a6714582.htm

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)

(in thousands, except share data)	March 31, 2011		December 31, 2010

LIABILITIES AND EQUITY

Current Liabilities
Short-Term Debt	$	116,976	$	79,490
Current Maturities of Long-Term Debt		683		604
Accounts Payable		109,834		117,911
Accrued Salaries and Wages		16,379		20,252
Accrued Taxes		11,642		11,957
Derivative Liabilities		19,633		17,991
Other Accrued Liabilities		11,142		9,546
Liabilities of Discontinued Operations		18,961		19,026
Total Current Liabilities		305,250		276,777

Pensions Benefit Liability		74,506		73,538
Other Postretirement Benefits Liability		42,991		42,372
Other Noncurrent Liabilities		21,182		21,043

Commitments (note 9)

Deferred Credits
Deferred Income Taxes		163,318		162,208
Deferred Tax Credits		44,199		44,945
Regulatory Liabilities		67,162		66,416
Other		469		556
Total Deferred Credits		275,148		274,125

Capitalization
Long-Term Debt, Net of Current Maturities		436,064		434,812

Class B Stock Options of Subsidiary		525		525

Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value; Outstanding 2011 and 2010 – 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, 2011—36,002,739 Shares; 2010—36,002,739 Shares		180,014		180,014
Premium on Common Shares		251,505		251,919
Retained Earnings		193,244		198,443
Accumulated Other Comprehensive Income		1,052		1,487
Total Common Equity		625,815		631,863

Total Capitalization		1,077,904		1,082,700

Total Liabilities and Equity	$	1,796,981	$	1,770,555
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)	2011		2010

Operating Revenues
Electric	$	91,525	$	91,381
Nonelectric		195,156		152,305
Total Operating Revenues		286,681		243,686

Operating Expenses
Production Fuel - Electric		19,577		20,909
Purchased Power - Electric System Use		12,377		12,056
Electric Operation and Maintenance Expenses		28,708		28,466
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)		155,709		117,484
Other Nonelectric Expenses		35,626		29,738
Depreciation and Amortization		19,113		18,584
Property Taxes - Electric		2,409		2,474
Total Operating Expenses		273,519		229,711

Operating Income		13,162		13,975

Other Income		675		13
Interest Charges		9,489		9,022
Income from Continuing Operations Before Income Taxes		4,348		4,966
Income Taxes – Continuing Operations		414		1,653
Income from Continuing Operations		3,934		3,313
Income from Discontinued Operations net of Income Taxes of $1,112 and $727, respectively		1,762		1,404
Net Income		5,696		4,717
Preferred Dividend Requirements		184		184
Earnings Available for Common Shares	$	5,512	$	4,533

Average Number of Common Shares Outstanding—Basic		35,876,853		35,720,571
Average Number of Common Shares Outstanding—Diluted		36,081,426		35,939,759

Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	0.10	$	0.09
Discontinued Operations		0.05		0.04
		0.15		0.13
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	0.10	$	0.09
Discontinued Operations		0.05		0.04
		0.15		0.13

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)	2011			2010
Cash Flows from Operating Activities
Net Income	$	5,696		$	4,717
Adjustments to Reconcile Net Income to Net Cash (Used in) Provided
by Operating Activities:
Income from Discontinued Operations		(1,762	)		(1,404	)
Depreciation and Amortization		19,113			18,584
Deferred Tax Credits		(659	)		(679	)
Deferred Income Taxes		4,099			6,863
Change in Deferred Debits and Other Assets		6,266			15
Change in Noncurrent Liabilities and Deferred Credits		90			2,346
Allowance for Equity (Other) Funds Used During Construction		(116	)		--
Change in Derivatives Net of Regulatory Deferral		(59	)		(1,622	)
Stock Compensation Expense – Equity Awards		452			610
Other—Net		(120	)		(52	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(23,737	)		(20,890	)
Change in Inventories		(1,787	)		(8,345	)
Change in Other Current Assets		(747	)		(23,425	)
Change in Payables and Other Current Liabilities		(3,869	)		2,837
Change in Interest Payable and Income Taxes Receivable/Payable		1,306			(710	)
Net Cash Provided by (Used in) Continuing Operations		4,166			(21,155	)
Net Cash Provided by (Used in) Discontinued Operations		2,795			(1,585	)
Net Cash Provided by (Used in) Operating Activities		6,961			(22,740	)
Cash Flows from Investing Activities
Capital Expenditures		(23,981	)		(17,687	)
Proceeds from Disposal of Noncurrent Assets		984			619
Net (Increase) in Other Investments		(598	)		(1,001	)
Net Cash Used in Investing Activities - Continuing Operations		(23,595	)		(18,069	)
Net Cash Provided by Investing Activities - Discontinued Operations		137			11
Net Cash Used in Investing Activities		(23,458	)		(18,058	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(10,030	)		244
Net Short-Term Borrowings		37,486			102,914
Proceeds from Issuance of Common Stock		--			55
Common Stock Issuance Expenses		--			(79	)
Payments for Retirement of Common Stock		--			(262	)
Proceeds from Issuance of Long-Term Debt		1,500			95
Short-Term and Long-Term Debt Issuance Expenses		(686	)		(87	)
Payments for Retirement of Long-Term Debt		(170	)		(58,350	)
Dividends Paid and Other Distributions		(11,041	)		(10,938	)
Net Cash Provided by Financing Activities - Continuing Operations		17,059			33,592
Net Cash (Used in) Provided by Financing Activities - Discontinued Operations		(88	)		3,007
Net Cash Provided by Financing Activities		16,971			36,599
Cash and Cash Equivalents at Beginning of Period – Discontinued Operations		--			(609	)
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations		(288	)		(233	)
Net Change in Cash and Cash Equivalents		186			(5,041	)
Cash and Cash Equivalents at Beginning of Period		--			5,041
Cash and Cash Equivalents at End of Period	$	186		$	--
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, 2010, 2009 and 2008 included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Because of seasonal and other factors, the earnings for the three months ended March 31, 2011 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, 2010.

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) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with 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 in the Company’s Wind Energy, Manufacturing and Construction segments 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 28.9% for the three months ended March 31, 2011 and 23.9% for the three months ended March 31, 2010. The method used to determine the progress of completion is based on the ratio of labor hours incurred to total estimated labor hours at the Company’s wind tower manufacturer and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.

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

	March 31,			December 31,
(in thousands)	2011			2010
Costs Incurred on Uncompleted Contracts	$	406,085		$	460,125
Less Billings to Date		(365,443	)		(430,471	)
Plus Estimated Earnings Recognized		20,628			31,231
	$	61,270		$	60,885

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)	2011			2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	66,269		$	67,352
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(4,999	)		(6,467	)
	$	61,270		$	60,885

Costs and Estimated Earnings in Excess of Billings at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer, were $56,178,000 as of March 31, 2011 and $58,990,000 as of December 31, 2010. 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 $11,638,000 on March 31, 2011 and $11,848,000 on December 31, 2010.

Sales of Receivables

DMI is a party to a $40 million receivables purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement, originally scheduled to expire in March 2011, was extended for one year by DMI in February 2011. The discount rate for the one-year extension was increased to 3-month LIBOR plus 4%. Accounts receivable sold totaled $19,048,000 in the first three months of 2011 compared with $10,800,000 in the first three months of 2010. Discounts, fees and commissions charged to operating expenses in the consolidated statements of income were $118,000 in the first three months of 2011 compared with $32,000 in the first three months of 2010. 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.

Supplemental Disclosures of Cash Flow Information

	Three Months Ended
	March 31,
(in thousands)	2011		2010
Increases in Accounts Payable Related to Capital Expenditures	$	1,047	$	41

Fair Value Measurements

The Company follows ASC 820, Fair Value Measurements and Disclosures, for recurring fair value measurements. ASC 820 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 are as follows:

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

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

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation 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, 2011 and December 31, 2010:

March 31, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash	$	699	$	--
Forward Gasoline Purchase Contracts		249
Forward Energy Contracts				5,480
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				15,027
Investments of Captive Insurance Company:
Corporate Debt Securities		8,692
Total Assets	$	9,640	$	20,507
Liabilities:
Forward Energy Contracts	$	--	$	19,633
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				242
Total Liabilities	$	--	$	19,875

December 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	$	800	$	--
Forward Gasoline Purchase Contracts		58
Forward Energy Contracts				6,875
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				12,054
Investments of Captive Insurance Company:
Corporate Debt Securities		8,467
Total Assets	$	9,325	$	18,929
Liabilities:
Forward Energy Contracts	$	--	$	17,991
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				175
Total Liabilities	$	--	$	18,166

Reclassifications and Changes to Presentation

The Company’s consolidated balance sheet as of December 31, 2010, and consolidated income statement and consolidated statement of cash flows for the three months ended March 31, 2010 reflect the reclassifications of the assets and liabilities, operating results and cash flows of Idaho Pacific Holdings, Inc. (IPH) to discontinued operations as a result of a second quarter 2011 decision to sell IPH. The Company reached an agreement to sell IPH on May 6, 2011. The reclassifications had no impact on the Company’s total assets, consolidated net income or cash flows for the three months ended March 31, 2010.

In 2011 management reported Minnesota Conservation Improvement Program (MNCIP) incentives in Operating Revenues – Electric rather than Other Income as they had been classified prior to 2011. The Company has corrected this classification resulting in an increase in Operating Revenues and Operating Income and a decrease in Other Income of $362,000 for the three months ended March 31, 2010. The correction had no impact on the Company’s net income, total assets, or operating cash flows for the three months ended March 31, 2010.

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2011		2010
Finished Goods	$	30,938	$	29,113
Work in Process		8,219		7,171
Raw Material, Fuel and Supplies		41,984		43,070
Total Inventories	$	81,141	$	79,354

Goodwill

The following table summarizes changes to goodwill by business segment during 2011:

(in thousands)	Balance December 31, 2010		Impairments			Balance (net of impairments) December 31, 2010		Adjustments to Goodwill in 2011		Balance (net of impairments) March 31, 2011
Electric	$	240	$	(240	)	$	--	$	--	$	--
Wind Energy		6,959		--			6,959		--		6,959
Manufacturing		24,445		(12,259	)		12,186		--		12,186
Construction		7,630		--			7,630		--		7,630
Plastics		19,302		--			19,302		--		19,302
Health Services		23,665		--			23,665		--		23,665
Total	$	82,241	$	(12,499	)	$	69,742	$	--	$	69,742

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at March 31, 2011 and December 31, 2010:

March 31, 2011 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	2,599	$	14,212	15 – 25 years
Covenants Not to Compete		1,704		1,688		16	3 – 5 years
Other Intangible Assets Including Contracts		930		892		38	5 – 30 years
Total	$	19,445	$	5,179	$	14,266
Nonamortized Intangible Assets:
Brand/Trade Name	$	1,790	$	--	$	1,790
December 31, 2010 (in thousands)
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	2,388	$	14,423	15 – 25 years
Covenants Not to Compete		1,704		1,676		28	3 – 5 years
Other Intangible Assets Including Contracts		930		891		39	5 – 30 years
Total	$	19,445	$	4,955	$	14,490
Nonamortized Intangible Assets:
Brand/Trade Name	$	1,790	$	--	$	1,790

The amortization expense for these intangible assets was $224,000 for the three months ended March 31, 2011 compared with $283,000 for the three months ended March 31, 2010. The estimated annual amortization expense for these intangible assets for the next five years is $874,000 for 2011, $895,000 for 2012, $931,000 for 2013, $931,000 for 2014 and $931,000 for 2015.

