrative law judge has been assigned to conduct a public hearing scheduled to begin May 24, 2010.

South Dakota

General Rate Case—On October 31, 2008 OTP filed a general rate case in South Dakota requesting an overall revenue increase of approximately $3.8 million, or 15.3%, which included, among other things, recovery of investments and expenses related to renewable resources in base rates. OTP increased rates by approximately 11.7% on a temporary basis beginning with electricity consumed on and after May 1, 2009, as allowed under South Dakota law. In an order issued by the South Dakota Public Utilities Commission (SDPUC) on June 30, 2009, OTP was granted an increase in South Dakota retail electric rates of $3.0 million or approximately 11.7%. OTP implemented final, approved rates in July 2009.

Federal

Revenue Sufficiency Guarantee (RSG) Charges—Since 2006, OTP has been a party to litigation before the FERC regarding the application of RSG charges to market participants who withdraw energy from the market or engage in financial-only, virtual sales of energy into the market or both. These litigated proceedings occurred in several electric rate and complaint dockets before the FERC and several of the FERC’s orders are on review before the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit).

On November 7, 2008 the FERC issued an order on rehearing and compliance in the RSG proceeding, reversing its determination in a prior order and stating that MISO should remove the volume of virtual supply offers of market participants—not physically withdrawing energy—from the denominator of the rate calculation from April 25, 2006 forward. MISO interpreted the order to mean that all virtual supply offers and deviations in the denominator of the rate calculation that do not ultimately pay the rate should be removed from April 1, 2005 (start of the Energy Market ) forward. On November 10, 2008 the FERC issued an order finding the current RSG rate unjust and unreasonable and accepting an interim rate that applied RSG charges to all virtual sales until such time as MISO makes a subsequent filing of the new RSG rate.

On May 6, 2009 the FERC issued an order on rehearing of the November 10, 2008 order. The May order relieved MISO from having to resettle RSG payments resulting from the FERC’s earlier decision to remove the words “actually withdraws energy” (AWE) from the RSG tariff provisions. Absent this relief (or waiver), the removal of the AWE language would have had two relevant impacts on the RSG charge: (1) it would tend to reduce the RSG rate because the rate denominator would include all virtual supply volumes and (2) it would impose RSG charges on all cleared virtual supply transactions. The waiver applies to the period August 10, 2007 through November 9, 2008. Beginning November 10, 2008, the MISO is obliged to resettle RSG charges by recalculating the RSG rate and impose RSG charges on all virtual supply transactions.

On June 12, 2009 the FERC issued an order on rehearing of the November 7, 2008 order. The June order, at a minimum, relieved MISO from having to resettle RSG payments resulting from any difference between the megawatt hours associated with virtual supply in the denominator of the RSG rate and the billing determinants associated with virtual supply transactions (VSO mismatch). This relief (or waiver) applies to the period April 25, 2006 through November 4, 2007. Since OTP would have had a payment obligation during this period associated with the virtual supply and other mismatches, the June order eliminates that payment obligation. However, the June order, like many of the other orders in this docket, is subject to appellate review and potential reversal. Beginning from November 5, 2007, MISO is obligated to resettle to correct the VSO mismatch. As of September 30, 2009, OTP had paid all its resettlement obligations determined and imposed by MISO. On August 7, 2009 the FERC issued an order requiring MISO’s RSG Task Force to develop a recommendation on any transactions that should be exempted from paying RSG charges. The RSG Task Force has completed its review and provided recommendations to the FERC. The Company does not know when these litigation proceedings will conclude.

Big Stone II Project

On June 30, 2005 OTP 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. On September 11, 2009 OTP announced its withdrawal—both as a participating utility and as the project’s lead developer—from Big Stone II, due to a number of factors. The broad economic downturn, a high level of uncertainty associated with proposed federal climate legislation and existing federal environmental regulations and challenging credit and equity markets made proceeding with Big Stone II and committing to approximately $400 million in capital expenditures untenable for OTP’s customers and the Company’s shareholders. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project.

As of March 31, 2010, OTP had incurred $13.2 million in costs related to this project that it believes are probable of recovery in future rates and has deferred recognition of these costs as operating expenses pending determination of recoverability by the state and federal regulatory commissions that approve OTP’s rates. In filings made on December 14, 2009, OTP requested from its three state commissions authority to reflect these costs on its books as a regulatory asset through the use of deferred accounting, pending a determination on the recoverability of the costs. OTP has requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010, and thereafter requested withdrawal of its December 14, 2009 request for deferred accounting as duplicative of the issues presented in the rate case. The SDPUC approved OTP’s request for deferred accounting treatment on February 9, 2010. OTP will request recovery of the South Dakota portion of its Big Stone II development costs over a five-year period in its next general rate case filing in South Dakota, expected to be filed in the second quarter of 2010.

