10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

[ X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from             to

Commission file number            0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota	27-0383995
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

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

866-410-8780

(Registrant's telephone number, including area code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T  (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes    X       No ___

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

Large accelerated filer X                                                                                    Accelerated filer __

Non-accelerated filer __                                                                                     Smaller reporting company  __

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  YES    NO X 

Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date:

October 31, 2011 – 36,062,023 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I.   Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – September 30, 2011 and December 31, 2010 (not audited)	2 & 3
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2011 and 2010 (not audited)	4
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010  (not audited)	5
	Notes to Consolidated Financial Statements (not audited)	6-30
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31-51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52-53
Item 4.	Controls and Procedures	54
Part II.  Other Information
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
Signatures		55

1

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands)	September 30, 2011		December 31, 2010
ASSETS
Current Assets
Cash and Cash Equivalents	$	6,604	$	--
Accounts Receivable:
Trade—Net		152,761		124,353
Other		16,249		19,399
Inventories		91,114		79,270
Deferred Income Taxes		11,987		11,068
Accrued Utility and Cost-of-Energy Revenues		13,446		16,323
Costs and Estimated Earnings in Excess of Billings		54,309		67,352
Income Taxes Receivable		1,530		4,146
Other		23,627		20,224
Assets of Discontinued Operations		77		93,783
Total Current Assets		371,704		435,918
Investments		11,564		9,708
Other Assets		27,109		27,356
Goodwill		69,742		69,742
Other Intangibles—Net		15,712		16,280
Deferred Debits
Unamortized Debt Expense		6,763		6,444
Regulatory Assets		111,454		127,766
Total Deferred Debits		118,217		134,210
Plant
Electric Plant in Service		1,343,080		1,332,974
Nonelectric Operations		368,739		340,167
Construction Work in Progress		67,174		42,031
Total Gross Plant		1,778,993		1,715,172
Less Accumulated Depreciation and Amortization		681,057		637,831
Net Plant		1,097,936		1,077,341
Total Assets	$	1,711,984	$	1,770,555
See accompanying notes to consolidated financial statements.

2

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands, except share data)	September 30, 2011			December 31, 2010
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt	$	39,075		$	79,490
Current Maturities of Long-Term Debt		3,286			604
Accounts Payable		113,966			113,761
Accrued Salaries and Wages		21,682			20,252
Accrued Taxes		10,034			11,957
Derivative Liabilities		16,390			17,991
Other Accrued Liabilities		11,368			9,546
Liabilities of Discontinued Operations		77			23,176
Total Current Liabilities		215,878			276,777
Pensions Benefit Liability		76,237			73,538
Other Postretirement Benefits Liability		43,666			42,372
Other Noncurrent Liabilities		19,813			21,043
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		178,308			162,208
Deferred Tax Credits		33,573			44,945
Regulatory Liabilities		69,113			66,416
Other		497			556
Total Deferred Credits		281,491			274,125
Capitalization
Long-Term Debt, Net of Current Maturities		433,454			434,812
Class B Stock Options of Subsidiary		--			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—36,062,023 Shares; 2010—36,002,739 Shares		180,310			180,014
Premium on Common Shares		252,219			251,919
Retained Earnings		196,295			198,443
Accumulated Other Comprehensive (Loss) Income		(2,879	)		1,487
Total Common Equity		625,945			631,863
Total Capitalization		1,074,899			1,082,700
Total Liabilities and Equity	$	1,711,984		$	1,770,555
See accompanying notes to consolidated financial statements.

3

Otter Tail Corporation
Consolidated Statements of Income
(not audited)
	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except share and per-share amounts)	2011			2010			2011			2010
Operating Revenues
Electric	$	85,117		$	89,272		$	254,618		$	258,130
Nonelectric		230,641			170,474			659,473			495,879
Total Operating Revenues		315,758			259,746			914,091			754,009
Operating Expenses
Production Fuel - Electric		19,080			18,210			55,737			55,611
Purchased Power - Electric System Use		7,488			10,254			27,759			32,730
Electric Operation and Maintenance Expenses		27,323			27,098			84,718			84,817
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)		184,964			138,403			534,503			392,899
Other Nonelectric Expenses		37,163			32,298			97,470			93,527
Asset Impairment Charge		--			--			--			19,740
Depreciation and Amortization		19,937			19,175			58,748			56,404
Property Taxes - Electric		2,601			2,271			7,427			7,222
Total Operating Expenses		298,556			247,709			866,362			742,950
Operating Income		17,202			12,037			47,729			11,059
Other Income		489			704			2,317			1,269
Interest Charges		8,708			9,287			27,346			27,707
Income (Loss) Before Income Taxes – Continuing Operations		8,983			3,454			22,700			(15,379	)
Income Tax Expense (Benefit) – Continuing Operations		2,109			(607	)		4,194			(6,625	)
Net Income (Loss) from Continuing Operations		6,874			4,061			18,506			(8,754	)
Discontinued Operations
Income (Loss) from Discontinued Operations net of income tax (benefit)
expense of $(34), $1,225, $(398), and $3,081 for the respective periods		(52	)		2,040			(412	)		5,354
Gain (Loss) on Disposition of Discontinued Operations net of income tax
(benefit) expense of $(302), $0, $3,213, and $0 for the respective periods		(454	)		--			12,798			--
Net Income (Loss) from Discontinued Operations		(506	)		2,040			12,386			5,354
Total Net Income (Loss)		6,368			6,101			30,892			(3,400	)
Preferred Dividend Requirement and Other Adjustments		184			187			874			650
Earnings Available for Common Shares	$	6,184		$	5,914		$	30,018		$	(4,050	)
Average Number of Common Shares Outstanding—Basic		35,933,003			35,806,453			35,911,993			35,775,418
Average Number of Common Shares Outstanding—Diluted		36,171,555			36,076,421			36,150,545			35,775,418
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	0.18		$	0.11		$	0.50		$	(0.26	)
Discontinued Operations (net of other adjustments)		(0.01	)		0.06			0.34			0.15
	$	0.17		$	0.17		$	0.84		$	(0.11	)
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$	0.18		$	0.11		$	0.50		$	(0.26	)
Discontinued Operations (net of other adjustments)		(0.01	)		0.05			0.33			0.15
	$	0.17		$	0.16		$	0.83		$	(0.11	)
Dividends Declared Per Common Share	$	0.2975		$	0.2975		$	0.8925		$	0.8925
See accompanying notes to consolidated financial statements.