Comprehensive Income

	Three Months Ended
	March 31,
(in thousands)	2011			2010
Net Income	$	5,696		$	4,717
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gain		445			488
Amortization of Unrecognized Losses and Costs Related to Postretirement Benefit Programs		(870	)		105
Unrealized (Loss) Gain on Available-for-Sale Securities		(10	)		39
Total Other Comprehensive Income (Loss)		(435	)		632
Total Comprehensive Income	$	5,261		$	5,349

2. Segment Information

The Company's businesses have been classified into six segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. These businesses reach customers in all 50 states and international markets. The six segments are: Electric, Wind Energy, Manufacturing, Construction, Plastics and Health Services.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by 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. Additionally, the electric segment includes Otter Tail Energy Services Company (OTESCO), which provides technical and engineering services, wind farm site development and energy efficient lighting primarily in North Dakota and Minnesota.

Wind Energy consists of two businesses: a steel fabrication company primarily involved in the production of wind towers sold in the United States and Canada, with manufacturing facilities in North Dakota, Oklahoma and Ontario, Canada, and a trucking company headquartered in West Fargo, North Dakota, specializing in flatbed and heavy-haul services and operating in 49 states and six Canadian provinces. Prior to the realignment of the Company’s business segments, the wind tower production company was included in Manufacturing and the trucking company was included in Other Business Operations.

Manufacturing consists of businesses in the following manufacturing activities: 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 and Missouri and sell products primarily in the United States.

Construction consists of businesses involved in residential, commercial and industrial electric contracting and construction of fiber optic and electric distribution systems, water, wastewater and HVAC systems primarily in the central United States. Construction operations were included in Other Business Operations prior to the realignment of the Company’s business segments.

Plastics consists of businesses producing polyvinyl chloride (PVC) pipe in the upper Midwest and Southwest regions of 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 equipment and technical staff to various medical institutions located throughout the United States.

Food Ingredient Processing is no longer a reportable segment as a result of the sale of IPH on May 6, 2011. The results of operations, financial position and cash flows of IPH are reported as discontinued operations in the Company’s consolidated financial statements.

OTP and OTESCO are wholly owned subsidiaries 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 had no single external customer that accounted for 10% or more of the Company’s consolidated revenues in 2010. Substantially all of the Company’s long-lived assets are within the United States except for 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,
	2011			2010
United States of America		98.7	%		97.2	%
Canada		1.2	%		2.7	%
All Other Countries (none greater than 1%)		0.1	%		0.1	%

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, 2011 and 2010 and total assets by business segment as of March 31, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2011			2010
Electric	$	91,596		$	91,452
Wind Energy		61,597			49,398
Manufacturing		56,313			38,031
Construction		37,515			17,774
Plastics		18,478			23,087
Health Services		22,495			25,171
Corporate Revenues and Intersegment Eliminations		(1,313	)		(1,227	)
Total	$	286,681		$	243,686

Interest Expense

	Three Months Ended
	March 31,
(in thousands)	2011		2010
Electric	$	5,088	$	5,270
Wind Energy		1,914		1,321
Manufacturing		1,306		1,247
Construction		220		118
Plastics		363		363
Health Services		399		245
Corporate and Intersegment Eliminations		199		458
Total	$	9,489	$	9,022

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2011			2010
Electric	$	2,600		$	4,834
Wind Energy		(2,798	)		(7	)
Manufacturing		1,530			(618	)
Construction		(210	)		(1,001	)
Plastics		(241	)		494
Health Services		409			(432	)
Corporate		(876	)		(1,617	)
Total	$	414		$	1,653

Earnings Available for Common Shares

	Three Months Ended
	March 31,
(in thousands)	2011			2010
Electric	$	11,142		$	7,491
Wind Energy		(8,111	)		33
Manufacturing		2,267			(735	)
Construction		(325	)		(1,489	)
Plastics		(374	)		781
Health Services		572			(691	)
Corporate		(1,421	)		(2,261	)
Discontinued Operations		1,762			1,404
Total	$	5,512		$	4,533

Total Assets

	March 31,		December 31,
(in thousands)	2011		2010
Electric	$	1,094,549	$	1,106,261
Wind Energy		195,574		175,852
Manufacturing		153,971		144,272
Construction		64,500		60,978
Plastics		76,993		73,508
Health Services		74,180		75,898
Corporate		46,947		43,102
Discontinued Operations		90,267		90,684
Total	$	1,796,981	$	1,770,555

3. Rate and Regulatory Matters

Minnesota

2010 General Rate Case Filing—OTP filed a general rate case on April 2, 2010 requesting an 8.01% increase with a 3.8% interim rate request. On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates and setting interim rates. The MPUC approved a 3.8% interim rate increase to be effective with customer usage on and after June 1, 2010. The MPUC held a hearing to decide on the issues in the rate case on March 25, 2011 and issued a written order on April 25, 2011. OTP calculated the impact of its understanding of the MPUC’s oral decision prior to receiving the written order and estimated there would be an interim rate refund of approximately $3.8 million. Based on its estimate, OTP accrued a $2.3 million refund liability in the first quarter of 2011 related to revenue that had been billed under interim rates from June 1, 2010 through March 31, 2011. OTP expects the refund to be distributed to Minnesota customers

during the fourth quarter of 2011. The MPUC’s written order included recovery of Big Stone II costs over five years (see discussion below), inclusion of wind farm assets in base rates, transfer of cost recovery from the MNCIP tracker to base rates, and inclusion of fuel costs and revenues related to asset-based wholesale sales of electricity in the Minnesota fuel clause adjustment (FCA). Pursuant to the order, OTP’s allowed rate of return on rate base will increase from 8.33% to 8.61% and its allowed rate of return on equity will increase from 10.43% to 10.74%. OTP's rates of return will be based on a capital structure of 48.28% long term debt and 51.72% common equity. OTP intends to request reconsideration on certain issues and the MPUC has 60 days to reconsider its order after requests for reconsideration are submitted.

OTP has a regulatory asset of $4.8 million for revenues that are eligible for recovery through the Minnesota Renewable Resource Adjustment (MNRRA) rider that have not been billed to Minnesota customers as of March 31, 2011. Except for the balance of this regulatory asset, the recovery of MNRRA costs will be moved to base rates late in 2011 as part of the MPUC’s order in OTP’s 2010 general rate case.

In OTP’s 2010 general rate case, the MPUC approved the transfer of transmission costs currently being recovered through OTP’s Minnesota Transmission Cost Recovery (TCR) rider to recovery in base rates. The transmission investments will continue to be recovered through OTP’s Minnesota TCR rider rate until final rates go into effect at the conclusion of the general rate case. OTP filed a request for an update to its Minnesota TCR rider rate on October 5, 2010. Comments and reply comments have been filed but the MPUC has not yet scheduled a hearing on the request.

North Dakota

Transmission Cost Recovery Rider—North Dakota law 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 North Dakota Public Service Commission (NDPSC) in its November 25, 2009 order. OTP filed a request for an initial North Dakota TCR rider with the NDPSC on April 29, 2011.

South Dakota

2010 General Rate Case Filing—On August 20, 2010 OTP filed a general rate case with the South Dakota Public Utilities Commission (SDPUC) requesting an overall revenue increase of approximately $2.8 million, or just under 10.0%, which includes, among other things, recovery of investments and expenses related to renewable resources. On September 28, 2010 the SDPUC suspended OTP’s proposed rates for a period of 180 days to allow time to review OTP’s proposal. On January 19, 2011 OTP submitted a proposal to use current rate design to implement an interim rate in South Dakota to be effective on and after February 17, 2011. On January 26, 2011 OTP submitted an amended proposal to also use a lower interim rate increase than originally proposed. At its February 1, 2011 meeting, the SDPUC approved OTP’s request to implement interim rates using current rate design and the lower interim increase to be effective on and after February 17, 2011.

A joint motion for approval of a settlement stipulation allowing the inclusion of OTP’s Luverne Wind Farm assets in its South Dakota rate base was filed and brought before the SDPUC on April 19, 2011. Final rates will be effective as of June 1, 2011. Interim rates will remain in effect until final rates begin and there will not be any interim rate refund because interim rates are the same amount as the final rates. In the oral decision made by the SDPUC, the SDPUC approved a revenue increase of $643,000. OTP’s allowed rate of return on rate base in South Dakota will be 8.50% based on a capital structure of 47.0% long term debt and 53.0% common equity.

Transmission Cost Recovery Rider—South Dakota law 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 submitted a request for an initial South Dakota TCR rider to the SDPUC on November 5, 2010. The South Dakota TCR request is scheduled for hearing on May 17, 2011.

Capacity Expansion 2020 (CapX2020)

Fargo–Monticello 345 kiloVolt (kV) Project, Brookings–Southeast Twin Cities 345 kV Project and Twin Cities–LaCrosse 345 kV Project—On April 16, 2009 the MPUC approved the Certificates of Need (CONs) for the three 345 kV Group 1 CapX2020 line projects (Fargo-Monticello, Brookings-Southeast Twin Cities, and Twin Cities-LaCrosse).

The route permit application for the Monticello to St. Cloud portion of the Fargo project was filed in April 2009. The MPUC approved the route permit application and issued a written order on July 12, 2010. Required permits from the Minnesota Department of Transportation, Minnesota Department of Natural Resources and the U.S. Army Corps of Engineers were received in 2010. A Transmission Capacity Exchange Agreement, allocating transmission capacity rights to owners across the Monticello to St. Cloud portion of the project, was accepted by the Federal Energy Regulatory Commission (FERC) in the third quarter of 2010.

The Minnesota route permit application for the St. Cloud to Fargo portion of the Fargo project was filed on October 1, 2009. The MPUC is expected to make a determination on the route permit application in the second quarter of 2011. Minnesota State Environmental Impact Statement (EIS) scoping meetings were held in September 2010 and public hearings were held in November 2010. On October 8, 2010, OTP submitted its application for a Certificate of Public Convenience and Necessity (CPCN) from the NDPSC for the North Dakota portion of the Fargo–Monticello 345 kV project. The NDPSC approved the CPCN in January 2011. The application for North Dakota Certificate of Corridor Compatibility was filed on December 30, 2010.