In a hearing held on May 5, 2010, the NDPSC reviewed a settlement agreement filed on April 23, 2010 between the NDPSC Advocacy Staff, OTP and the North Dakota Large Industrial Energy Group in the matter of OTP’s applications for a determination of prudence to discontinue participation in the Big Stone II generating plant and authority to use deferred accounting. The terms of the settlement agreement indicate that OTP’s discontinuation of participation in the project was prudent and OTP should be authorized to recover the portion of costs it incurred related to the Big Stone II generation project. The North Dakota portion of Big Stone II generation and transmission costs under consideration pursuant to the settlement agreement is approximately $5.1 million. The settlement agreement is on file with the NDPSC. The NDPSC will evaluate the settlement agreement along with requested supplemental information in a working session yet to be scheduled before rendering a decision in this matter.

If Minnesota, North Dakota or South Dakota jurisdictions eventually deny recovery of all or any portion of these deferred costs, such costs would be subject to expense in the period they are deemed unrecoverable.

4. Regulatory Assets and Liabilities

As a regulated entity OTP accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation.

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

		March 31,				December 31,
(in thousands)		2010				2009
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits		$	77,992			$	78,871
Deferred Marked-to-Market Losses			13,309				7,614
Unrecovered Project Costs — Big Stone II			13,184				12,982
Minnesota Renewable Resource Rider Accrued Revenues			5,904				5,324
Deferred Income Taxes			5,595				5,441
Debt Reacquisition Premiums			4,037				3,051
Deferred Conservation Improvement Program Costs			2,079				1,908
Accumulated ARO Accretion/Depreciation Adjustment			1,908				1,808
General Rate Case Recoverable Expenses			1,519				1,693
MISO Schedule 16 and 17 Deferred Administrative Costs — ND			998				1,091
North Dakota Renewable Resource Rider Accrued Revenues			872				566
South Dakota — Asset-Based Margin Sharing Shortfall			406				330
Minnesota Transmission Rider Accrued Revenues			344				420
Deferred Holding Company Formation Costs			234				248
MISO Schedule 16 and 17 Deferred Administrative Costs — MN			183				252
Plant Acquisition Costs			7				18
Accrued Cost-of-Energy (Refund) Revenue			(1,243	)			1,175
Total Regulatory Assets		$	127,328			$	122,792
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs — Net of Salvage		$	59,447			$	58,937
Deferred Income Taxes			4,796				4,965
Deferred Marked-to-Market Gains			284				224
Other Regulatory Liabilities			154				148
Total Regulatory Liabilities		$	64,681			$	64,274
Net Regulatory Asset Position		$	62,647			$	58,518

The regulatory asset related to the unrecognized transition obligation, prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses 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 and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

All Deferred Marked-to-Market Gains and Losses recorded as of March 31, 2010 are related to forward purchases of energy scheduled for delivery through December 2013.

Unrecovered Project Costs — Big Stone II are costs incurred by OTP related to its participation in the planned construction of a 500- to 600-megawatt generating unit at its Big Stone Plant site. On September 11, 2009 OTP announced its withdrawal from participation in the Big Stone II project due to a number of factors. OTP believes the costs it incurred during its participation in the project are probable of recovery in future rates and has deferred recognition of these costs as operating expenses pending determination of recoverability by the state and federal regulatory commissions that approve OTP’s rates. No recovery period has been established for the recovery of these deferred costs as OTP is in the initial phase of seeking recovery of these costs

through the regulatory process. If OTP is denied recovery of any portion of these deferred costs, such costs would be subject to expense in the period they are deemed unrecoverable.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 and 2009 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of March 31, 2010. Minnesota Renewable Resource Rider Accrued Revenues are expected to be recovered over the next 48 months.

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC 740, Income Taxes.

Debt Reacquisition Premiums included in Unamortized Debt Expense are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 23 years.

Deferred Conservation Program Costs represent mandated conservation expenditures and incentives recoverable through retail electric rates over the next 15 months.

The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

General Rate Case Recoverable Expenses will be recovered over the next 49 months.

MISO Schedule 16 and 17 Deferred Administrative Costs — ND will be recovered over the next 32 months.

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 and 2009 renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2010. North Dakota Renewable Resource Rider Accrued Revenues are expected to be recovered over the next 45 months.

South Dakota — Asset-Based Margin Sharing Shortfall represents a difference in OTP’s South Dakota share of actual profit margins on wholesale sales of electricity from company-owned generating units and estimated profit margins from those sales that were used in determining current South Dakota retail electric rates. Net shortfalls or excess margins accumulated annually will be subject to recovery or refund through future retail rate adjustments in South Dakota in the following year.

Minnesota Transmission Rider Accrued Revenues are expected to be recovered over the next 9 months.

Deferred Holding Company Formation Costs will be amortized over the next 51 months.

MISO Schedule 16 and 17 Deferred Administrative Costs — MN will be recovered over the next 8 months.

Plant Acquisition Costs will be amortized over the next 2 months.

The Accrued Cost-of-Energy (Refund) is netted against Accrued Utility and Cost-of-Energy Revenues and will be credited to retail electric customers over the next 17 months.

The Accumulated Reserve for Estimated Removal Costs — Net of Salvage is reduced as actual removal costs are incurred.

Other Regulatory Liabilities includes: 1) a portion of profit margins on wholesales sales of purchased power subject to refund to South Dakota customers through future retail rate adjustments and 2) a deferred gain on the sale of utility property that will be paid to Minnesota retail electric customers over the next 24 years.