4

Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)
	Nine Months Ended September 30,
(in thousands)	2011			2010
Cash Flows from Operating Activities
Net Income (Loss)	$	30,892		$	(3,400	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		(12,798	)		--
Net Loss (Income) from Discontinued Operations		412			(5,354	)
Depreciation and Amortization		58,748			56,404
Asset Impairment Charge		--			19,740
Deferred Tax Credits		(1,834	)		(2,037	)
Deferred Income Taxes		10,144			17,373
Change in Deferred Debits and Other Assets		11,844			(1,298	)
Discretionary Contribution to Pension Fund		--			(20,000	)
Change in Noncurrent Liabilities and Deferred Credits		1,742			5,534
Allowance for Equity (Other) Funds Used During Construction		(576	)		(8	)
Change in Derivatives Net of Regulatory Deferral		(177	)		202
Stock Compensation Expense – Equity Awards		1,760			1,973
Other—Net		(301	)		(444	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(25,251	)		(47,442	)
Change in Inventories		(11,845	)		87
Change in Other Current Assets		11,038			4,586
Change in Payables and Other Current Liabilities		3,463			1,103
Change in Interest Payable and Income Taxes Receivable/Payable		764			29,886
Net Cash Provided by Continuing Operations		78,025			56,905
Net Cash Provided by Discontinued Operations		2,347			3,970
Net Cash Provided by Operating Activities		80,372			60,875
Cash Flows from Investing Activities
Capital Expenditures		(71,337	)		(61,382	)
Proceeds from Disposal of Noncurrent Assets		3,055			2,709
Net Decrease (Increase) in Other Investments		234			(1,669	)
Net Cash Used in Investing Activities - Continuing Operations		(68,048	)		(60,342	)
Net Proceeds from Sale of Discontinued Operations		84,330			--
Net Cash Used in Investing Activities - Discontinued Operations		(6,065	)		(1,485	)
Net Cash Provided by (Used in) Investing Activities		10,217			(61,827	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(10,031	)		4,528
Net Short-Term Borrowings		(40,415	)		86,388
Proceeds from Issuance of Common Stock		--			549
Proceeds from Issuance of Class B Stock of Subsidiary		--			158
Common Stock Issuance Expenses		--			(142	)
Payments for Retirement of Common Stock		(152	)		(401	)
Payments for Retirement of Class B Stock of Subsidiary		--			(1,017	)
Proceeds from Issuance of Long-Term Debt		2,007			95
Short-Term and Long-Term Debt Issuance Expenses		(1,577	)		(1,699	)
Payments for Retirement of Long-Term Debt		(683	)		(59,166	)
Dividends Paid and Other Distributions		(33,011	)		(32,824	)
Net Cash Used in Financing Activities - Continuing Operations		(83,862	)		(3,531	)
Net Cash Provided by Financing Activities - Discontinued Operations		201			256
Net Cash Used in Financing Activities		(83,661	)		(3,275	)
Cash and Cash Equivalents at Beginning of Period – Discontinued Operations		--			(609	)
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations		(324	)		(205	)
Net Change in Cash and Cash Equivalents		6,604			(5,041	)
Cash and Cash Equivalents at Beginning of Period		--			5,041
Cash and Cash Equivalents at End of Period	$	6,604		$	--
See accompanying notes to consolidated financial statements.

5

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the condensed consolidated financial statements for the periods presented. The condensed 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 month and nine month periods ended September 30, 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 the Financial Accounting Standards Board Accounting Standards Codification (ASC). 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 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. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Percentage-of-Completion Revenues		34.9	%		26.3	%		33.5	%		26.5	%

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

	September 30,			December 31,
(in thousands)	2011			2010
Costs Incurred on Uncompleted Contracts	$	525,259		$	460,125
Less Billings to Date		(507,751	)		(430,471	)
Plus Estimated Earnings Recognized		26,756			31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

6

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:

	September 30,			December 31,
(in thousands)	2011			2010
Costs and Estimated Earnings in Excess of Billings	$	54,309		$	67,352
Billings in Excess of Costs and Estimated Earnings		(10,045	)		(6,467	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

Included in Costs and Estimated Earnings in Excess of Billings are the following amounts at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer:

	September 30,		December 31,
(in thousands)	2011		2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	38,843	$	58,990

These amounts are 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.

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures.

(in thousands)
Warranty Reserve Balance, December 31, 2010	$	2,676
Provision for Warranties Used During the Year		845
Less Settlements Made During the Year		991
Increase in Warranty Estimates for Prior Years		145
Warranty Reserve Balance, September 30, 2011	$	2,675

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 the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Accounts Receivable include the following amounts, billed under contracts by the Company’s subsidiaries, that have been retained by customers pending project completion:

	September 30,		December 31,
(in thousands)	2011		2010
Accounts Receivable Retained by Customers	$	12,447	$	11,848

7

Sales of Receivables

DMI is a party to a $40 million receivables sales agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement is subject to renewal in March 2012. The current discount rate is 3-month LIBOR plus 4%. 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. Following are the amounts of accounts receivable sold and discounts, fees and commissions paid under DMI’s receivables sales agreement with General Electric Capital Corporation:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Accounts Receivable Sold	$	20,662	$	14,800	$	48,802	$	44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable		153		45		406		152

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, requires enhanced disclosures about assets and liabilities measured at fair value and 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.

8

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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash	$	513	$	--
Forward Gasoline Purchase Contracts		24
Forward Energy Contracts				3,929
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				13,560
Investments of Captive Insurance Company:
Corporate Debt Securities		9,172
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account		3,000
Total Assets	$	12,709	$	17,489
Liabilities:
Forward Energy Contracts	$	--	$	16,390
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				125
Total Liabilities	$	--	$	16,515

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 and nine months ended September 30, 2010 reflect the reclassifications of the assets and liabilities, operating results and cash flows of IPH and E.W. Wylie’s (Wylie) heavy haul and specialized shipment and transportation of wind turbine components business to discontinued operations as a result of second quarter 2011 sale of IPH and the Company's decision to exit the heavy haul and specialized shipment and transportation of wind turbine components business. The Company sold 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 and nine months ended September 30, 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 the following increases in Operating Revenues and Operating Income and decreases in Other Income:

	Three Months Ended		Nine Months Ended
(in thousands)	September 30, 2010		September 30, 2010
MNCIP Incentives reclassified from Other Income to Operating Revenue	$	550	$	2,151

The correction had no impact on the Company’s net income, total assets, or operating cash flows for the three and nine months ended September 30, 2010.