The Minnesota route permit application for the Brookings project was filed in the fourth quarter of 2008. On July 15, 2010 the MPUC voted to approve most of the Brookings route permit application. On September 15, 2010 the MPUC approved a route permit for five of six project line segments, with the exception of the line segment that crosses the Minnesota River. Additional Evidentiary Hearings were held regarding the line segment crossing the Minnesota River, and the Administrative Law Judge issued a report in December 2010. The MPUC approved the final line segment for the project on February 3, 2011.

An application for a South Dakota facility route permit was filed with the SDPUC on November 22, 2010. The SDPUC conducted a public hearing in January 2011 and a South Dakota route permit is expected to be approved in the second quarter of 2011.

Bemidji–Grand Rapids 230 kV Project—OTP serves as the lead utility for the CapX2020 Bemidji-Grand Rapids 230-kV project, which has an expected in-service date of late 2012 or early 2013. The MPUC approved the CON for this project on July 9, 2009. A route permit application was filed with the MPUC in the second quarter of 2008 for the Bemidji-Grand Rapids project. On October 28, 2010 the MPUC approved the route permit application for the project. The joint state and federal EIS was published by the federal agencies on September 7, 2010, and the project’s Transmission Capacity Exchange Agreement was accepted and approved by the FERC in the third quarter of 2010. On March 25, 2011, the Leech Lake Band of Ojibwe (LLBO) submitted a petition to MPUC, requesting the revocation or suspension of the project’s route permit. The request is based on the LLBO’s allegation that it has jurisdiction to require the project to obtain its permission to cross through the historical boundaries of the LLBO Reservation. The owners of the Bemidji project, including OTP, have filed reply comments in opposition to the LLBO’s request. On April 25, 2011, the Bemidji project owners filed a declaratory judgment complaint in the U.S. District Court for Minnesota against the LLBO. The federal court action seeks a declaratory judgment that no consent from the LLBO is required for the Project through the LLBO reservation boundaries since the project is located exclusively on non LLBO lands.

CapX2020 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-Monticello, Brookings-Southeast Twin Cities, and Bemidji-Grand Rapids). An administrative law judge conducted an evidentiary hearing on the application in May 2010. On October 6, 2010 the NDPSC adopted an order approving a settlement between OTP and intervener NDPSC advocacy staff, and issuing an advance determination of prudence to OTP for participation in the three Group 1 projects. The order is subject to a number of terms and conditions in addition to the settlement agreement, including the provision of additional information on the eventual resolution of cost allocation issues relevant to the Brookings-Southeast Twin Cities project and its associated impact on North Dakota. On April 29, 2011, OTP filed its compliance filing with the NDPSC, seeking the NDPSC’s determination of continued prudence for OTP’s investment in the Brookings Project.

Big Stone Air Quality Control System

The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant is subject to Best Available Retrofit Technology (BART) requirements of the Clean Air Act (CAA), based on air dispersion modeling indicating that Big Stone’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan. Under the U.S. Environmental Protection Agency’s (EPA) regional haze regulations, South Dakota has developed and submitted its implementation plan and associated implementing rules to EPA on January 11, 2011. Under the South Dakota Implementation Plan, and its implementing rules that became effective in December 2010, the Big Stone Plant must install and operate a new BART compliant air quality control system to reduce emissions as expeditiously as practicable, but no later than five years after the EPA’s approval of South Dakota’s implementation plan. Although studies and evaluations are continuing, the current project cost is estimated to be approximately $490 million (OTP’s share would be $264 million). On January 14, 2011 OTP filed a petition asking the MPUC for advance determination of prudence for the design, construction and operation of the BART compliant air quality control system at Big Stone Plant attributable to serving OTP’s Minnesota customers. The Big Stone Plant is currently operating within all presently applicable federal and state air quality and emission standards.

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. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project.

OTP 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. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period expected to begin in October 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers (which excludes $3,246,000 of project transmission-related costs) was $3,199,000. Because the MPUC denied OTP an investment return on these deferred costs over the 60-month recovery period, the recoverable amount has been discounted to its present value of $2,758,000, in accordance with ASC 980, Regulated Operations, accounting requirements.

On December 30, 2010 OTP filed a request for an extension of the Minnesota Route Permit for the Big Stone transmission facilities. The request asks to extend the deadline for filing a CON for these transmission facilities until March 17, 2013. The April 25, 2011 MPUC order instructed OTP to transfer the $3,246,000 Minnesota share of Big Stone II transmission costs to Construction Work in Progress (CWIP) and to create a tracker account through which any over or under recoveries could be accumulated for refund or recovery determination in future rate cases as a regulatory liability or asset. If determined eligible for recovery under the FERC-approved MISO regional transmission tariff, the Minnesota portion of Big Stone II transmission costs and accumulated Allowance for Funds Used During Construction (AFUDC) will receive rate base treatment and recovery through the FERC-approved MISO regional transmission rates. Any amounts over or under collected through MISO rates will be reflected in the tracker account.

OTP requested recovery of the South Dakota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in South Dakota on August 20, 2010. In the first quarter of 2011, the SDPUC approved recovery of the South Dakota portion of Big Stone II generation development costs totaling approximately $1.0 million from South Dakota ratepayers over a ten-year period beginning in February 2011 with the implementation of interim rates. OTP will be allowed to earn a return on the amount subject to recovery over the ten-year recovery period. Therefore, the South Dakota settlement amount is not discounted. OTP transferred the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates.

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,		Recovery/
(in thousands)	2011			2010		Refund Period
Regulatory Assets - Current:
Accrued Cost-of-Energy Revenue	$	(68	)	$	2,387	17 months
Regulatory Assets – Long Term:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	71,628		$	74,156	see below
Deferred Marked-to-Market Losses		15,027			12,054	48 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		7,289			6,655	27 months
Minnesota Renewable Resource Rider Accrued Revenues		4,836			6,834	36 months
Big Stone II Unrecovered Project Costs – North Dakota		3,052			3,460	28 months
Debt Reacquisition Premiums		2,858			3,107	258 months
Big Stone II Unrecovered Project Costs – Minnesota		2,758			6,445	66 months
Deferred Income Taxes		2,453			5,785	asset lives
Accumulated ARO Accretion/Depreciation Adjustment		2,325			2,218	asset lives
General Rate Case Recoverable Expenses		1,451			1,773	35 months
North Dakota Renewable Resource Rider Accrued Revenues		1,272			2,415	33 months
Big Stone II Unrecovered Project Costs – South Dakota		987			1,419	118 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		624			717	20 months
South Dakota – Asset-Based Margin Sharing Shortfall		494			501	11 months
Minnesota Transmission Rider Accrued Revenues		252			34	21 months
Deferred Holding Company Formation Costs		179			193	39 months
Total Regulatory Assets – Long Term	$	117,485		$	127,766
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	62,132		$	61,740	asset lives
Deferred Income Taxes		4,148			4,289	asset lives
Minnesota Transmission Rider Accrued Refund		436			--	see below
Deferred Marked-to-Market Gains		242			175	53 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		127			128	273 months
South Dakota – Nonasset-Based Margin Sharing Excess		77			84	21 months
Total Regulatory Liabilities	$	67,162		$	66,416
Net Regulatory Asset Position	$	50,255		$	63,737

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, 2011 are related to forward purchases of energy scheduled for delivery through August 2015.

Deferred Conservation Program Costs & Accrued Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 through 2011 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of March 31, 2011.

Big Stone II Unrecovered Project Costs – North Dakota are the North Dakota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 258 months.

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

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.

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

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2011.

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

South Dakota – Asset-Based Margin Sharing Shortfall represents differences 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 asset-based margin sharing accumulated shortfalls will be subject to recovery or refund through future retail rate adjustments in South Dakota.

Minnesota Transmission Rider Accrued Revenues are expected to be recovered from Minnesota retail electric customers over 12 months beginning in January 2012.

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

No schedule has been set for the return of the March 31, 2011 Minnesota Transmission Rider Accrued Refund balance.

South Dakota – Nonasset-Based Margin Sharing Excess represents 25% of OTP’s South Dakota share of actual profit margins on nonasset-based wholesale sales of electricity. The excess margins accumulated annually will be subject to refund through future retail rate adjustments in South Dakota in the following year.

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, 2011 OTP had recognized, on a pretax basis, $632,000 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 and CME Globex. 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, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to March 31, 2011:

(in thousands)	March 31, 2011			December 31, 2010
Current Asset – Marked-to-Market Gain	$	5,480		$	6,875
Regulatory Asset – Deferred Marked-to-Market Loss		15,027			12,054
Total Assets		20,507			18,929
Current Liability – Marked-to-Market Loss		(19,633	)		(17,991	)
Regulatory Liability – Deferred Marked-to-Market Gain		(242	)		(175	)
Total Liabilities		(19,875	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	632		$	763

(in thousands)	Year-to-Date March 31, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(79	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(17	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		--
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(32	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		635
Changes in Fair Value of Contracts Entered into in 2011		(3	)
Net Fair Value End of Period	$	632

The $632,000 in recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on March 31, 2011 is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)		2nd Quarter 2011				3rd Quarter 2011				4th Quarter 2011				2012				Total
Net Gain		$	99			$	109			$	103			$	321			$	632

Realized and unrealized net (losses)/gains on forward energy contracts of ($8,000) for the three months ended March 31, 2011 and $1,825,000 for the three months ended March 31, 2010 are included in electric operating revenues on the Company’s consolidated statements of income.

OTP’s credit risk with its largest counterparty on delivered and marked-to-market forward contracts as of March 31, 2011 was $378,000. As of March 31, 2011 OTP had a net credit risk exposure of $661,000 from eight counterparties with investment grade credit ratings and one counterparty that has not been rated by an external credit rating agency but has been evaluated internally and assigned an internal credit rating equivalent to investment grade. OTP had no exposure at March 31, 2011 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 $661,000 credit risk exposure included 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, 2011. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Mark-to-market losses of $250,000 on certain OTP derivative energy contracts included in the $19,633,000 derivative liability on March 31, 2011 are covered by deposited funds. Certain other OTP 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 the immediate deposit of cash to cover contracts in net liability positions. The aggregate fair value of all forward energy derivative contracts with credit-risk-related contingent features that were in a liability position on March 31, 2011 was $5,381,000, for which OTP had posted $5,131,000 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 had been triggered on March 31, 2011, OTP would have been required to provide $0 in additional cash to its counterparties. The remaining derivative liability balance of $14,252,000 relates to mark-to-market losses on contracts that have no ratings triggers or deposit requirements.

OTP’s credit risk with its largest counterparty on delivered and marked-to-market forward contracts as of December 31, 2010 was $585,000. As of December 31, 2010 OTP had a net credit risk exposure of $1,129,000 from four counterparties with investment grade credit ratings. OTP had no exposure at December 31, 2010 to counterparties with credit ratings below investment grade. The $1,129,000 credit risk exposure included 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 December 31, 2010. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Mark-to-market losses of $427,000 on certain OTP derivative energy contracts included in the $17,991,000 derivative liability on December 31, 2010 are covered by deposited funds. Certain other OTP 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 the immediate deposit of cash to cover contracts in net liability positions. The aggregate fair value of all forward energy derivative contracts with credit-risk-related contingent features that were in a liability position on December 31, 2010 was $10,904,000, for which OTP had posted $6,219,000 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 had been triggered on December 31, 2010, OTP would have been required to provide $4,685,000 in additional cash to its counterparties. The remaining derivative liability balance of $6,660,000 relates to mark-to-market losses on contracts that have no ratings triggers or deposit requirements.