If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its 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 guidance under ASC 980 ceases.

5. Forward Contracts Classified as Derivatives

Electricity Contracts

All of OTP’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. OTP’s objective in entering into forward contracts for the purchase and sale of energy is to optimize the use of its generating and transmission facilities and leverage its knowledge of wholesale energy markets in the region to maximize financial returns for the benefit of both its customers and shareholders. OTP’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. OTP also enters into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales.

As of March 31, 2010 OTP had recognized, on a pretax basis, $2,652,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. The market prices used to value OTP’s forward contracts for the purchases and sales of electricity and electricity generating capacity are determined by survey of counterparties or brokers used by OTP’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. These basis spreads are determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into level 2 of the fair value hierarchy set forth in ASC 820-10-35.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of March 31, 2010 and December 31, 2009, and the change in the Company’s consolidated balance sheet position from December 31, 2009 to March 31, 2010:

		March 31,				December 31,
(in thousands)		2010				2009
Current Asset – Marked-to-Market Gain		$	11,200			$	8,321
Regulatory Asset – Deferred Marked-to-Market Loss			13,309				7,614
Total Assets			24,509				15,935
Current Liability – Marked-to-Market Loss			(21,573	)			(14,681	)
Regulatory Liability – Deferred Marked-to-Market Gain			(284	)			(224	)
Total Liabilities			(21,857	)			(14,905	)
Net Fair Value of Marked-to-Market Energy Contracts		$	2,652			$	1,030

		Year-to-Date
(in thousands)		March 31, 2010
Fair Value at Beginning of Year		$	1,030
Less: Amount Realized on Contracts Entered into in 2009 and Settled in 2010			126
Changes in Fair Value of Contracts Entered into in 2009			—
Net Fair Value of Contracts Entered into in 2009 at End of Period			904
Changes in Fair Value of Contracts Entered into in 2010			1,748
Net Fair Value End of Period		$	2,652

The $2,652,000 in recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on March 31, 2010 is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

		2nd Quarter				3rd Quarter				4th Quarter
(in thousands)		2010				2010				2010				2011				2012				Total
| | | | | |
Net Gain		$	1,209			$	721			$	81			$	320			$	321			$	2,652

Realized and unrealized net gains on forward energy contracts of $1,825,000 for the three months ended March 31, 2010 and $1,034,000 for the three months ended March 31, 2009 are included in electric operating revenues on the Company’s consolidated statements of income.

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. OTP’s credit risk with its largest counterparty on delivered and marked-to-market forward contracts as of March 31, 2010 was $1,062,000. As of March 31, 2010 OTP had a net credit risk exposure of $2,038,000 from six counterparties with investment grade credit ratings. OTP had no exposure at March 31, 2010 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 $2,038,000 credit risk exposure includes net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after March 31, 2010. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Mark-to-market losses of $1,699,000 on certain of OTP’s derivative energy contracts included in the $21,573,000 derivative liability on March 31, 2010 are covered by deposited funds. Certain other of OTP’s derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request immediate and ongoing full overnight collateralization on contracts in net liability positions. The aggregate fair value of all forward energy derivative contracts with credit-risk-related contingent features that are in a liability position on March 31, 2010 is $11,063,000, for which OTP has posted $9,730,000 as collateral in the form of offsetting gain positions on other contracts with its counterparties under master netting agreements. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2010, OTP would have been required to post $1,333,000 in additional collateral to its counterparties. The remaining derivative liability balance of $8,811,000 relates to mark-to-market losses on contracts that have no ratings triggers or deposit requirements.

Fuel Contracts

In order to limit its exposure to fluctuations in future prices of natural gas, IPH entered into contracts with a fuel supplier in December 2009 for firm purchases of natural gas to cover portions of its anticipated natural gas needs in Ririe, Idaho through August 2010 at fixed prices. These contracts qualify for the normal purchase exception to mark-to-market accounting under ASC 815-10-15.

Foreign Currency Exchange Forward Windows

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 in 2008. Each monthly contract was for the exchange of $400,000 U.S. dollars for the amount of Canadian dollars stated in each contract. IPH’s Canadian subsidiary also entered into forward contracts for the exchange of U.S. dollars into Canadian dollars in July 2009. Each monthly contract was for the exchange of $200,000 U.S. dollars for the amount of Canadian dollars stated in each contract. All contracts were settled as of December 31, 2009.

(in thousands)		Settlement Periods		USD				CAD
Contracts Entered into in July 2008		January 2009 — July 2009		$	2,800			$	2,918
Contracts Entered into in October 2008		January 2009 — October 2009		$	4,000			$	5,001
Contracts Entered Into in July 2009		August 2009 — December 2009		$	1,000			$	1,163

These contracts were derivatives subject to mark-to-market accounting. IPH did 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. IPH settled these contracts during their stated settlement periods and used the proceeds to pay its Canadian liabilities when they came due. These contracts did not qualify for hedge accounting treatment

because the timing of their settlements did not coincide with the payment of specific bills or contractual obligations. The foreign currency exchange forward contracts outstanding as of March 31, 2009 were valued and marked to market on March 31, 2009 based on quoted exchange values on March 31, 2009. Realized and unrealized net losses on IPH’s foreign currency exchange forward windows of $144,000 for the three months ended March 31, 2009, are included in Other Income on the Company’s consolidated statements of income.