9

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2011		2010
Finished Goods	$	26,218	$	29,113
Work in Process		14,248		7,171
Raw Material, Fuel and Supplies		50,648		42,986
Total Inventories	$	91,114	$	79,270

Goodwill

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

(in thousands)	Gross Balance December 31, 2010		Accumulated Impairments			Balance (net of impairments) December 31, 2010		Adjustments to Goodwill in 2011		Balance (net of impairments) September 30, 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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	3,024	$	13,787	15 – 25 years
Covenants Not to Compete		1,704		1,697		7	3 – 5 years
Other Intangible Assets Including Contracts		1,030		902		128	5 – 30 years
Total	$	19,545	$	5,623	$	13,922
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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Amortization Expense – Intangible Assets	$	220	$	238	$	668	$	784

(in thousands)	2011		2012		2013		2014		2015
Estimated Amortization Expense – Intangible Assets	$	887	$	911	$	947	$	947	$	931

10

Comprehensive Income

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Net Income (Loss)	$	6,368		$	6,101	$	30,892		$	(3,400	)
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gains and (Reversal of   Previously Recorded Foreign Currency Translation Gains)		--			484		(3,977	)		295
Amortization of Unrecognized Losses and Costs   Related to Postretirement Benefit Programs		47			105		(395	)		314
Unrealized Gain (Loss) on Available-for-Sale Securities		(2	)		54		6			86
Total Other Comprehensive Income (Loss)		45			643		(4,366	)		695
Total Comprehensive Income (Loss)	$	6,413		$	6,744	$	26,526		$	(2,705	)

Supplemental Disclosures of Cash Flow Information

	Nine Months Ended
	September 30,
(in thousands)	2011		2010
Increases in Accounts Payable Related to Capital Expenditures	$	1,790	$	63

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 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.

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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. One customer of DMI has accounted for 11.2% of the Company’s consolidated revenues in the first nine months of 2011. 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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
United States of America		98.2	%		98.9	%		98.2	%		98.2	%
Canada		1.3	%		0.9	%		1.5	%		1.6	%
All Other Countries		0.5	%		0.2	%		0.3	%		0.2	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for three and nine month periods ended September 30, 2011 and 2010 and total assets by business segment as of September 30, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	85,172		$	89,315		$	254,799		$	258,294
Wind Energy		65,007			40,389			187,534			134,764
Manufacturing		55,815			43,342			170,486			130,880
Construction		53,247			36,885			139,895			84,808
Plastics		36,231			26,736			99,082			76,562
Health Services		21,853			24,300			67,331			73,116
Corporate Revenues and Intersegment Eliminations		(1,567	)		(1,221	)		(5,036	)		(4,415	)
Total	$	315,758		$	259,746		$	914,091		$	754,009

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Interest Charges

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Electric	$	4,796		$	5,172	$	14,874		$	15,791
Wind Energy		1,925			1,641		5,806			4,511
Manufacturing		1,323			1,298		3,984			3,839
Construction		251			190		698			463
Plastics		411			403		1,176			1,194
Health Services		451			377		1,295			902
Corporate and Intersegment Eliminations		(449	)		206		(487	)		1,007
Total	$	8,708		$	9,287	$	27,346		$	27,707

Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	3,364		$	4,257		$	5,972		$	8,562
Wind Energy		(863	)		(3,529	)		(4,676	)		(5,053	)
Manufacturing		591			(349	)		3,650			(4,800	)
Construction		(115	)		435			(195	)		(872	)
Plastics		1,295			238			3,198			873
Health Services		115			311			863			(66	)
Corporate		(2,278	)		(1,970	)		(4,618	)		(5,269	)
Total	$	2,109		$	(607	)	$	4,194		$	(6,625	)

Earnings Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	10,900		$	12,265		$	29,428		$	24,188
Wind Energy		(3,497	)		(7,120	)		(16,443	)		(9,755	)
Manufacturing		1,083			(383	)		6,071			(16,234	)
Construction		(179	)		645			(320	)		(1,337	)
Plastics		1,970			367			4,908			1,380
Health Services		125			421			1,155			(235	)
Corporate		(3,712	)		(2,319	)		(6,845	)		(7,313	)
Discontinued Operations		(506	)		2,038			12,064			5,256
Total	$	6,184		$	5,914		$	30,018		$	(4,050	)

Total Assets

	September 30,		December 31,
(in thousands)	2011		2010
Electric	$	1,101,146	$	1,106,261
Wind Energy		169,138		172,753
Manufacturing		152,693		144,272
Construction		74,639		60,978
Plastics		84,463		73,508
Health Services		72,566		75,898
Corporate		57,262		43,102
Discontinued Operations		77		93,783
Total	$	1,711,984	$	1,770,555

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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% base rate increase as well as a 3.8% interim rate increase.On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates, and approving the interim rate increase, as requested, 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. The MPUC authorized a revenue increase of approximately $5.0 million, or 3.76% in base rate revenues, excluding the effect of moving recovery of wind investments to base rates. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years (see discussion below), (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of MNCIP costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota fuel clause adjustment (FCA). Final rates went into effect October 1, 2011. The overall increase to customers will be approximately 1.6% compared to the authorized interim rate increase of 3.8%,which resulted in an interim rate refund of approximately $3.9 million. As of September 30, 2011, OTP had recognized a $3.9 million refund liability for revenue billed under interim rates from June 1, 2010 through September 30, 2011. On October 31, 2011 OTP issued the interim rate refund, including interest, to Minnesota customers. 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 has a regulatory asset of $3.5 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 September 30, 2011. The recovery of MNRRA costs was moved to base rates as of October 1, 2011 under the MPUC’s April 25, 2011 general rate case order with the exception of the remaining balance of this regulatory asset.

In its April 25, 2011 general rate case order, 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. Final rates went into effect on October 1, 2011. The Company will continue to utilize the rider cost recovery mechanism until the remaining balance of the current transmission projects has been collected as well as to recover costs associated with approved regional projects. OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. Comments and reply comments have been filed but the MPUC has not yet scheduled a hearing on the request.