6. Common Shares and Earnings Per Share

Common Shares

The Company did not issue or retire any common shares during the three months ended March 31, 2011.

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, 2011 and 2010:

Quarter Ended March 31,	Options Outstanding	Range of Exercise Prices
2011	383,460	$24.93 – $31.34
2010	390,210	$24.93 – $31.34

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 2011. As of March 31, 2011 the remaining unrecognized compensation expense related to stock-based compensation was approximately $2.3 million (before income taxes) which will be amortized over a weighted-average period of 2.2 years.

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three months ended March 31, 2011 and 2010 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2011		2010
Employee Stock Purchase Plan (15% discount)	$	62	$	69
Restricted Stock Granted to Directors		192		140
Restricted Stock Granted to Employees		115		118
Restricted Stock Units Granted to Employees		83		60
Stock Performance Awards Granted to Executive Officers		--		222
Totals	$	452	$	609

9. Commitments and Contingencies

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

At December 31, 2010 OTP had commitments for capacity and energy requirements under agreements extending through 2032 at annual costs of approximately $20,134,000 in 2011, $21,637,000 in 2012, $16,492,000 in 2013, $15,388,000 in 2014, $12,307,000 in 2015 and $78,879,000 for the years beyond 2015. In the first quarter of 2011, OTP entered into additional energy purchase agreements increasing its commitments for capacity and energy requirements by $1,134,000 in 2011, $3,388,000 in 2012, $5,376,000 in 2013, $9,313,000 in 2014 and $6,608,000 in 2015.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. In the first quarter of 2011, OTP extended its contract for the purchase of coal for Hoot Lake Plant resulting in an increase in minimum purchase commitments of $2,145,000 in 2011 and $5,198,000 in 2012. OTP’s current coal purchase agreements now expire in 2012 and 2016. In total, OTP is now committed to the minimum purchase, dating from January 1, 2011, of approximately $123,092,000 or to make payments in lieu thereof, under these contracts. The FCA mechanism lessens the risk of loss from market price changes because it provides for recovery of most fuel costs.

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, 2011 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, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on March 31, 2011		Restricted due to Outstanding Letters of Credit		Available on March 31, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	96,976	$	1,674	$	101,350	$	144,350
OTP Credit Agreement		170,000		20,000		1,050		148,950		144,436
Total	$	370,000	$	116,976	$	2,724	$	250,300	$	288,786

On March 3, 2011 OTP entered into an Amended and Restated Credit Agreement (the OTP Credit Agreement) with the Banks named therein. The OTP Credit Agreement provides for a $170 million line of credit that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. The OTP Credit Agreement is an unsecured revolving credit facility that OTP can draw on to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under the line of credit currently bear interest at LIBOR plus 1.5%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. Under the OTP Credit Agreement OTP is required to pay the Banks’ commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement expires on March 3, 2016.

The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default. The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The OTP Credit Agreement amends and restates the $170 million Credit Agreement dated as of July 30, 2008 among OTP (formerly known as Otter Tail Corporation, dba Otter Tail Power Company), the Banks named therein, as amended by a First Amendment to Credit Agreement dated as of April 21, 2009 and a Second Amendment to Credit Agreement dated as of June 22, 2009.

The OTP Credit Agreement also contains certain financial covenants. Specifically, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization (as defined in the OTP Credit Agreement) to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio (as defined in the OTP Credit Agreement) to be less than 1.50 to 1.00.

On March 18, 2011 Otter Tail Corporation borrowed $1.5 million under a Partnership in Assisting Community Expansion loan to finance capital investments made at Northern Pipe Products, Inc., the Company’s PVC pipe manufacturing subsidiary located in Fargo, North Dakota. The ten-year unsecured note bears interest at 2.54% with monthly principal and interest payments through March 2021.

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, 2011:

(in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt – Credit Lines	$	20,000			$	96,976	$	116,976
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011	$	90,000					$	90,000
Pollution Control Refunding Revenue Bonds, Variable, 2.50% at March 31, 2011, 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		5,090						5,090
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		20,215						20,215
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
Other Obligations - Various up to 13.31% at March 31, 2011			$	4,546		1,501		6,047
Total	$	280,705	$	4,546	$	151,501	$	436,752
Less:
Current Maturities		--		589		94		683
Unamortized Debt Discount		--		--		5		5
Total Long-Term Debt	$	280,705	$	3,957	$	151,402	$	436,064
Total Short-Term and Long-Term Debt (with current maturities)	$	300,705	$	4,546	$	248,472	$	553,723

11. Class B Stock Options of Subsidiary

As of March 31, 2011 there were 363 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $233,000. These options were adjusted to their fair value based on the fair value of an underlying share of Class B Common Stock of $2,973.90 per share in conjunction with the sale of IPH on May 6, 2011. The book value of outstanding IPH Class B common share options on March 31, 2011 was based on an IPH Class B common share value of $2,085.88 per share. The $322,000 difference between the fair value and book value of the options will be charged to retained earnings and earnings available for common shares will be reduced by $322,000 in the second quarter of 2011.

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)	2011			2010
Service Cost—Benefit Earned During the Period	$	1,175		$	1,247
Interest Cost on Projected Benefit Obligation		3,175			3,030
Expected Return on Assets		(3,537	)		(3,400	)
Amortization of Prior-Service Cost		100			170
Amortization of Net Actuarial Loss		650			495
Net Periodic Pension Cost	$	1,563		$	1,542

The Company did not make a contribution to its pension plan in the three months ended March 31, 2011 and is not currently required to make a contribution in 2011.

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)	2011		2010
Service Cost—Benefit Earned During the Period	$	20	$	165
Interest Cost on Projected Benefit Obligation		408		418
Amortization of Prior-Service Cost		61		18
Amortization of Net Actuarial Loss		19		119
Net Periodic Pension Cost	$	508	$	720

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)	2011			2010
Service Cost—Benefit Earned During the Period	$	425		$	425
Interest Cost on Projected Benefit Obligation		850			775
Amortization of Transition Obligation		187			187
Amortization of Prior-Service Cost		50			50
Amortization of Net Actuarial Loss		213			188
Effect of Medicare Part D Expected Subsidy		(525	)		(500	)
Net Periodic Postretirement Benefit Cost	$	1,200		$	1,125

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, 2011						December 31, 2010
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Short-Term Investments	$	186		$	186		$	--		$	--
Long-Term Debt		(436,064	)		(472,829	)		(434,812	)		(474,307	)

15. Income Taxes – Continuing Operations

Income taxes - continuing operations decreased $1.2 million in the first quarter of 2011 compared with the first quarter of 2010 as a result of the following: (1) a charge of $1.7 million in the first quarter of 2010 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 for retiree prescription drug benefits that qualify for the Medicare Part D retiree drug subsidy, and (2) a $0.5 million increase in federal production tax credits (PTCs) earned as a result of a 25.6% increase in kilowatt-hours (kwh) generated from tax credit qualified wind turbines owned by OTP in the first quarter of 2011, offset by (3) DMI deferring recognition of tax benefits in the first quarter of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s deferred tax benefits totaled $0.9 million in the first quarter of 2011.

The Company’s effective income tax rates on continuing operations for the three months ended March 31, 2011 and 2010 were approximately 9.5% and 33.3%, respectively. The Company’s effective income tax rate for the three months ended March 31, 2010 was increased by the $1.7 million charge related to the enactment of new federal health care legislation in March 2010. Reductions from the federal statutory rate reflect the benefit of the PTCs and North Dakota wind energy credits in the respective quarters. Federal production tax credits are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. 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. Discontinued Operations

On May 6, 2011, the Company completed the sale of IPH to affiliates of Novacap Industries III, L.P. for approximately $87.0 million in cash. The proceeds from the sale, net of $3.0 million deposited in an escrow account, were used to pay down borrowings under the Otter Tail Corporation Credit Agreement. The financial position, results of operations, and cash flows of IPH are reported as discontinued operations in the Company’s consolidated financial statements as of March 31, 2011 and December 31, 2010, and for the three month periods ended March 31, 2011 and 2010. Following are pro forma summary presentations of the Company’s consolidated income statements for the years ended December 31, 2010 and 2009, reflecting the classification of IPH’s results as discontinued operations:

Otter Tail Corporation Summary Consolidated Income Statements For the Years Ended December 31,

	2010									2009
(in thousands, except per share amounts)	As Previously Reported			IPH1			With IPH classified as Discontinued Operations			As Previously Reported			IPH1			With IPH classified as Discontinued Operations
Operating Revenues	$	1,119,084		$	77,202		$	1,041,882		$	1,039,512		$	78,632		$	960,880
Operating Expenses:
Cost of Goods Sold		600,956			56,619			544,337			565,192			58,718			506,474
Other Operating Expenses		402,919			3,729			399,190			355,322			3,330			351,992
Depreciation Expense		80,696			4,703			75,993			73,608			4,333			69,275
Total Operating Expenses		1,084,571			65,051			1,019,520			994,122			66,381			927,741
Operating Income		34,513			12,151			22,362			45,390			12,251			33,139
Other Income (Deductions)		5,126			(408	)		5,534			4,550			(404	)		4,954
Interest Charges		37,032			29			37,003			28,514			30			28,484
Income Tax Expense (Benefit)		3,951			3,716			235			(4,605	)		4,410			(9,015	)
Net Income - Continuing Operations		(1,344	)		7,998			(9,342	)		26,031			7,407			18,624
Net Income – Discontinued Operations								7,998									7,407
Net Income		(1,344	)		7,998			(1,344	)		26,031			7,407			26,031
Preferred Dividend Requirements		833			--			833			736			--			736
Earnings Available for Common Shares	$	(2,177	)	$	7,998		$	(2,177	)	$	25,295		$	7,407		$	25,295

Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	(0.06	)	$	0.22		$	(0.28	)	$	0.71		$	0.21		$	0.50
Discontinued Operations								0.22									0.21
							$	(0.06	)							$	0.71
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	(0.06	)	$	0.22		$	(0.28	)	$	0.71		$	0.21		$	0.50
Discontinued Operations								0.22									0.21
							$	(0.06	)							$	0.71
1Includes reinstatement of intercompany eliminations related to intercompany transactions with IPH.

18. Subsequent Events

Stock Incentive Awards—On April 11, 2011 the Company’s Board of Directors granted 19,800 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan), payable in common shares on April 8, 2015, the date the units vest. The grant date fair value of each restricted stock unit was $18.03 per share based on the market value of the Company’s common stock on April 11, 2011, discounted for the value of the dividend exclusion over the four-year vesting period.