6. Common Shares and Earnings Per Share

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2009 through March 31, 2010:

Common Shares Outstanding, December 31, 2009			35,812,280
Issuances:
Executive Officer Stock Performance Awards			34,768
Stock Options Exercised			2,800
Retirements:
Shares Withheld for Individual Income Tax Requirements			(11,495	)
Common Shares Outstanding, March 31, 2010			35,838,353

Earnings Per Share

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

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the quarters ended March 31, 2010 and 2009:

Quarter Ended March 31,		Options Outstanding				Range of Exercise Prices
2010			390,210			$	24.93 – $31.34
2009			420,460			$	24.93 – $31.34

Common Stock Distribution Agreement

On March 17, 2010, the Company entered into a Distribution Agreement (the Agreement) with J.P. Morgan Securities Inc. (JPMS). Pursuant to the terms of the Agreement, the Company may offer and sell its common shares from time to time through JPMS, as the Company’s distribution agent for the offer and sale of the shares, up to an aggregate sales price of $75,000,000.

Under the Agreement, the Company will designate the minimum price and maximum number of shares to be sold through JPMS on any given trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the NASDAQ Global Select Market at market prices or as otherwise agreed with JPMS. The Company may also agree to sell shares to JPMS, as principal for its own account, on terms agreed by the Company and JPMS in a separate agreement at the time of sale. JPMS will receive from the Company a commission of 2% of the gross sales price per share for any shares sold through it as the Company’s distribution agent under the Agreement.

The Company is not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement, as amended.

7. Share-Based Payments

The Company has five share-based payment programs. No new stock awards were granted under these programs in the first quarter of 2010. As of March 31, 2010 the remaining unrecognized compensation expense related to stock-based compensation was approximately $5.0 million (before income taxes) which will be amortized over a weighted-average period of 1.9 years.

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three months ended March 31, 2010 and 2009 are presented in the table below:

		Three months ended
		March 31,
(in thousands)		2010				2009
Employee Stock Purchase Plan (15% discount)		$	69			$	90
Restricted Stock Granted to Directors			140				111
Restricted Stock Granted to Employees			118				91
Restricted Stock Units Granted to Employees			60				121
Stock Performance Awards Granted to Executive Officers			222				435
Totals		$	609			$	848

9. Commitments and Contingencies

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 alleged certain violations of the Prevention of Significant Deterioration and New Source Performance Standards (NSPS) provisions of the Clean Air Act (CAA) and certain violations of the South Dakota State Implementation Plan (South Dakota SIP). The action further alleged 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 CAA and the South Dakota SIP. The Sierra Club alleged 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 sought both declaratory and injunctive relief to bring the defendants into compliance with the CAA 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 was and is being operated in compliance with the CAA and the South Dakota SIP.

The defendants filed a motion to dismiss the Sierra Club complaint on August 12, 2008. On March 31, 2009 and April 6, 2009, the U.S. District Court for the District of South Dakota (Northern Division) issued a Memorandum and Order and Amended Memorandum and Order, respectively, granting the defendants’ motion to dismiss the Sierra Club complaint. On April 17, 2009 the Sierra Club filed a motion for reconsideration of the Amended Memorandum Opinion and Order. The Sierra Club motion was opposed by the defendants. The Sierra Club motion for reconsideration was denied on July 22, 2009. On July 30, 2009 the Sierra Club filed a notice of appeal to the 8th U.S. Circuit Court of Appeals. The briefing schedule calls for the appellant to submit its brief by mid-October, for appellees to submit their brief by mid-November and for the appellant to submit its reply brief by the end of November. On October 13, 2009, the United States Department of Justice filed a motion seeking a 30-day extension of the time to file an amicus brief in support of the Sierra Club’s position. The Court of Appeals granted this motion, as well as the appellees’ subsequent joint motion with the Sierra Club, extending the time to file the appellees’ brief and the Sierra Club’s reply brief. Briefing was complete on January 22, 2010 on filing of the Sierra Club’s reply brief. Oral arguments before the Court of Appeals are scheduled for May 11, 2010. The ultimate outcome of this matter cannot be determined at this time.

Federal Power Act Complaint

On August 29, 2008 Renewable Energy System Americas, Inc. (RES), a developer of wind generation, and PEAK Wind Development, LLC (PEAK Wind), a group of landowners in Barnes County, North Dakota, filed a complaint with the FERC alleging that OTP and Minnkota Power Cooperative, Inc. (Minnkota) had acted together in violation of the Federal Power Act (FPA) to deny RES and PEAK Wind access to the Pillsbury Line, an interconnection facility which Minnkota owns to interconnect generation projects being developed by OTP and NextEra Energy Resources, Inc. (fka FPL Energy, Inc.)