Conservation Improvement Program—OTP has a regulatory asset of $7.2 million for allowable costs and financial incentives that are eligible for recovery through the MNCIP rider that have not been billed to Minnesota customers as of  September 30, 2011. OTP has recognized $3.7 million in financial incentives relating to 2010. A final decision regarding the 2010 MNCIP financial incentive is expected in December 2011. OTP currently has $1.3 million of income recognized relating to the 2011 MNCIP financial incentive. 

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. The request is under review by the NDPSC.

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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 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. On April 21, 2011, the SDPUC issued its written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50 percent for the interim rates and final rates. Final rates were effective with bills rendered on and after June 1, 2011.

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 has been assigned to an SDPUC outside consultant and likely will not be on an SDPUC agenda until later this year.

Capacity Expansion 2020 (CapX2020)

CapX2020 is a joint initiative of 11 investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kiloVolt (kV) Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji – Grand Rapids Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project.

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

The Fargo Project—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 Fargo Project, was accepted by the Federal Energy Regulatory Commission (FERC) in the third quarter of 2010. The Monticello to St. Cloud portion of the Fargo Project is scheduled for completion in December 2011.

The Minnesota route permit application for the St. Cloud to Fargo portion of the Fargo Project was filed on October 1, 2009. Minnesota State Environmental Impact Statement (EIS) scoping meetings were held in September 2010 and public hearings were held in November 2010. The MPUC approved the route permit on June 24, 2011. The agreements for Phase 2, which consists of the line section between St. Cloud and Alexandria, Minnesota were signed by all of the participants on August 3, 2011. Easement acquisition discussions with landowners are underway. Construction is expected to begin in November 2011.

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 Project. The NDPSC approved the CPCN in January 2011. The application for the North Dakota Certificate of Corridor Compatibility (CCC) was filed on December 30, 2010 and was revised in March 2011. The June 23, 2011 hearing for the North Dakota CCC application was postponed. A combined North Dakota CCC and route permit application was submitted to the NDPSC on October 3, 2011.

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The Brookings Project—The Minnesota route permit application for the Brookings Project was filed in the fourth quarter of 2008. The MPUC approved the final line segment route permit for the Brookings 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 the South Dakota route permit was approved in June 2011. The MISO board of directors granted conditional approval of the Multi-Value Project (MVP) cost allocation designation under the MISO Tariff for the Brookings Project. Once the MISO board finalizes its analysis of all of the MVP projects in its study portfolio, the MISO board will be in a position to remove the condition, which is anticipated to occur in December 2011. Easement acquisition discussions with landowners are underway.

The Bemidji Project—OTP serves as the lead utility for the Bemidji Project, which has an expected in-service date in late 2012. 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 and approved on October 28, 2010.  The joint state and federal EIS was published by 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 the 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 Leech Lake Reservation. The owners of the Bemidji Project, including OTP, filed reply comments in opposition to the LLBO’s request. On April 25, 2011, the Bemidji Project owners filed a declaratory judgment in the U.S. District Court for Minnesota against the LLBO seeking that no consent from the LLBO is required for the project to run through the LLBO reservation boundaries since the project is located exclusively on non LLBO lands. On June 22, 2011, Federal District Judge Frank issued a preliminary injunction which ordered the LLBO to cease and desist from pursuing its claims of jurisdiction over the project in tribal court or the MPUC or from taking any other actions to interfere with the routing or construction of the project. The parties had engaged in court supervised mediation; however, no agreement was reached. The preliminary injunction remains in place prohibiting the LLBO from interfering with project construction.

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: the Fargo Project, the Brookings Project and the Bemidji Project. 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 issued 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 Project and its associated impact on North Dakota. On April 29, 2011, OTP filed its compliance filing with the NDPSC, seeking a determination of continued prudence for OTP’s investment in the Brookings Project. The NDPSC hearing occurred on July 25, 2011. On August 23, 2011, an executed settlement agreement on continued prudence was filed and the hearing for consideration of the settlement agreement on continued prudence was held on October 26, 2011.  A final decision is expected later this year.

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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 developed and submitted its implementation plan and associated implementation rules to the EPA on January 21, 2011. The DENR and EPA have agreed on non-substantive rule revisions, which were adopted by the Board of Minerals and Environment and became effective on September 19, 2011. South Dakota developed and submitted its revised implementation plan and associated implementation rules to EPA on September 19, 2011. Under the South Dakota implementation plan, and its implementing rules, 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 (ADP) 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. On June 1, 2011, the MPUC referred the matter to the Office of Administrative Hearings for contested case proceedings before an administrative law judge (ALJ). Evidentiary hearings took place on September 14 and 15, 2011 with an ALJ report and recommendation expected by November 9, 2011. A decision by the MPUC is expected in December. OTP filed an application for an ADP with the NDPSC on May 20, 2011 with a decision expected by December 20, 2011. North Dakota has hired a consulting firm to evaluate the ADP request. Evidentiary hearings are scheduled for November 29 and 30, 2011. 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 which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers was $3,199,000 (which excludes $3,246,000 of project transmission-related costs). 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 South Dakota portion of 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.

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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:

	September 30,		December 31,		Remaining Recovery/
(in thousands)	2011		2010		Refund Period
Regulatory Assets – Current:
Accrued Cost-of-Energy Revenue	$	2,552	$	2,387	23 months
Regulatory Assets – Long Term:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial
Losses on Pensions and Other Postretirement Benefits	$	70,265	$	74,156	see notes
Deferred Marked-to-Market Losses		13,560		12,054	47 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		7,158		6,655	21 months
Minnesota Renewable Resource Rider Accrued Revenues		3,452		6,834	30 months
Big Stone II Unrecovered Project Costs – Minnesota		2,758		6,445	60 months
Debt Reacquisition Premiums		2,582		3,107	252 months
Accumulated ARO Accretion/Depreciation Adjustment		2,545		2,218	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		2,508		3,460	22 months
Deferred Income Taxes		2,025		5,785	asset lives
North Dakota Renewable Resource Rider Accrued Revenues		1,379		2,415	27 months
General Rate Case Recoverable Expenses		1,189		1,773	28 months
Big Stone II Unrecovered Project Costs – South Dakota		936		1,419	112 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		436		717	14 months
South Dakota – Asset-Based Margin Sharing Shortfall		257		501	5 months
Minnesota Transmission Rider Accrued Revenues		252		34	15 months
Deferred Holding Company Formation Costs		152		193	33 months
Total Regulatory Assets – Long Term	$	111,454	$	127,766
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	64,031	$	61,740	asset lives
Deferred Income Taxes		3,691		4,289	asset lives
Minnesota Transmission Rider Accrued Refund		1,081		--	see notes
Deferred Marked-to-Market Gains		125		175	35 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		124		128	267 months
South Dakota – Nonasset-Based Margin Sharing Excess		61		84	15 months
Total Regulatory Liabilities	$	69,113	$	66,416
Net Regulatory Asset Position	$	44,893	$	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 September 30, 2011 are related to forward purchases of energy scheduled for delivery through August 2015.