On April 11, 2011 the Company’s Board of Directors granted 24,000 shares of restricted stock to the Company’s nonemployee directors and 24,600 shares of restricted stock to the Company’s executive officers (which include 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 $22.51 per share, the average market price on the date of grant.

On April 11, 2011 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 97,200 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, 2011 through December 31, 2013. The aggregate target share award is 48,600 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 of common shares projected to be awarded was $23.61 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.

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, 2011 and 2010, followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2011 and our business outlook for the remainder of 2011.

Comparison of the Three Months Ended March 31, 2011 and 2010

Consolidated operating revenues were $286.7 million for the three months ended March 31, 2011 compared with

$243.7 million for the three months ended March 31, 2010. Operating income was $13.2 million for the three months ended March 31, 2011 compared with $14.0 million for the three months ended March 31, 2010. The Company recorded diluted earnings per share from continuing operations of $0.10 for the three months ended March 31, 2011 compared to $0.09 for the three months ended March 31, 2010 and total diluted earnings per share of $0.15 for the three months ended March 31, 2011 compared to $0.13 for the three months ended March 31, 2010.

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, 2011 and 2010 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, 2011		March 31, 2010
Operating Revenues:
Electric	$	71	$	71
Nonelectric		1,242		1,156
Cost of Goods Sold		1,055		1,081
Other Nonelectric Expenses		258		146

Electric

	Three Months Ended
	March 31,							%
(in thousands)	2011		2010		Change			Change
Retail Sales Revenues	$	82,903	$	81,375	$	1,528			1.9
Wholesale Revenues – Company Generation		2,736		3,992		(1,256	)		(31.5	)
Net Revenue – Energy Trading Activity		228		2,007		(1,779	)		(88.6	)
Other Revenues		5,729		4,078		1,651			40.5
Total Operating Revenues	$	91,596	$	91,452	$	144			0.2
Production Fuel		19,577		20,909		(1,332	)		(6.4	)
Purchased Power – System Use		12,377		12,056		321			2.7
Other Operation and Maintenance Expenses		28,708		28,466		242			0.9
Depreciation and Amortization		10,039		10,037		2			--
Property Taxes		2,409		2,474		(65	)		(2.6	)
Operating Income	$	18,486	$	17,510	$	976			5.6

The increase in retail sales revenues mainly is due to the following: (1) a $1.9 million increase in revenues due to a 3.5% increase in kilowatt-hour (kwh) sales driven by colder weather, as heating degree days were up 12.9% in the first quarter of 2011, (2) a $1.3 million increase from interim rates implemented in Minnesota in June 2010, (3) a $0.9 million increase in estimated Minnesota Conservation Improvement Program (CIP) incentives, (4) a $0.6 million increase in Minnesota CIP surcharge revenues, and (5) $0.4 million related to recovery of the North Dakota portion of Otter Tail Power Company’s (OTP’s) abandoned Big Stone II project costs, offset by (6) a $2.3 million reduction in revenue related to a Minnesota interim rate refund accrued in the first quarter of 2011 for excess amounts collected under interim rates in effect since June 2010, (7) a $0.8 million decrease in resource recovery and transmission rider revenues, and (8) a $0.5 million reduction in retail revenues related to the recovery of fuel and purchased power costs.

Wholesale electric revenues from company-owned generation decreased $1.3 million mainly as a result of a 30.2% decrease in revenue per wholesale kwh sold related to decreases in wholesale market prices for electricity. Net gains from energy trading activities, including net mark-to-market gains on forward energy contracts decreased $1.8 million as a result of a reduction in mark-to-market gains on open energy contracts combined with a reduction in the volume of long-term forward energy contracts entered into in 2011. Other electric operating revenues increased $1.7 million as a result of: (1) a $1.1 million payment received by Otter Tail Energy Services Company (OTESCO) in the first quarter of 2011 for access rights to construct a transmission line through an OTESCO wind farm development site, and (2) a $0.6 million increase in transmission tariff and services revenues.

The decrease in fuel costs is due to a 10.2% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators, partially offset by a 4.2% increase in the cost of fuel per kwh generated. The cost of purchased power for retail sales increased $0.3 million as a result of a 75.1% increase in kwhs purchased, mostly offset by 41.4% decrease in the cost per kwh purchased. The increase in kwhs purchased was due to a 7.5% decrease in kwhs generated for retail combined with a 3.5% increase in retail kwh sales.

Wind Energy

	Three Months Ended
	March 31,								%
(in thousands)	2011			2010		Change			Change
Wind Tower Revenues	$	46,988		$	40,928	$	6,060			14.8
Transportation Revenues		14,609			8,470		6,139			72.5
Total Operating Revenues	$	61,597		$	49,398		12,199			24.7
Cost of Goods Sold		47,791			33,427		14,364			43.0
Operating Expenses		19,947			11,624		8,323			71.6
Depreciation and Amortization		2,671			2,727		(56	)		(2.1	)
Operating (Loss) Income	$	(8,812	)	$	1,620	$	(10,432	)		(644.0	)

The increase in revenues in our Wind Energy segment relates to the following:

·	Revenues at DMI Industries, Inc., (DMI), our manufacturer of wind towers, increased as a result of a 33.6% increase in tower production.

Revenues at E.W. Wylie Corporation (Wylie), our flatbed trucking company, increased as a result of the following (1) $4.9 million in revenue earned on a major wind tower and turbine transportation contract in the first quarter of 2011 that was initiated in October 2010, (2) a 12.8% increase in revenue per mile driven, reflecting price increases for fuel cost recovery related to a 32.7% increase in the average cost per gallon of fuel consumed, and (3) a $0.4 million increase in brokerage revenues.

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

·	Cost of goods sold at DMI increased $14.4 million, in part as a result of an increase in towers completed, and due to production inefficiencies related to throughput constraints and increased quality control costs incurred to satisfy expanded customer requirements.

The increase in operating expenses in our Wind Energy segment relates to the following:

·	Operating expenses at DMI were unchanged between the quarters.

Operating expenses at Wylie increased $8.3 million as a result of increases of: (1) $6.6 million in costs incurred in the first quarter of 2011 related to the major wind tower and turbine transportation contract initiated in October 2010, (2) $1.1 million in fuel costs, (3) $0.3 million in labor costs, and (4) $0.3 million in brokerage settlements.

Manufacturing

	Three Months Ended
	March 31,								%
(in thousands)	2011		2010			Change			Change
Operating Revenues	$	56,313	$	38,031		$	18,282			48.1
Cost of Goods Sold		43,073		28,859			14,214			49.3
Operating Expenses		4,967		6,000			(1,033	)		(17.2	)
Depreciation and Amortization		3,170		3,266			(96	)		(2.9	)
Operating Income (Loss)	$	5,103	$	(94	)	$	5,197			--

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

·	Revenues at BTD Manufacturing, Inc. (BTD), our metal parts stamping and fabrication company, increased $15.1 million as a result of higher sales volume due to improved customer demand.

·	Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased by $2.0 million due to increased sales of horticultural and industrial products.

·	Revenues at ShoreMaster, Inc. (ShoreMaster), our waterfront equipment business, increased $1.2 million mainly as a result of higher sales of residential products due to improving dealer confidence and expanded distribution in Canada.

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

·	Cost of goods sold at BTD increased $11.6 million mainly as a result of increased sales volume.

·	Cost of goods sold at T.O. Plastics increased $1.4 million as a result of the increase in sales of horticultural and industrial products.

·	Cost of goods sold at ShoreMaster increased $1.3 million related to an increase in sales of residential products and inventory write downs on discounted products.

The net decrease in operating expenses in our Manufacturing segment is due to the following:

·	Operating expenses at BTD increased $0.2 million due to increased salary and benefit costs related to workforce expansion.

·	Operating expenses at T.O. Plastics increased $0.2 million due to increased salary and benefit costs.

·	Operating expenses at ShoreMaster decreased $1.4 million, reflecting lower collection costs and decreases in sales and employee benefit expenses.

Construction

	Three Months Ended
	March 31,									%
(in thousands)	2011			2010			Change			Change
Operating Revenues	$	37,515		$	17,774		$	19,741			111.1
Cost of Goods Sold		34,289			16,423			17,866			108.8
Operating Expenses		3,106			3,215			(109	)		(3.4	)
Depreciation and Amortization		445			525			(80	)		(15.2	)
Operating Loss	$	(325	)	$	(2,389	)	$	2,064			(86.4	)

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

·	Revenues at Foley Company, a mechanical and prime contractor on industrial projects, increased $19.6 million due to an increase in volume of jobs in progress.

·	Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, increased $0.2 million between the quarters.

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

·	Cost of goods sold at Foley Company increased $17.7 million, mainly in the areas of material and subcontractor costs related to the increase in Foley’s work volume between the quarters.

·	Cost of goods sold at Aevenia increased $0.1 million between the quarters.

Plastics

	Three Months Ended
	March 31,								%
(in thousands)	2011			2010		Change			Change
Operating Revenues	$	18,478		$	23,087	$	(4,609	)		(20.0	)
Cost of Goods Sold		16,720			19,490		(2,770	)		(14.2	)
Operating Expenses		1,221			1,197		24			2.0
Depreciation and Amortization		803			781		22			2.8
Operating (Loss) Income	$	(266	)	$	1,619	$	(1,885	)		(116.4	)

Operating revenues for the plastics segment decreased as result of an 18.1% decrease in pounds of polyvinyl chloride (PVC) pipe sold combined with a 2.3% decrease in the price per pound pipe sold. The decrease in costs of goods sold was related to the decrease in pounds of pipe sold partially offset by a 4.7% increase in the cost per pound of pipe sold.

Health Services

	Three Months Ended
	March 31,								%
(in thousands)	2011		2010			Change			Change
Operating Revenues	$	22,495	$	25,171		$	(2,676	)		(10.6	)
Cost of Goods Sold		14,891		20,366			(5,475	)		(26.9	)
Operating Expenses		4,673		4,616			57			1.2
Depreciation and Amortization		1,848		1,104			744			67.4
Operating Income (Loss)	$	1,083	$	(915	)	$	1,998			218.4

Revenues from scanning and other related services decreased $2.0 million due to a 17.4% decrease in scans performed, partially offset by a 9.6% increase in revenue per scan, reflecting the planned discontinuance of portable x-ray services. Revenues from equipment sales decreased $0.7 million mainly due to a decrease in revenues from sales of equipment used in the imaging side of the business. The decrease in cost of goods sold includes a $1.6 million reduction in material and service labor costs and a $3.5 million reduction in equipment rental costs directly related to efforts by the health services segment to right-size its fleet of imaging assets by exercising purchase options on productive imaging assets coming off lease and not renewing leases on underutilized imaging assets. As of March 31, 2011 there were 123 owned and leased assets in the fleet compared with 147 at March 31, 2010. The increase in depreciation expense reflects an increase in owned equipment compared with a year ago.

Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

	Three Months Ended
	March 31,							%
(in thousands)	2011		2010		Change			Change
Operating Expenses	$	1,969	$	3,232	$	(1,263	)		(39.1	)
Depreciation and Amortization		138		144		(6	)		(4.2	)

The decrease in corporate operating expenses mainly due to lower salary and employee benefit costs due to lower staffing levels between the periods and lower general and administrative costs.

Interest Charges

Interest charges increased $0.5 million in the first three months of 2011 compared with the first three months of 2010 as a result of a $10.2 million increase in the average balance of short-term debt outstanding between the quarters.

Other Income

Other income increased $0.6 million in the first three months of 2011 compared with the first three months of 2010 as a result of increases in interest revenue, allowance for equity funds used during construction at OTP and a decrease in foreign currency transaction losses in the Canadian operations of DMI, between the quarters.

Income Taxes – Continuing Operations

Income taxes - continuing operations decreased $1.2 million in the first quarter of 2011 compared with the first quarter of 2010 as a result of the following: (1) a noncash charge of $1.7 million in the first quarter of 2010 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 for retiree prescription drug benefits that qualify for the Medicare Part D retiree drug subsidy, and (2) a $0.5 million increase in federal production tax credits (PTCs) earned as a result of a 25.6% increase in kwhs generated from tax credit qualified wind turbines owned by OTP, offset by (3) DMI deferring recognition of tax benefits on the operating losses of its Canadian operations until those operations become profitable. DMI’s deferred tax benefits totaled $0.9 million in the first quarter of 2011.

Our consolidated effective income tax rates on continuing operations for the three months ended March 31, 2011 and 2010 were approximately 9.5% and 33.3%, respectively. Our effective income tax rate for the three months ended March 31, 2010 was increased by the $1.7 million charge related to the enactment of new federal health care legislation in March 2010. Reductions from the federal statutory rate reflect the benefit of the PTCs and North Dakota wind energy credits in the respective quarters. Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. 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.

Discontinued Operations - Food Ingredient Processing

Food ingredient processing net income was $1.8 million compared with $1.4 million for the first quarter of 2010. The $0.4 million increase in net income was driven by a $1.7 million increase in revenue resulting from a 7.5% increase in pounds of product sold. Cost of goods sold increased $1.1 million due to the increase in sales volume while the cost per pound of product sold only increased 0.3%. Income taxes increased $0.4 million as a result of an increase in taxable income between the quarters.

FINANCIAL POSITION

The following table presents the status of our lines of credit as of March 31, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on March 31, 2011		Restricted due to Outstanding Letters of Credit		Available on March 31, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	96,976	$	1,674	$	101,350	$	144,350
OTP Credit Agreement		170,000		20,000		1,050		148,950		144,436
Total	$	370,000	$	116,976	$	2,724	$	250,300	$	288,786

We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings, and alternative financing arrangements such as leasing.

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 11, 2009 we filed a shelf registration statement with the Securities and Exchange Commission under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. On March 17, 2010, we entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million. Equity or debt financing will be required in the period 2011 through 2015 given the expansion plans related to our Electric segment to fund construction of new rate base investments, in the event we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt or cumulative preferred shares, to complete acquisitions or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected. Also, our operating cash flow and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

Our dividend payout ratio has exceeded 100% in each of the last three years. The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share to levels in excess of the indicated annual dividend per share of $1.19, cash flows from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects. The decision to declare a quarterly dividend is reviewed quarterly by the Board of Directors.

DMI is party to a $40 million receivable purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement, originally scheduled to expire in March 2011, was extended for one year by DMI in February 2011. The discount rate for the one-year extension has been increased to 3-month LIBOR plus 4%. Accounts receivable totaling $19.0 million were sold in the first quarter of 2011. Discounts, fees and commissions charged to operating expense for the three months ended March 31, 2011 and 2010 were $118,000 and $32,000, respectively. The balance of receivables sold that was outstanding to the buyer as of March 31, 2011 was $17.2 million. The sales of these accounts receivable are reflected as a reduction of accounts receivable in our consolidated balance sheets and the proceeds are included in the cash flows from operating activities in our consolidated statement of cash flows.

Cash provided by operating activities from continuing operations was $4.2 million for the three months ended March 31, 2011 compared with cash used in operating activities for continuing operations of $21.2 million for the three months ended March 31, 2010. The $25.4 million increase in cash provided by operating activities of continuing operations between the quarters reflects a $21.7 million decrease in cash used for working capital items between the quarters mainly due to a reduction in cash used for other current assets of $22.7 million, as costs in excess of billings at DMI decreased by $2.8 million in the first quarter of 2011, compared with an increase of $20.8 million in the first quarter of 2010.

Net cash used in investing activities of continuing operations was $23.6 million for the three months ended March 31, 2011 compared to $18.1 million for the three months ended March 31, 2010. Cash used for capital expenditures at the electric utility increased $5.7 million between the quarters mainly related to expenditures for the Fargo to St. Cloud and Bemidji to Grand Rapids CapX2020 transmission line construction projects.

Net cash provided by financing activities from continuing operations decreased $17.1 million in the three months ended March 31, 2011 compared with the three months ended March 31, 2010 mainly due to an $18.1 million increase in short-term borrowings and checks issued in excess of cash, net of a decrease in cash used to retire long-term debt between the quarters. We paid $58.4 million to retire long-term debt in the first quarter of 2010. Proceeds from short-term borrowings and checks written in excess of cash, net of cash used to retire long-term debt, was $27.3 million in the first quarter of 2011 compared with $45.4 million in the first quarter of 2010.

Our contractual obligations reported in the table on page 56 of our Annual Report on Form 10-K for the year ended December 31, 2010 have increased by $33.2 million: Our “Capacity and Energy Requirements” have increased by $1.1 million for 2011, $8.8 million for 2012 and 2013, and $15.9 million for 2014 and 2015 related to long-term power purchase agreements entered into with a regional generator and supplier in the first quarter of 2011. Our “Coal Contracts (required minimums)” have increased by $2.1 million in 2011 and $5.2 million in 2012 related to an expansion and extension of an agreement to supply coal to OTP’s Hoot Lake Plant.

On May 11, 2009 we filed a shelf registration statement with the Securities and Exchange Commission under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement.

On March 17, 2010, we entered into a Distribution Agreement (the Agreement) with JPMS. Pursuant to the terms of the Agreement, we may offer and sell our common shares from time to time through JPMS, as our distribution agent for the offer and sale of the shares, up to an aggregate sales price of $75 million. Under the Agreement, we 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. We are 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 our shelf registration statement, as amended. No shares have been sold pursuant to the Agreement.

On May 4, 2010 we entered into a $200 million Second Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement) with the Banks named therein, which is an unsecured revolving credit facility that we can draw on to support our nonelectric operations. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 3.25%, subject to adjustment based on our senior unsecured credit ratings. The Otter Tail Corporation Credit Agreement expires on May 4, 2013. The Otter Tail Corporation Credit Agreement contains a number of restrictions on us and the businesses of Varistar Corporation (Varistar), our wholly owned subsidiary, and its material subsidiaries, including restrictions on our and 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 Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default. The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our material subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $50 million. The Otter Tail Corporation Credit Agreement has an accordion feature whereby the line can be increased to $250 million as described in the Otter Tail Corporation Credit Agreement.

On March 18, 2011 we borrowed $1.5 million under a Partnership in Assisting Community Expansion loan to finance capital investments made at Northern Pipe Products, Inc., our PVC pipe manufacturing subsidiary located in Fargo, North Dakota. The ten-year unsecured note bears interest at 2.54% with monthly principal and interest payments through March 2021.

OTP’s Senior Unsecured Notes 6.63% due December 1, 2011 remain classified as long-term debt because OTP has the ability to refinance this debt under the OTP Credit Agreement, as amended and restated.

The note purchase agreement relating to OTP’s $90 million 6.63% senior notes due December 1, 2011, as amended (the 2001 Note Purchase Agreement), the note purchase agreement relating to our $50 million 8.89% senior note due November 30, 2017, as amended (the Cascade Note Purchase Agreement), and the note purchase agreement relating to OTP’s $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037, as amended (the 2007 Note Purchase Agreement) each states that the applicable obligor may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. Each of the Cascade Note Purchase Agreement and the 2001 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require the applicable obligor to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the respective note purchase agreements. The 2007 Note Purchase Agreement states the applicable obligor must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of such obligor. The 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and the Cascade Note Purchase Agreement each contain a number of restrictions on the applicable obligor and its subsidiaries. These include restrictions on the obligor’s ability and the ability of the obligor’s subsidiaries to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. Our obligations under the Cascade Note Purchase Agreement are guaranteed by certain of our material subsidiaries. Cascade owned approximately 9.6% of the Company’s outstanding common stock as of December 31, 2010.

On June 23, 2010 we entered into Amendment No. 3 to the Cascade Note Purchase Agreement. Amendment No. 3 amends certain covenants and related definitions contained in the Cascade Note Purchase Agreement to, among other things, provide us and our material subsidiaries with additional flexibility to incur certain customary liens, make certain investments, and give certain guaranties, in each case under the circumstances set forth in Amendment No. 3. On July 29, 2010 we entered into Amendment No. 4 to the Cascade Note Purchase Agreement, which was effective June 30, 2010. The amendments contained in Amendment No. 4 permit us to exclude impairment charges and write-offs of assets from the calculation of the interest charges coverage ratio required to be maintained under the Cascade Note Purchase Agreement.

Financial Covenants

As of March 31, 2011 the Company was in compliance with the financial statement covenants that existed in its debt agreements.

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

Our borrowing agreements are subject to certain financial covenants. Specifically:

Under the Otter Tail Corporation Credit Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the Credit Agreement. As of March 31, 2011 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 1.68 to 1.00.

Under the Cascade Note Purchase Agreement, we may not permit our ratio of Consolidated Debt to Consolidated Total Capitalization to be greater than 0.60 to 1.00 or our Interest Charges Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), permit the ratio of OTP’s Debt to OTP’s Total Capitalization to be greater than 0.60 to 1.00, or permit Priority Debt to exceed 20% of Varistar Consolidated Total Capitalization, as provided in the Cascade Note Purchase Agreement. As of March 31, 2011 our Interest Charges Coverage Ratio calculated under the requirements of the Cascade Note Purchase Agreement was 1.60 to 1.00.

Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, as provided in the OTP Credit Agreement. As of March 31, 2011 OTP’s Interest and Dividend Coverage Ratio calculated under the requirements of the OTP Credit Agreement was 3.21 to 1.00.

Under the 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and the financial guaranty insurance policy with Ambac Assurance Corporation relating to certain pollution control refunding bonds, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio (or, in the case of the 2001 Note Purchase Agreement, its Interest Charges Coverage Ratio) to be less than 1.50 to 1.00, in each case as provided in the related borrowing or insurance agreement. In addition, under the 2001 Note Purchase Agreement and the 2007 Note Purchase Agreement, OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of March 31, 2011 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2001 Note Purchase Agreement and the 2007 Note Purchase Agreement, respectively, was 3.21 to 1.00.