(NextEra). RES and PEAK Wind asked that (1) the FERC order Minnkota to interconnect its Glacier Ridge project to the Pillsbury Line, or in the alternative, (2) the FERC direct MISO to interconnect the Glacier Ridge project to the Pillsbury Line. RES and Peak Wind also requested that OTP, Minnkota and NextEra pay any costs associated with interconnecting the Glacier Ridge Project to the MISO transmission system which would result from the interconnection of the Pillsbury Line to the Minnkota transmission system, and that the FERC assess civil penalties against OTP. OTP answered the complaint on September 29, 2008, denying the allegations of RES and PEAK Wind and requesting that the FERC dismiss the complaint. On October 14, 2008, RES and PEAK Wind filed an answer to OTP’s answer and, restated the allegations included in the initial complaint. RES and PEAK Wind also added a request that the FERC rescind both OTP’s waiver from the FERC Standards of Conduct and its market-based rate authority. On October 28, 2008, OTP filed a reply, denying the allegations made by RES and PEAK Wind in its answer. By order issued on December 19, 2008, the FERC set the complaint for hearing and established settlement procedures. A formal settlement agreement was filed with the FERC requesting approval of the settlement and withdrawal of the complaint. On May 6, 2010 the FERC issued an order approving the settlement and terminating the proceeding. The settlement did not have a material impact on OTP’s financial position, results of operations or cash flows.

Other

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 March 31, 2010 will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of March 31, 2010 and December 31, 2009:

										Restricted due to
						In Use on				Outstanding Letters				Available on				Available on
(in thousands)		Line Limit				March 31, 2010				of Credit				March 31, 2010				December 31, 2009
| | | | |
Otter Tail Corporation Credit Agreement		$	200,000			$	47,000			$	14,295			$	138,705			$	179,755
OTP Credit Agreement1			170,000				63,499				250				106,251				167,735
Total		$	370,000			$	110,499			$	14,545			$	244,956			$	347,490

The Otter Tail Corporation Credit Agreement was amended and restated effective May 4, 2010. See note 17 — Subsequent Events for further details.

The following table provides a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2010:

														Otter Tail
										Otter Tail				Corporation
(in thousands)		OTP				Varistar				Corporation				Consolidated
| | | |
Lines of Credit		$	63,499							$	47,000			$	110,499
Senior Unsecured Notes 6.63%, due December 1, 2011			90,000												90,000
Pollution Control Refunding Revenue Bonds, Variable, 3.00% at March 31, 2010, due December 1, 2012			10,400												10,400
9.000% Notes, due December 15, 2016										$	100,000				100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017			33,000												33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017			5,125												5,125
Senior Unsecured Note 8.89%, due November 30, 2017											50,000				50,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022			30,000												30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022			20,390												20,390
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027			42,000												42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037			50,000												50,000
Obligations of Varistar Corporation — Various up to 13.31% at March 31, 2010						$	6,471								6,471
Total		$	280,915			$	6,471			$	150,000			$	437,386
Less:
Current Maturities			—				916				—				916
Unamortized Debt Discount			—				386				6				392
Total Long-Term Debt		$	280,915			$	5,169			$	149,994			$	436,078
Total Short-Term and Long-Term Debt (with current maturities)		$	344,414			$	6,085			$	196,994			$	547,493

11. Class B Stock Options of Subsidiary

As of March 31, 2010 there were 772 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $391,000. All 772 outstanding options were “in-the-money” on March 31, 2010. A valuation of IPH Class B common shares in the first quarter of 2010 indicated a fair value of $2,485.60 per share. The book value of outstanding IPH Class B common share options on March 31, 2010 is based on an IPH Class B common share value of $2,085.88 per share.

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
		March 31,
(in thousands)		2010				2009
Service Cost—Benefit Earned During the Period		$	1,247			$	1,133
Interest Cost on Projected Benefit Obligation			3,030				2,975
Expected Return on Assets			(3,400	)			(3,448	)
Amortization of Prior-Service Cost			170				181
Amortization of Net Actuarial Loss			495				5
Net Periodic Pension Cost		$	1,542			$	846

The Company did not make a contribution to its pension plan in the three months ended March 31, 2010 and is not currently required to make a contribution in 2010.

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

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Service Cost—Benefit Earned During the Period		$	165			$	188
Interest Cost on Projected Benefit Obligation			418				424
Amortization of Prior-Service Cost			18				18
Amortization of Net Actuarial Loss			119				96
Net Periodic Pension Cost		$	720			$	726

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

		Three Months Ended
		March 31,
(in thousands)		2010				2009
Service Cost—Benefit Earned During the Period		$	425			$	301
Interest Cost on Projected Benefit Obligation			775				753
Amortization of Transition Obligation			187				187
Amortization of Prior-Service Cost			50				53
Amortization of Net Actuarial Loss			188				1
Effect of Medicare Part D Expected Subsidy			(500	)			(297	)
Net Periodic Postretirement Benefit Cost		$	1,125			$	998

13. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Long-Term Debt—The fair value of the Company’s long-term debt is estimated based on the current rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value.