18

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 September 30, 2011.

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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 252 months.

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

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.

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.

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 September 30, 2011.

General Rate Case Recoverable Expenses relate to expenses incurred during the rate case proceedings that are eligible for recovery.

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 September 30, 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.

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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.

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.

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 September 30, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to September 30, 2011:

(in thousands)	September 30, 2011			December 31, 2010
Other Current Assets – Marked-to-Market Gain	$	3,929		$	6,875
Regulatory Assets – Deferred Marked-to-Market Loss		13,560			12,054
Total Assets		17,489			18,929
Derivative Liabilities – Marked-to-Market Loss		(16,390	)		(17,991	)
Regulatory Liabilities – Deferred Marked-to-Market Gain		(125	)		(175	)
Total Liabilities		(16,515	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	974		$	763

(in thousands)	Year-to-Date September 30, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(225	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(28	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		(14	)
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(72	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		424
Changes in Fair Value of Contracts Entered into in 2011		550
Net Fair Value End of Period	$	974

The September 30, 2011 balance of recognized but unrealized net mark-to-market gains on the forward energy and capacity purchases and sales is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	4th Quarter 2011		2012		Total
Net Gain	$	354	$	620	$	974

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The following realized and unrealized net gains on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Net Gains on Forward Electric Energy Contracts	$	456	$	144	$	587	$	1,945

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.

The following table provides information on OTP’s credit risk exposure on delivered and marked-to-market forward contracts as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	792		5	$	1,129		4
Net Credit Risk to Single Largest Counterparty	$	372			$	585

OTP had no exposure at September 30, 2011 or December 31, 2010 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The credit risk exposures include 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 subsequent to the reporting date. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2011 and December 31, 2010:

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2011			December 31, 2010
Loss Contracts Covered by Deposited Funds	$	2,551		$	427
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,803			10,904
Loss Contracts with No Ratings Triggers or Deposit Requirements		36			6,660
Total Current Liability – Marked-to-Market Loss	$	16,390		$	17,991
1   Certain 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.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,803		$	10,904
Offsetting Gains with Counterparties under Master Netting Agreements		(3,411	)		(6,219	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,392		$	4,685

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6.  Common Shares and Earnings Per Share

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2010 through September 30, 2011:

Common Shares Outstanding, December 31, 2010	36,002,739
Issuances:
Restricted Stock Issued to Employees	24,600
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	17,325
Retirements:
Shares Withheld for Individual Income Tax Requirements	(6,641	)
Common Shares Outstanding, September 30, 2011	36,062,023

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 prices:

Three Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

Nine Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

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7.  Share-Based Payments

The Company has five share-based payment programs.

Stock Incentive Awards

On April 11, 2011 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors, executive officers and key employees under the 1999 Stock Incentive Plan, as amended:

Award	Shares/Units Granted	Grant-Date Fair Value per Share		Vesting
Restricted Stock Granted to Nonemployee Directors	24,000	$	22.51	25% per year through April 8, 2015
Restricted Stock Granted to Executive Officers	24,600	$	22.51	25% per year through April 8, 2015
SStock Performance Awards Granted to Executive Officers	48,600	$	23.61	December 31, 2013
Restricted Stock Units Granted to Employees	19,800	$	18.03	100% on April 8, 2015

The restricted shares granted to the Company’s nonemployee directors and executive officers (which includes OTP’s president) are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was the average of the high and low market price per share on the date of grant.

Under the performance share 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 measurement 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 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.

The grant date fair value of each restricted stock unit was based on the market value of one share of the Company’s common stock on the grant date, discounted for the value of the dividend exclusion over the four-year vesting period.

As of September 30, 2011 the remaining unrecognized compensation expense related to stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.6 years.

Compensation expense recognized under the Company’s stock-based payment programs:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011		2010			2011		2010
Employee Stock Purchase Plan (15% discount)	$	51	$	64		$	185	$	205
Restricted Stock Granted to Directors		185		148			571		446
Restricted Stock Granted to Employees		511		239			759		519
Stock Performance Awards Granted to Executive Officers		1,766		722			1,766		879
Restricted Stock Units Granted to Employees		92		(20	)		244		137
Totals	$	2,605	$	1,153		$	3,525	$	2,186

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9.  Commitments and Contingencies

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

In the first quarter of 2011, OTP entered into additional energy purchase agreements increasing its commitments for capacity and energy requirements. Amounts of commitments for OTP’s capacity and energy requirements under agreements extending through 2032 were as follows:

Capacity and Energy Requirements (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	21,268	$	20,134	$	1,134
2012		25,025		21,637		3,388
2013		21,868		16,492		5,376
2014		24,701		15,388		9,313
2015		18,915		12,307		6,608
Beyond 2015		78,879		78,879		--
Total	$	190,656	$	164,837	$	25,819

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. In the first half of 2011, OTP extended its contract for the purchase of coal for Hoot Lake Plant resulting in an increase in minimum purchase commitments. OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP is now committed to the minimum purchase, dating from January 1, 2011, or to make payments in lieu thereof in the following amounts:

Coal and Freight Purchase Commitments (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	52,819	$	47,122	$	5,697
2012		48,444		34,958		13,486
2013		9,855		9,855		--
2014		9,854		9,854		--
2015		9,854		9,854		--
Beyond 2015		4,106		4,106		--
Total	$	134,932	$	115,749	$	19,183

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 September 30, 2011 will not be material.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood that a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to product warranty, environmental remediation, litigation matters, possible liquidated damages and the resolution of matters related to open tax years. Should any of these items result in a liability being incurred, the range of loss could be as high as $9.0 million. Additionally, we may become subject to significant claims of which we are unaware, or the claims of which we are aware may result in our incurring a significantly greater liability than we anticipate.