As of March 31, 2011 our interest-bearing debt to total capitalization was 0.46 to 1.00 on a fully consolidated basis and 0.48 to 1.00 for OTP.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $10.6 million, but our line of credit borrowing limits are only restricted by $2.7 million of the outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

2011 BUSINESS OUTLOOK

We are updating our 2011 diluted earnings per share guidance to reflect the sale of IPH, our Food Ingredient Processing business, and to adjust for changing business conditions in our other segments. This guidance considers the cyclical nature of some of our businesses and reflects challenges presented by current economic conditions and our plans and strategies for improving future operating results. Since our February 2011 earnings release, guidance for two segments has been raised, but the outlook for Wind Energy has been lowered.

The sale of IPH allows us to refine our portfolio to focus on a mix of businesses that will reduce our risk profile. We will continue to review our portfolio to see where additional opportunities exist to improve our risk profile, improve credit metrics and generate additional sources of cash to support the future capital expenditure plans of our Electric segment. The proceeds from the sale of IPH will be used to pay down short-term borrowings on our credit facility for our nonelectric businesses.

The updated 2011 earnings per share guidance range is as follows:

Original 2011 Earnings Per Share Guidance Range							Updated 2011 Earnings Per Share Guidance Range
	Low			High				Low			High
Electric	$	.97		$	1.02		Electric	$	.99		$	1.04
Wind Energy		(.10	)		.05		Wind Energy		(.40	)		(.25	)
Manufacturing		.13			.18		Manufacturing		.25			.29
Construction		.05			.08		Construction		.05			.08
Plastics		.05			.08		Plastics		.05			.08
Health Services		.00			.04		Health Services		.00			.04
Food Ingredient Processing		.17			.20		Corporate		(.20	)		(.18	)
Corporate		(.27	)		(.25	)	Total – Continuing Operations	$	.74		$	1.10
Total	$	1.00		$	1.40		Earnings – Discontinued Operations		.06			.07
							Gain on Sale of Discontinued Operations		.35			.38
							Total	$	1.15		$	1.55

Contributing to the earnings guidance update for 2011 are the following items:

We expect an increase in net income from our Electric segment in 2011 compared to 2010. This is based on anticipated sales growth and rate and rider recovery increases, an increase in capitalized interest costs related to larger construction expenditures and reductions in operating and maintenance expense in 2011 due to lower benefit costs.

·	We are revising our 2011 earnings guidance downward for our Wind Energy segment due to the following factors:

DMI has had challenges ramping up production to meet customer demand. This has resulted in a full year outlook that reflects production of fewer towers than originally forecast. Cost levels continue at planned levels but output has not matched those costs due to throughput constraints in the plants and additional processing and verification required to complete the projects under contract. DMI also incurred higher costs in procuring steel for a customer contract when the steel supplier failed to deliver according to the terms of a purchase agreement, requiring DMI to replace the steel at a higher cost in order to meet its contractual commitments.

E.W. Wylie incurred additional costs in completing a major wind tower transportation project in the first quarter of 2011. The additional costs, in part, relate to severe weather on the East Coast, which resulted in extreme delays resulting in cost overruns in permits, truck escort services, and detention and crane operation costs.

Backlog in the Wind Energy segment is $134 million for 2011 compared with $141 million one year ago.

We expect earnings from our Manufacturing segment to increase from our original 2011 guidance as a result of increased order volume and continuing improvement in economic conditions in the industries BTD serves. ShoreMaster is expecting significantly improved performance as a result of bringing costs in line with current revenue levels and absent last year’s $15.6 million noncash impairment charge. T.O. Plastics is expected to have slightly better earnings in 2011 compared with 2010. Backlog for the manufacturing companies for 2011 is approximately $87 million compared with $75 million one year ago.

·	We expect higher net income from our Construction segment in 2011 as the economy improves and the construction companies record earnings on a higher volume of jobs in progress. Backlog for the construction businesses is $105 million for 2011 compared with $85 million one year ago.

·	We expect our Plastics segment's 2011 performance to be in line with 2010 results.

·	We expect increased net income from our Health Services segment in 2011 as the benefits of implementing its asset reduction plan continue to be realized.

·	Corporate general and administrative costs are expected to decrease in 2011, compared with 2010, as a result of recent reductions in employee count and associated decreases in benefit costs.

Earnings expectations from discontinued operations reflect net income from the Food Ingredient Processing segment from January 2011 through May 6, 2011, the date of the sale. We expect to recognize earnings from a gain on the sale of IPH in the range of $0.35 to $0.38 per share.

The sale of IPH is a strategic decision by management to monetize a currently strong earning asset and use the proceeds to pay down short-term borrowings. This frees up liquidity going forward for upcoming Electric segment capital investments and helps ease the need to rely on the capital markets to fully fund these expenditures. Future IPH earnings forfeited through this sale are expected to be replaced by increased utility earnings over the next three years as the utility makes investments in its current capital plan. This will result in a larger percentage of our earnings coming from our most stable and relatively predictable business, Otter Tail Power Company, and is consistent with the strategy to grow this business given its current investment opportunities.

We currently anticipate the following capital expenditures and electric utility average rate base for 2011 through 2013:

(in millions)	2011		2012		2013
Capital Expenditures:
Electric Segment:
Transmission	$	23	$	31	$	65
Environmental		4		49		97
Other		40		50		57
Total Electric Segment	$	67	$	130	$	219
Nonelectric Segments		40		41		48
Total Capital Expenditures	$	107	$	171	$	267
Total Electric Utility Average Rate Base	$	651	$	722	$	876

Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2011 through 2013 timeframe. We intend to maintain an equity to total capitalization ratio near its present level of 51% in our Electric segment and will seek to earn our allowed overall return on equity of approximately 10.5% in the utility’s regulatory jurisdictions.

Regarding the collective operating companies in our nonelectric segments, there is a general expectation that business will strengthen in 2012 and 2013, assuming continued recovery in the U.S. economy. This is expected to lead to increased demand for our industrial products and services, generating higher revenues. This expectation, coupled with cost reductions that have taken place across the Company, should result in rising earnings per share for our nonelectric businesses as a whole.

Critical Accounting Policies Involving Significant Estimates

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

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, accrued renewable resource and transmission rider revenues, valuations of forward energy contracts, service contract maintenance costs, percentage-of-completion and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the Board of Directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 61 through 64 of our Annual Report on Form 10-K for the year ended December 31, 2010. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2011.

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

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

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

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

·	Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

·	Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and could increase borrowing costs and pension plan and postretirement health care expenses.

·	We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are not able to access capital at competitive rates, our ability to implement our business plans may be adversely affected.

We may experience fluctuations in revenues and expenses related to our operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to our shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of our customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.

We made a $20.0 million discretionary contribution to our defined benefit pension plan in 2010. We could be required to contribute additional capital to the pension plan in future years if the market value of pension plan assets significantly declines in the future, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

·	Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating performance.

·	A sustained decline in our common stock price below book value or declines in projected operating cash flows at any of our operating companies may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

·	The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on us.

·	Economic conditions could negatively impact our businesses.

·	If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

·	Our plans to grow and diversify through acquisitions and capital projects may not be successful, which could result in poor financial performance.

·	Our plans to acquire additional businesses and grow and operate our nonelectric businesses could be limited by state law.

·	Our subsidiaries enter into production and construction contracts, including contracts for new product designs, which could expose them to unforeseen costs and costs not within their control, which may not be recoverable and could adversely affect our results of operations and financial condition.

·	Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

·	We are subject to risks associated with energy markets.

·	We are subject to risks and uncertainties related to the timing and recovery of deferred tax assets which could have a negative impact on our net income in future periods.

·	Certain of our operating companies sell products to consumers that could be subject to recall.

·	Competition is a factor in all of our businesses.

·	Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

OTP could be required to absorb a disproportionate share of costs for investments in transmission infrastructure required to provide independent power producers access to the transmission grid. These costs may not be recoverable through a transmission tariff and could result in reduced returns on invested capital and/or increased rates to OTP's retail electric customers.

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

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

·	Changes to regulation of generating plant emissions, including but not limited to carbon dioxide (CO2) emissions, could affect OTP’s operating costs and the costs of supplying electricity to its customers.

·	The U.S. wind industry is reliant on tax and other economic incentives and political and governmental policies. A significant change in these incentives and policies could negatively impact our results of operations and growth.

·	Our wind tower manufacturing business is substantially dependent on a few significant customers.

Competition from foreign and domestic manufacturers, cost management in a fixed price contract project environment, the price and availability of raw materials and diesel fuel, the ability of suppliers to deliver materials at contracted prices, fluctuations in foreign currency exchange rates and general economic conditions could affect the revenues and earnings of our wind energy and manufacturing businesses.

·	A significant failure or an inability to properly bid or perform on projects by our wind energy, construction or manufacturing businesses could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

Our Plastics segment is highly dependent on a limited number of vendors for PVC resin, many of which are located in the Gulf Coast regions, and a limited supply of resin. The loss of a key vendor, or an interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this segment.

·	Our plastic pipe companies compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish the pipe companies’ products from those of its competitors.

·	Reductions in PVC resin prices can negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory.

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

·	Our health services businesses may be unable to continue to maintain agreements with Philips Medical from which the businesses derive significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.

·	Technological change in the diagnostic imaging industry could reduce the demand for diagnostic imaging services and require our health services operations to incur significant costs to upgrade its equipment.

·	Actions by regulators of our health services operations could result in monetary penalties or restrictions in our health services operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At March 31, 2011 we had exposure to market risk associated with interest rates because we had $97.0 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 3.25% under our $200 million revolving credit facility and $20.0 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 1.5% under OTP’s $170 million revolving credit facility. At March 31, 2011 we had exposure to changes in foreign currency exchange rates. DMI has market risk related to changes in foreign currency exchange rates at its plant in Ft. Erie, Ontario because the plant pays its operating expenses in Canadian dollars. Outstanding trade accounts receivable of the Canadian operations of IPH are not at risk of valuation change due to changes in foreign currency exchange rates because the Canadian company transacts all sales in U.S. dollars. However, IPH does have market risk related to changes in foreign currency exchange rates because approximately 24.0% of IPH sales in the first quarter of 2011 were outside the United States and the Canadian operation of IPH pays its operating expenses in Canadian dollars.

The majority of our consolidated long-term debt has fixed interest rates. The interest rate on variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of March 31, 2011 we had $10.4 million of long-term debt subject to variable interest rates. Assuming no change in our financial structure, if variable interest rates were to average one percentage point higher or lower than the average variable rate on March 31, 2011, annualized interest expense and pre-tax earnings would change by approximately $104,000.

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

DMI and the companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, lumber, aluminum, cement and resin. The price and availability of these raw materials could affect the revenues and earnings of our Wind Energy and Manufacturing segments.