		March 31, 2010								December 31, 2009
		Carrying								Carrying
(in thousands)		Amount				Fair Value				Amount				Fair Value
Cash and Short-Term Investments		$	—			$	—			$	4,432			$	4,432
Long-Term Debt			(436,078	)			(456,784	)			(436,170	)			(457,907	)

15. Income Taxes

The Company’s effective income tax rates for the three months ended March 31, 2010 and 2009 were approximately 33.5% and (46.0%), respectively. Income taxes in the first quarter of 2010 included a charge of $1.7 million related to the enactment of new federal health care legislation in March 2010 which resulted in the reversal of previously recognized deferred tax assets due to the elimination of the tax deduction related to the Medicare Part D retiree drug subsidy, offset by $1.8 million in production tax credits and North Dakota wind energy credits related to OTP’s wind turbines. The reduction from the federal statutory rate in the first quarter 2009 is mainly due to the recognition of production tax credits and North Dakota wind energy tax credits totaling $2.1 million.

The Company recognizes PTCs as wind energy is generated and sold based on a per kwh rate prescribed in applicable federal statutes, which may differ significantly from amounts computed, on a quarterly basis, using an overall effective income tax rate

anticipated for the full year. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years. The Company utilizes this method of recognizing PTCs for specific reasons, including that PTCs are an integral part of the financial viability of most wind projects and a fundamental component of such wind projects’ results of operations.

17. Subsequent Events

Stock Incentive Awards—On April 12, 2010 the Company’s Board of Directors granted 26,180 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan), payable in common shares on April 8, 2014, the date the units vest. The grant date fair value of each restricted stock unit was $17.76 per share based on the market value of the Company’s common stock on April 12, 2010, discounted for the value of the dividend exclusion over the four-year vesting period.

On April 12, 2010 the Company’s Board of Directors granted 24,800 shares of restricted stock to the Company’s nonemployee directors and 31,600 shares of restricted stock to the Company’s executive officers, including OTP’s president, under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2011 through 2014 and are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was $21.835 per share, the average market price on the date of grant.

On April 12, 2010 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 146,800 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, 2010 through December 31, 2012. The aggregate target share award is 73,400 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 target amount common shares projected to be awarded was $20.97 per share, as determined under a Monte Carlo simulation valuation method. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC 718-10-25-18, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

Federal Income Tax Refund—On May 3, 2010 the Company received a federal income tax refund of $42.3 million related to the carry-back of 2009 net operating losses for tax purposes to prior years.

2010 Minnesota General Rate Case Filing—OTP filed a general rate case in Minnesota on April 2, 2010 requesting an interim rate increase of approximately 3.8% or $5.0 million in annual revenue, effective June 1, 2010, and a final overall rate increase of approximately 8.0% or $10.6 million in annual revenue. If approved by the MPUC, interim rates will remain in effect for all Minnesota customers until the MPUC makes a final determination on the request, which is expected to occur in 2011. If final rates are lower than interim rates, OTP will refund Minnesota customers the difference with interest.

Credit Agreement Renewal—On May 4, 2010 the Company entered into a $200 million Second Amended and Restated Credit Agreement (the Credit Agreement) with the banks named therein, including U.S. Bank National Association, a national banking association, as administrative agent for the Banks and as Lead Arranger, Bank of America, N.A. and JPMorgan Chase Bank, National Association, as Co-Syndication Agents, and KeyBank National Association, as Documentation Agent. The Credit Agreement amends and restates the Company’s $200 million credit agreement dated as of December 23, 2008, and is an unsecured revolving credit facility that the Company can draw on to support its nonelectric operations. Borrowings under the Credit Agreement bear interest at LIBOR plus 3.25%, subject to adjustment based on the Company’s senior unsecured credit ratings. The Credit Agreement expires on May 4, 2013. The Credit Agreement contains a number of restrictions on the Company and the businesses of Varistar and its material subsidiaries, including restrictions on their ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Credit Agreement also contains affirmative covenants and events of default. The Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Credit Agreement are guaranteed by Varistar and its material subsidiaries. Outstanding letters of credit issued by the Company under the Credit Agreement can reduce the amount available for borrowing under the line by up to $50 million. The Credit Agreement has an accordion feature whereby the line can be increased to $250 million as described in the Credit Agreement.

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 months ended March 31, 2010 and 2009, followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2010 and our expectations for the remainder of 2010.

Comparison of the Three Months Ended March 31, 2010 and 2009

Consolidated operating revenues were $262.2 million for the three months ended March 31, 2010 compared with $277.2 million for the three months ended March 31, 2009. Operating income was $16.0 million for the three months ended March 31, 2010 compared with $8.6 million for the three months ended March 31, 2009. The Company recorded diluted earnings per share of $0.13 for the three months ended March 31, 2010 compared to $0.12 for the three months ended March 31, 2009.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended March 31, 2010 and 2009 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:

Intersegment Eliminations (in thousands)		March 31, 2010				March 31, 2009
Operating Revenues:
Electric		$	72			$	62
Nonelectric			881				937
Cost of Goods Sold			751				840
Other Nonelectric Expenses			202				159