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10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on September 30, 2011		Restricted due to Outstanding Letters of Credit		Available on September 30, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	20,000	$	1,374	$	178,626	$	144,350
OTP Credit Agreement		170,000		19,010		1,050		149,940		144,436
Total	$	370,000	$	39,010	$	2,424	$	328,566	$	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 at Northern Pipe Products, Inc. (NPP), 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. On April 6, 2011 Otter Tail Corporation borrowed $0.5 million under a North Dakota Development Fund loan to finance additional capital investments at NPP. The seven-year unsecured note bears interest at 3.95% with monthly principal and interest payments through April 1, 2018.

On July 29, 2011, OTP entered into a Note Purchase Agreement with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers in a private placement transaction $140 million aggregate principal amount of OTP’s 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes).  The 2021 Notes are expected to be issued on December 1, 2011, subject to the satisfaction of certain customary conditions to closing.  OTP intends to use a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of OTP’s 6.63% Senior Notes due December 1, 2011 and $10.4 million aggregate principal amount of its pollution control refunding revenue bonds due December 1, 2012.  The remaining proceeds of the 2021 Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the 2021 Notes and for other general corporate purposes.

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The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	19,010	$	65		$	20,000	$	39,075
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011	$	90,000						$	90,000
Pollution Control Refunding Revenue Bonds,   Variable, 1.50% at September 30, 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		20,105							20,105
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 September 30, 2011				$	4,220		1,929		6,149
Total	$	280,595		$	4,220	$	151,929	$	436,744
Less: Current Maturities		--			3,124		162		3,286
Unamortized Debt Discount		--			--		4		4
Total Long-Term Debt	$	280,595		$	1,096	$	151,763	$	433,454
Total Short-Term and Long-Term Debt (with current maturities)	$	299,605		$	4,285	$	171,925	$	475,815

December 31, 2010 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	25,314	$	--		$	54,176	$	79,490
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 December 31, 2010, due December 1, 2012		10,400							10,400
9.000% Notes, due December 15, 2016						$	100,000		100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000							33,000
Grant County, South Dakota Pollution Control    Refunding Revenue Bonds 4.65%, due September 1, 2017		5,100							5,100
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 December 31, 2010				$	4,706				4,706
Total	$	280,715		$	4,706	$	150,000	$	435,421
Less: Current Maturities		--			604		--		604
Unamortized Debt Discount		--			--		5		5
Total Long-Term Debt	$	280,715		$	4,102	$	149,995	$	434,812
Total Short-Term and Long-Term Debt (with current maturities)	$	306,029		$	4,706	$	204,171	$	514,906

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11. Class B Stock Options of Subsidiary

In conjunction with the sale of IPH on May 6, 2011, all 363 outstanding IPH Class B common share options were cancelled by mutual agreement between the issuer and the holders of the options and a liability to the holders of the options was established based on the fair value of the options on May 6, 2011. The liability was assumed by the new owner of IPH. The 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 on May 6, 2011. The book value of IPH Class B common share options prior to their cancellation on May 6, 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 was charged to retained earnings and earnings available for common shares were 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 September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	961		$	997		$	3,311		$	3,491
Interest Cost on Projected Benefit Obligation		3,150			2,990			9,500			9,050
Expected Return on Assets		(3,530	)		(3,483	)		(10,605	)		(10,283	)
Amortization of Prior-Service Cost		125			172			325			512
Amortization of Net Actuarial Loss		663			511			1,963			1,501
Net Periodic Pension Cost	$	1,369		$	1,187		$	4,494		$	4,271

The Company did not make a contribution to its pension plan in the nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Service Cost—Benefit Earned During the Period	$	20	$	165	$	61	$	495
Interest Cost on Projected Benefit Obligation		407		417		1,223		1,253
Amortization of Prior-Service Cost		18		19		55		55
Amortization of Net Actuarial Loss		62		120		184		358
Net Periodic Pension Cost	$	507	$	721	$	1,523	$	2,161

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 September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	425		$	375		$	1,275		$	1,225
Interest Cost on Projected Benefit Obligation		850			855			2,550			2,405
Amortization of Transition Obligation		187			187			561			561
Amortization of Prior-Service Cost		50			58			150			158
Amortization of Net Actuarial Loss		213			248			639			624
Effect of Medicare Part D Expected Subsidy		(525	)		(558	)		(1,575	)		(1,558	)
Net Periodic Postretirement Benefit Cost	$	1,200		$	1,165		$	3,600		$	3,415

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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.

	September 30, 2011						December 31, 2010
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Short-Term Investments	$	6,604		$	6,604		$	--		$	--
Long-Term Debt		(433,454	)		(479,567	)		(434,812	)		(474,307	)

15. Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Income (Loss) Before Income Taxes – Continuing Operations	$	8,983		$	3,454		$	22,700		$	(15,379	)
Income Tax Expense (Benefit) – Continuing Operations		2,109			(607	)		4,194			(6,625	)
Effective Income Tax Rate – Continuing Operations		23.5	%		(17.6	)%		18.5	%		43.1	%

The increase in Income Tax Expense (Benefit) - Continuing Operations for the three months ended September 30, 2011 compared with the three months ended September 30, 2010 is mainly due to the increase in income before income taxes between the quarters, but also due to DMI deferring recognition of tax benefits in the third 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 $0.5 million in the third quarter of 2011. The Company’s effective income tax rates for the three months ended September 30, 2011 and 2010 were decreased as a result of recording $1.4 million and $1.6 million, respectively, in federal production tax credits (PTCs) earned on kilowatt-hours (kwhs) generated from tax credit qualified wind turbines owned by OTP.

The increase in Income Tax Expense (Benefit) - Continuing Operations for the nine months ended September 30, 2011 compared with the nine months ended September 30, 2010 is mainly due to the increase in income before income taxes between the periods.  Also, only $2.8 million of ShoreMaster’s $12.2 million second quarter 2010 goodwill impairment loss was deductible for income taxes and DMI is deferring recognition of tax benefits in the first nine months of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s 2011 deferred tax benefits totaled $2.4 million through September 30, 2011. The Company’s effective income tax rates for the nine months ended September 30, 2011 and 2010 were decreased as a result of recording $5.3 million and $4.7 million, respectively, in federal PTCs earned on kwhs generated from tax credit qualified wind turbines owned by OTP.