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

OTP has market, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of March 31, 2011 OTP had recognized, on a pretax basis, $632,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value OTP’s forward contracts for the purchases and sales of electricity 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 and CME Globex. 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 forward energy sales contracts that are marked to market as of March 31, 2011, are 100% offset by forward energy purchase contracts in terms of volumes and delivery periods but not in terms of delivery points. The differential in forward prices at the different delivery locations currently results in a mark-to-market unrealized gain on OTP’s open forward contracts.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. Volumetric limits and loss limits are used to adequately manage the risks associated with our energy trading activities. Additionally, we have a Value at Risk (VaR) limit to further manage market price risk. There was price risk on open positions as of March 31, 2011 because the open purchases were not at the same delivery points as the open sales.

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 our consolidated balance sheets as of March 31, 2011 and December 31, 2010, and the change in our consolidated balance sheet position from December 31, 2010 to March 31, 2011:

(in thousands)	March 31, 2011			December 31, 2010
Current Asset – Marked-to-Market Gain	$	5,480		$	6,875
Regulatory Asset – Deferred Marked-to-Market Loss		15,027			12,054
Total Assets		20,507			18,929
Current Liability – Marked-to-Market Loss		(19,633	)		(17,991	)
Regulatory Liability – Deferred Marked-to-Market Gain		(242	)		(175	)
Total Liabilities		(19,875	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	632		$	763

(in thousands)	Year-to-Date March 31, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(79	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(17	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		--
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(32	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		635
Changes in Fair Value of Contracts Entered into in 2011		(3	)
Net Fair Value End of Period	$	632

(in thousands)		2nd Quarter 2011				3rd Quarter 2011				4th Quarter 2011				2012				Total
Net Gain		$	99			$	109			$	103			$	321			$	632

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, 2011 was $378,000. As of March 31, 2011 OTP had a net credit risk exposure of $661,000 from eight counterparties with investment grade credit ratings and one counterparty that has not been rated by an external credit rating agency but has been evaluated internally and assigned an internal credit rating equivalent to investment grade. OTP had no exposure at March 31, 2011 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 $661,000 credit risk exposure included 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, 2011. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Item 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of March 31, 2011, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2011.

During the fiscal quarter ended March 31, 2011, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Other

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

Item 1A. Risk Factors

The Company is updating the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 32 through 39 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 by replacing a risk factor related to its construction segment with a general risk factor that applies to several businesses owned by the Company, adding a risk factor related to warranty claims, and eliminating a risk factor related to its Food Ingredient Processing operations.

New Risk Factors:

A significant failure or an inability to properly bid or perform on projects by the corporations wind energy, construction or manufacturing businesses could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

The profitability and success of our wind energy, construction or manufacturing companies require us to identify, estimate and timely bid on profitable projects. The quantity and quality of projects up for bids at any time is uncertain. Additionally, once a project is awarded, we must be able to perform within cost estimates that were set when the bid was submitted and accepted. A significant failure or an inability to properly bid or perform on projects could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

Depending on the specific product or service, we provide certain warranty terms against manufacturing defects and certain materials. We reserve for warranty claims based on industry experience and estimates made by management. For some of our products we have limited history to base our warranty estimate on. Our assumptions could be materially different from any actual claim and could exceed reserve balances.

Expenses associated with remediation activities in the wind energy segment could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. If we are required to cover remediation expenses in addition to our regular warranty coverage, we could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect our consolidated results of operations and financial condition.

Eliminated Risk Factors:

Our construction companies may be unable to properly bid and perform on projects.

The profitability and success of our construction companies require us to identify, estimate and timely bid on profitable projects. The quantity and quality of projects up for bids at any time is uncertain. Additionally, once a project is awarded, we must be able to perform within cost estimates that were set when the bid was submitted and accepted. A significant failure or an inability to properly bid or perform on projects could lead to adverse financial results for our construction companies.

Our company that processes dehydrated potato flakes, flour and granules, IPH, competes in a highly competitive market and is dependent on adequate sources of potatoes for processing.

The market for processed, dehydrated potato flakes, flour and granules is highly competitive. The profitability and success of our potato processing company is dependent on superior product quality, competitive product pricing, strong customer relationships, raw material costs, fuel prices and availability and customer demand for finished goods. In most product categories, our company competes with numerous manufacturers of varying sizes in the United States.

The principal raw material used by IPH is washed process-grade potatoes from growers and potato fresh packing operations. These potatoes are unsuitable for use in other markets due to imperfections. They are not subject to the United States Department of Agriculture’s general requirements and expectations for size, shape or color. While our food ingredient processing company has processing capabilities in three geographically distinct growing regions, there can be no assurance it will be able to obtain raw materials due to poor growing conditions, a loss of key suppliers, loss of potato production acres to other crops, and other factors. A loss or shortage of raw materials or the necessity of paying much higher prices for raw materials or fuel could adversely affect the financial performance of this company. Fluctuations in foreign currency exchange rates could have a negative impact on our potato processing company’s net income and competitive position because approximately 18% of IPH sales in 2010 and approximately 16% of IPH sales in 2009 were outside the United States and the Canadian plant pays its operating expenses in Canadian dollars.

Item 5. Other Information

On May 6, 2011 the Company and Varistar entered into a stock purchase agreement (the IPH Purchase Agreement) with IPH Acquirer Inc. (IPH Acquirer) and 7820429 Canada Inc. (7820429), affiliates of Novacap Industries III, L.P. (together, the Buyer Group), providing for the sale of all of the outstanding shares of capital stock of IPH to IPH Acquirer. The sale of shares of IPH (the IPH Closing) was completed on May 6, 2011 for a cash purchase price of $70.9 million, subject to certain post-closing adjustments as provided in the IPH Purchase Agreement. On May 5, 2011, IPH and 7820429 had entered into a stock purchase agreement (the AWI Purchase Agreement) providing for the sale of all of the outstanding shares of capital stock of AWI Acquisition Company (AWI), a wholly owned subsidiary of IPH, to 7820429. The sale of shares of AWI was completed on May 5, 2011 for a purchase price of $15.9 million, subject to certain post-closing adjustments as provided in the AWI Purchase Agreement, payable in the form of a promissory note that was assigned by IPH to Varistar prior to the IPH Closing on May 6, 2011. The note was paid in full at the IPH Closing. Also at the IPH Closing, $3.0 million of the purchase price was deposited into an escrow account to be available for the satisfaction of indemnification claims pursuant to the IPH Purchase Agreement. The cash received by Varistar for IPH and its subsidiaries on May 6, 2011, net of the $3.0 million deposited in an escrow account, was $83.8 million.

The Company, Varistar and the Buyer Group each made customary representations, warranties and covenants in the IPH Purchase Agreement, and the IPH Purchase Agreement also contains customary indemnification obligations under certain circumstances.

The foregoing summaries of the IPH Purchase Agreement and the AWI Purchase Agreement are qualified in their entirety by reference to the full text of such agreements, which are filed herewith as Exhibits 2.1 and 2.2, respectively, and incorporated herein by reference.

As of the date hereof, there are no material relationships between the Company and its affiliates and any member of the Buyer Group, other than with respect to the IPH Purchase Agreement and the AWI Purchase Agreement.

Pro forma financial information with respect to the transactions described above are included in Note 17 of the Company’s consolidated financial statements included in this Form 10-Q and incorporated herein by reference.

Item 6. Exhibits

2.1

Stock Purchase Agreement, dated as of May 6, 2011, among Otter Tail Corporation, Varistar Corporation, IPH Acquirer Inc. and 7820429 Canada Inc.*

2.2

Stock Purchase Agreement, dated as of May 5, 2011, between Idaho Pacific Holdings, Inc. and 7820429 Canada Inc.*

4.1

Amended and Restated Credit Agreement dated as of March 3, 2011 among Otter Tail Power Company, the Banks named therein, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as Syndication Agents, KeyBank National Association and CoBank, ACB, as Documentation Agents, and U.S. Bank National Association, as administrative agent for the Banks (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation, on March 8, 2011).

31.1

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

* The schedules and exhibits to this Exhibit have not been filed with the Securities and Exchange Commission pursuant to Item 601(b)(2) of Regulation S-K. Otter Tail Corporation agrees to furnish copies of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

SIGNATURES

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

OTTER TAIL CORPORATION

By: /s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

(Chief Financial Officer/Authorized Officer)

Dated: May 10, 2011

EXHIBIT INDEX

Exhibit Number	Description

2.1	Stock Purchase Agreement, dated as of May 6, 2011, among Otter Tail Corporation, Varistar Corporation, IPH Acquirer Inc. and 7820429 Canada Inc.*

2.2	Stock Purchase Agreement, dated as of May 5, 2011, between Idaho Pacific Holdings, Inc. and 7820429 Canada Inc.*

4.1	Amended and Restated Credit Agreement dated as of March 3, 2011 among Otter Tail Power Company, the Banks named therein, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as Syndication Agents, KeyBank National Association and CoBank, ACB, as Documentation Agents, and U.S. Bank National Association, as administrative agent for the Banks (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation, on March 8, 2011).

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema Document.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

*	The schedules and exhibits to this Exhibit have not been filed with the Securities and Exchange Commission pursuant to Item 601(b)(2) of Regulation S-K. Otter Tail Corporation agrees to furnish copies of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

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)

Large accelerated filer X		Accelerated filer __

Non-accelerated filer __		Smaller reporting company __
(Do not check if a smaller reporting company)

(in thousands)	March 31, 2011		December 31, 2010

ASSETS

Current Assets
Cash and Cash Equivalents	$	186	$	--
Accounts Receivable:
Trade—Net		152,509		125,308
Other		15,935		19,399
Inventories		81,141		79,354
Deferred Income Taxes		12,206		11,068
Accrued Utility and Cost-of-Energy Revenues		13,090		16,323
Costs and Estimated Earnings in Excess of Billings		66,269		67,352
Income Taxes Receivable		4,307		4,146
Other		25,503		21,646
Assets of Discontinued Operations		90,267		90,684
Total Current Assets		461,413		435,280

Investments		9,794		9,708
Other Assets		28,233		27,356
Goodwill		69,742		69,742
Other Intangibles—Net		16,056		16,280

Deferred Debits
Unamortized Debt Expense		6,656		6,444
Regulatory Assets		117,485		127,766
Total Deferred Debits		124,141		134,210

Plant
Electric Plant in Service		1,333,125		1,332,974
Nonelectric Operations		355,842		340,907
Construction Work in Progress		51,808		42,031
Total Gross Plant		1,740,775		1,715,912
Less Accumulated Depreciation and Amortization		653,173		637,933
Net Plant		1,087,602		1,077,979

Total Assets	$	1,796,981	$	1,770,555
See accompanying notes to consolidated financial statements.

Part I. Financial Information		Page No.

Item 1.	Financial Statements

	Consolidated Balance Sheets – March 31, 2011 and December 31, 2010 (not audited)	2 & 3

	Consolidated Statements of Income - Three Months Ended March 31, 2011 and 2010 (not audited)	4

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010 (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	27-41

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41-43

Item 4.	Controls and Procedures	43

Part II. Other Information

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44-45

Item 5.	Other Information	45

Item 6.	Exhibits	46

Signatures		46