Electric

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Retail Sales Revenues		$	81,013			$	79,055			$	1,958				2.5
Wholesale Revenues – Company Generation			3,992				4,404				(412	)			(9.4	)
Net Revenue – Energy Trading Activity			2,007				1,393				614				44.1
Other Revenues			4,074				3,689				385				10.4
Total Operating Revenues		$	91,086			$	88,541			$	2,545				2.9
Production Fuel			20,909				18,659				2,250				12.1
Purchased Power – System Use			12,056				17,373				(5,317	)			(30.6	)
Other Operation and Maintenance Expenses			28,322				26,930				1,392				5.2
Depreciation and Amortization			10,037				8,988				1,049				11.7
Property Taxes			2,474				2,490				(16	)			(0.6	)
Operating Income		$	17,288			$	14,101			$	3,187				22.6

The increase in retail sales revenues mainly is due to the following: (1) a $1.7 million increase in revenues related to a general rate increase in South Dakota which began in May 2009, (2) a $1.4 million increase in Minnesota resource recovery and transmission rider revenues, (3) a $0.9 million increase in North Dakota resource recovery rider revenues, (4) a $0.5 million increase in Minnesota Conservation Investment Program (CIP) surcharge revenues, and (5) an additional Minnesota interim rate refund accrual of $0.5 million in the first quarter of 2009, partially offset by (6) a $2.1 million reduction in Fuel Clause Adjustment revenues related to a decrease in fuel and purchased power costs incurred to serve retail customers, and (7) a 2.3% decrease in retail kilowatt-hour (kwh) sales related to a 9.6% reduction in heating-degree-days between the quarters.

Wholesale electric revenues from company-owned generation decreased as a result of an 11.8% decrease in wholesale kwh sales, partially offset by a 2.7% increase in the average price per kwh sold. Net revenue from energy trading activity, including net mark-to-market gains on forward energy contracts, increased mainly as a result of an increase in net mark-to-market gains recognized on forward purchases and sales of electricity entered into in the first quarter of 2010 and scheduled for settlement in the second and third quarters of 2010. The increase in other electric revenues reflects a $0.2 million increase in revenues from contracted services and a $0.2 million increase in transmission services related revenue.

The increase in fuel costs is due to a 10.2% increase in kwhs generated from Otter Tail Power Company’s (OTP’s) fuel-fired plants combined with a 1.7% increase in the price of fuel per kwh generated. The decrease in purchased power – system use is due to a 45.3% decrease in kwhs purchased for retail sales, partially offset by a 26.9% increase in the cost per kwh purchased. The decrease in kwh purchases for system use is due to an increase in kwhs generated at company-owned plants in combination with a decrease in retail kwh sales.

The increase in other operation and maintenance expenses is due to higher Minnesota CIP recognized program costs, increased dues and subscription expenses, wage increases for employees under union contracts and increases in regulatory filing fees, insurance costs and storm repair expenses.

The increase in depreciation expense is mainly due to the addition of 33 wind turbines at the Luverne Wind Farm that were placed in service in September 2009.

Plastics

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Operating Revenues		$	23,087			$	13,530			$	9,557				70.6
Cost of Goods Sold			19,490				15,352				4,138				27.0
Operating Expenses			1,197				1,375				(178	)			(12.9	)
Depreciation and Amortization			781				716				65				9.1
Operating Income (Loss)		$	1,619			$	(3,913	)		$	5,532				141.4

Operating revenues for the plastics segment increased as result of a 42.4% increase in pounds of pipe sold combined with a 20.2% increase in the price per pound of polyvinyl chloride (PVC) pipe sold. The increase in costs of goods sold was related to the increase in pounds of pipe sold partially offset by a 10.9% decrease in the cost per pound of pipe sold. The increased profitability between the quarters was also impacted by the sell-off of higher priced finished goods inventory in the first quarter of 2009. The decrease in operating expenses related to reductions in salary and benefit costs.

Manufacturing

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Operating Revenues		$	78,578			$	96,019			$	(17,441	)			(18.2	)
Cost of Goods Sold			61,958				79,535				(17,577	)			(22.1	)
Operating Expenses			8,469				10,046				(1,577	)			(15.7	)
Product Recall and Testing Costs			—				1,766				(1,766	)			—
Depreciation and Amortization			5,821				5,358				463				8.6
Operating Income (Loss)		$	2,330			$	(686	)		$	3,016				439.7

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

	•		Revenues at DMI Industries, Inc. (DMI) decreased $8.9 million as production activity was reduced to match customer delivery schedules.
	•		Revenues at BTD Manufacturing, Inc. (BTD) decreased $4.7 million due to a decrease in sales volume. However, improved productivity on work completed and increased prices for scrap metal contributed to a $0.7 million increase in operating income at BTD.
	•		Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $0.5 million due to increased sales of horticultural products.
	•		Revenues at ShoreMaster, Inc. (ShoreMaster) decreased $4.3 million mainly due to a lower volume of sales of commercial products but also due to reduced sales of residential products.

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

	•		Cost of goods sold at DMI decreased $8.7 million as a result of decreased production levels and productivity improvements.
	•		Cost of goods sold at BTD decreased $5.1 million as a result of decreased sales volume and because the first quarter of 2009 included a $1.1 million reduction in the price of finished goods inventory.
	•		Cost of goods sold at T.O. Plastics increased $0.1 million as a result of increased sales of horticultural products.
	•		Cost of goods sold at ShoreMaster decreased $3.9 million mainly due to the decrease in sales of commercial products and $0.9 million in additional costs incurred on a commercial project in the first quarter of 2009.