28

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. In the second quarter of 2011, Wylie decided to exit its heavy haul/specialized shipment and transportation of wind turbine components business, determining that the risks associated with continuing to provide these services outweighed any potential profits to be derived from these operations. The financial position, results of operations, and cash flows of IPH and Wylie’s specialized shipment and transportation of wind turbine components business are reported as discontinued operations in the Company’s consolidated financial statements as of September 30, 2011 and December 31, 2010, and for the three and nine month periods ended September 30, 2011 and 2010. Following are summary presentations of the results of discontinued operations for the three and nine month periods ended September 30, 2011 and 2010 and of the major components of assets and liabilities of discontinued operations as of September 30, 2011 and December 31, 2010:

	Three Months Ended
	September 30, 2011									September 30, 2010
(in thousands)	IPH			Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	--		$	--		$	--		$	19,478	$	2,046	$	21,524
Income (Loss) Before Income Taxes	$	--		$	(86	)	$	(86	)	$	3,183	$	82	$	3,265
Gain (Loss) on Disposition - Pretax		(756	)		--			(756	)		--		--		--
Income Tax Expense (Benefit)		(302	)		(34	)		(336	)		1,192		33		1,225
Net Income (Loss)	$	(454	)	$	(52	)	$	(506	)	$	1,991	$	49	$	2,040

	Nine Months Ended
	September 30, 2011								September 30, 2010
(in thousands)	IPH		Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	28,125	$	5,448		$	33,573		$	56,648	$	4,700	$	61,348
Income (Loss) Before Income Taxes	$	3,840	$	(4,650	)	$	(810	)	$	8,306	$	129	$	8,435
Gain on Disposition - Pretax		16,011		--			16,011			--		--		--
Income Tax Expense (Benefit)		4,675		(1,860	)		2,815			3,029		52		3,081
Net Income (Loss)	$	15,176	$	(2,790	)	$	12,386		$	5,277	$	77	$	5,354

	September 30, 2011				December 31, 2010
(in thousands)	Wylie-Wind		Total		IPH		Wylie-Wind		Total
Current Assets	$	2	$	2	$	24,836	$	2,461	$	27,297
Goodwill		--		--		24,324		--		24,324
Other Intangibles - Net		--		--		10,852		--		10,852
Net Plant		75		75		30,672		638		31,310
Assets of Discontinued Operations	$	77	$	77	$	90,684	$	3,099	$	93,783
Current Liabilities	$	77	$	77	$	6,839	$	4,150	$	10,989
Deferred Income Taxes		--		--		11,553		--		11,553
Long-Term Debt		--		--		634		--		634
Liabilities of Discontinued Operations	$	77	$	77	$	19,026	$	4,150	$	23,176

29

Because IPH was a material subsidiary, the Company is providing the following pro forma summary presentations of its 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 (Loss)		(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.

30

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

RESULTS OF OPERATIONS

Following is an analysis of our operating results by business segment for the three and nine month periods ended September 30, 2011 and 2010, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2011 and our business outlook for the remainder of 2011.

Comparison of the Three Months Ended September 30, 2011 and 2010

Consolidated operating revenues were $315.8 million for the three months ended September 30, 2011 compared with $259.7 million for the three months ended September 30, 2010. Operating income was $17.2 million for the three months ended September 30, 2011 compared with operating income of $12.0 million for the three months ended September 30, 2010. The Company recorded diluted earnings per share from continuing operations of $0.18 for the three months ended September 30, 2011 compared with $0.11 for the three months ended September 30, 2010 and total diluted earnings per share of $0.17 for the three months ended September 30, 2011 compared with $0.16 for the three months ended September 30, 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 September 30, 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)	September 30, 2011		September 30, 2010
Operating Revenues:
Electric	$	55	$	43
Nonelectric		1,512		1,178
Cost of Goods Sold		1,507		1,150
Other Nonelectric Expenses		60		71

Electric

	Three Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Retail Sales Revenues	$	73,766	$	77,779	$	(4,013	)		(5.2	)
Wholesale Revenues – Company Generation		6,107		7,313		(1,206	)		(16.5	)
Net Revenue – Energy Trading Activity		592		239		353			147.7
Other Revenues		4,707		3,984		723			18.1
Total Operating Revenues	$	85,172	$	89,315	$	(4,143	)		(4.6	)
Production Fuel		19,080		18,210		870			4.8
Purchased Power – System Use		7,488		10,254		(2,766	)		(27.0	)
Other Operation and Maintenance Expenses		27,323		27,098		225			0.8
Depreciation and Amortization		10,046		10,036		10			0.1
Property Taxes		2,601		2,271		330			14.5
Operating Income	$	18,634	$	21,446	$	(2,812	)		(13.1	)

The $4.0 million decrease in retail sales revenues reflects: (1) a $2.5 million decrease in revenues mainly due to a 1.0% decrease in total retail kilowatt-hour (kwh) sales driven by decreases in commercial and industrial kwh sales, (2) a $0.6 million reduction in revenue related to the recovery of lower fuel and purchased power costs, (3) a $0.5 million decrease in resource recovery and transmission rider revenues, and (4) a $0.4 million refund accrual for excess amounts collected under interim rates in Minnesota in the third quarter of 2011. Revenues related to the recovery of fuel and purchased power costs decreased as a result of a reduction in purchased power costs in excess of an increase in fuel costs incurred to serve retail load.

31

Wholesale electric revenues from company-owned generation decreased $1.2 million due to a 23.0% decline in wholesale kwh sales, partially offset by an 8.4% increase in the average price per wholesale kwh sold, as a result of a 5.8% reduction in kwh generation at Otter Tail Power Company (OTP) generating units and lower demand in wholesale markets. Net gains from energy trading activities, including net mark-to-market gains on forward energy contracts, increased $0.4 million mainly as a result of an increase in mark-to-market gains on OTP’s open energy contracts. Other electric operating revenues increased $0.7 million as a result of an increase in transmission tariff revenues.