The net decrease in operating expenses, including product recall and testing costs, in our manufacturing segment is due to the following:

	•		Operating expenses at DMI decreased $0.6 million as a result of decreases in employee benefit costs and reductions in insurance expenses related to safety improvements. The decrease also reflects a $0.2 million loss on an asset sale in the first quarter of 2009.
	•		Operating expenses at BTD decreased $0.5 million. In the first quarter of 2009, BTD spent $0.6 million on implementation of a management program designed to improve productivity across the organization. No similar costs were incurred in the first quarter of 2010.
	•		Operating expenses at T.O. Plastics increased $0.2 million mainly due to increased salary and benefit costs related to new hires in engineering and sales positions.
	•		Operating expenses at ShoreMaster decreased $2.5 million, reflecting a $1.8 million reduction in product recall and testing costs, a $0.4 million reduction in bad debt expense and a $0.4 million decrease in salary and payroll tax expenses. ShoreMaster’s first quarter 2009 expenses included $1.4 million in costs related to the recall of certain trampoline products and $0.4 million in costs to test imported products for lead/phthalate content.

Depreciation expense increased as a result of 2009 capital additions, mainly at DMI and BTD.

Health Services

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Operating Revenues		$	25,171			$	28,167			$	(2,996	)			(10.6	)
Cost of Goods Sold			20,366				22,137				(1,771	)			(8.0	)
Operating Expenses			4,616				5,089				(473	)			(9.3	)
Depreciation and Amortization			1,104				990				114				11.5
Operating Loss		$	(915	)		$	(49	)		$	(866	)			—

A $3.6 million decrease in revenues from scanning and other related services related to a 9.1% decrease in scans performed combined with a 5.5% decrease in revenue per scan was partially offset by a $0.6 million increase in revenue from equipment sales and servicing. The decrease in cost of goods sold was directly related to the decreases in sales revenue. The decrease in operating expenses includes a $0.2 million gain on sale of an asset in the first quarter of 2010 and a $0.2 million reduction in sales and marketing salaries and expenses. The imaging side of the business continues to be affected by less-than-optimal utilization of certain imaging assets. The increase in depreciation expense reflects an increase in owned equipment related to the purchase of assets coming off lease.

Food Ingredient Processing

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Operating Revenues		$	18,915			$	20,086			$	(1,171	)			(5.8	)
Cost of Goods Sold			14,428				15,982				(1,554	)			(9.7	)
Operating Expenses			942				812				130				16.0
Depreciation and Amortization			1,167				1,041				126				12.1
Operating Income		$	2,378			$	2,251			$	127				5.6

The decrease in food ingredient processing revenues is due to a 0.4% decrease in pounds of product sold, combined with a 5.5% decrease in the price per pound of product sold. The decrease in cost of goods sold reflects a 9.4% decrease in the cost per pound of product sold mainly due to a decrease in raw potato costs. The increase in operating expenses is mainly due to salary and benefit cost increases.

Other Business Operations

		Three Months Ended
		March 31,												%
(in thousands)		2010				2009				Change				Change
Operating Revenues		$	26,302			$	31,895			$	(5,593	)			(17.5	)
Cost of Goods Sold			16,421				20,795				(4,374	)			(21.0	)
Operating Expenses			12,517				10,861				1,656				15.2
Depreciation and Amortization			697				624				73				11.7
Operating Loss		$	(3,333	)		$	(385	)		$	(2,948	)			(765.7	)

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

	•		Revenues at Foley Company decreased $6.3 million due to a decrease in volume of completed projects due to unfavorable winter weather conditions in the first quarter of 2010 compared to the first quarter of 2009.
	•		Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, decreased $0.9 million as a result of a reduction in work volume.

•

Revenues at E.W. Wylie Corporation (Wylie) increased $1.6 million as a result of a 34.7% increase in miles driven by company-owned and owner-operated trucks, partially offset by a 6.8% reduction in revenue per mile.

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

	•		Cost of goods sold at Foley Company decreased $3.7 million, mainly in the area of subcontractor costs as Foley’s work volume was down in the first quarter of 2010.
	•		Cost of goods sold at Aevenia decreased $0.6 million, mainly due to a decrease in labor costs related to a reduction of jobs in progress.

A reduction in construction activity due to the economic recession and related credit constraints has led to excess capacity in the construction industry, resulting in a highly competitive bidding environment and lower margins on available work.

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

	•		Operating expenses at Foley Company increased $0.2 million between the quarters mainly for salaries and insurance.
	•		Operating expenses at Aevenia increased $0.1 million between the quarters.
	•		Operating expenses at Wylie increased $1.4 million between the quarters related to the increase in miles driven by company-owned and owner-operated trucks. Subcontractor expenses increased $0.7 million as a result of a 57.1% increase in miles driven by owner-operated trucks. Labor costs increased by $0.5 million as a result of a 26.1% increase in miles driven by company-owned trucks. Equipment rental costs increased by $0.2 million due to the leasing of additional equipment.