The $0.9 million increase in fuel costs is due to a 9.4% increase in the cost of fuel per kwh generated, partially offset by a 4.3% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators. The cost of purchased power for retail sales decreased $2.8 million as a result of a 40.2% decrease in kwhs purchased, partially offset by 22.1% increase in the cost per kwh purchased. The $0.3 million increase in property taxes reflects increases in Minnesota and South Dakota property taxes due to capital additions and increases in assessments, assessed values and the percentage of a property’s assessed value subject to taxation in those states.

Wind Energy

In the second quarter of 2011, E. W. Wylie Corporation (Wylie) exited the wind-heavy haul business. Accordingly, the results of operations of Wylie’s wind-heavy haul business are reported as discontinued operations.

	Three Months Ended
	September 30,								%
(in thousands)	2011			2010			Change		Change
Wind Tower Revenues	$	52,595		$	29,330		$	23,265		79.3
Transportation Revenues		12,412			11,059			1,353		12.2
Total Operating Revenues	$	65,007		$	40,389			24,618		61.0
Cost of Goods Sold		48,893			33,847			15,046		44.5
Operating Expenses		15,635			12,689			2,946		23.2
Depreciation and Amortization		3,005			2,803			202		7.2
Operating Loss	$	(2,526	)	$	(8,950	)	$	6,424		(71.8	)

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 70.8% increase in tower production.

● Revenues at Wylie, our flatbed trucking company, increased mainly as a result of an increase in fuel surcharge revenues related to a 33.0% increase in the average cost per gallon of fuel consumed.

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

Cost of goods sold at DMI increased $15.0 million, reflecting $16.9 million in increased costs related to the increase in towers produced, partially offset by a $1.1 million decrease in indirect material costs and $0.9 million in productivity gains mainly due to a reduction in costs incurred to rework towers.

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

● Operating expenses at DMI decreased $0.3 million between the quarters as a result of decreases in expenditures for building repairs and maintenance and professional services.

● Operating expenses at Wylie increased $3.2 million as a result of increases in fuel prices, contractor and brokerage settlement costs and insurance costs.

32

Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Operating Revenues	$	55,815	$	43,342	$	12,473			28.8
Cost of Goods Sold		43,292		33,176		10,116			30.5
Operating Expenses		6,293		6,450		(157	)		(2.4	)
Depreciation and Amortization		3,233		3,155		78			2.5
Operating Income	$	2,997	$	561	$	2,436			434.2

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 $9.8 million as a result of higher sales volume due to improved customer demandfor products and services.

● Revenues at ShoreMaster, Inc. (ShoreMaster), our waterfront equipment business, increased $2.8 million due to increased sales of both residential and commercial products.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased by $0.1 million due to a slight decrease in sales volume.

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

● Cost of goods sold at BTD increased $7.8 million mainly as a result of increased sales volume.

● Cost of goods sold at ShoreMaster increased $1.9 million as a result of increased sales volume.

● Cost of goods sold at T.O. Plastics increased $0.4 million as a result of increases in material and overhead costs.

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

● Operating expenses at BTD increased $0.6 million due to increases in salary and benefit costs related to workforce expansion and increased promotional expenses.

● Operating expenses at ShoreMaster decreased $0.8 million, reflecting a $0.4 million decrease to its allowance for doubtful accounts between the quarters and a $0.4 million decrease in labor and benefit costs.

● Operating expenses at T.O. Plastics increased by less than $0.1 million between the quarters.

33

Construction

	Three Months Ended
	September 30,								%
(in thousands)	2011			2010		Change			Change
Operating Revenues	$	53,247		$	36,885	$	16,362			44.4
Cost of Goods Sold		49,740			32,066		17,674			55.1
Operating Expenses		3,063			3,052		11			0.4
Depreciation and Amortization		523			510		13			2.5
Operating (Loss) Income	$	(79	)	$	1,257	$	(1,336	)		(106.3	)

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 $14.9 million due to an increase in the magnitude and volume of jobs in progress.

● Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, increased $1.4 million, reflecting $2.9 million in increased revenue from electrical and data wiring work and construction of underground and overhead electric transmission and distribution lines, offset by a $1.5 million reduction in revenues from work on substation and wind power projects.

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

● Cost of goods sold at Foley Company increased $15.5 million, mainly in the areas of material and subcontractor costs related to the increase in Foley’s work volume between the quarters, but also due to $0.8 million in cost overruns recorded on one large project in the third quarter of 2011.

● Cost of goods sold at Aevenia increased $2.2 million, mainly in labor and material costs, as a result of increased construction activity.

Plastics

	Three Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Operating Revenues	$	36,231	$	26,736	$	9,495			35.5
Cost of Goods Sold		29,956		23,278		6,678			28.7
Operating Expenses		1,756		1,606		150			9.3
Depreciation and Amortization		851		858		(7	)		(0.8	)
Operating Income	$	3,668	$	994	$	2,674			269.0

Operating revenues for the Plastics segment increased as result of a 5.2% increase in pounds of pipe sold combined with a 28.8% increase in the price per pound of pipe sold. The increase in costs of goods sold was due to the increase in pounds of pipe sold combined with a 22.3% increase in the cost per pound of pipe sold. The increase in operating expenses is mainly due to an increase in sales commissions paid as a result of the increase in pounds of pipe sold.

34

Health Services

	Three Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Operating Revenues	$	21,853	$	24,300	$	(2,447	)		(10.1	)
Cost of Goods Sold		14,590		17,186		(2,596	)		(15.1	)
Operating Expenses		4,489		4,353		136			3.1
Depreciation and Amortization		2,144		1,694		450			26.6
Operating Income	$	630	$	1,067	$	(437	)		(41.0	)

Revenues from scanning and other related services decreased $2.0 million as a result of an 8.5% reduction in scans performed. Revenues from equipment sales and servicing decreased $0.4 million. The decrease in cost of goods sold reflects a $2.3 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. The increase in operating expenses is mainly due to an increase in labor costs. 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
	September 30,						%
(in thousands)	2011		2010		Change		Change
Operating Expenses	$	5,987	$	4,219	$	1,768		41.9
Depreciation and Amortization		135		119		16		13.4

The increase in corporate operating expenses is mainly due to the accrual of termination benefits related to the resignation of our chief executive officer in the third quarter of 2011.

Interest Charges

Interest charges decreased $0.6 million in the third quarter of 2011 compared with the third quarter of 2010 mainly as a result of a $46.1 million decrease in the average balance of short-term debt outstanding between the quarters, due in part to the pay down of borrowings under our line of credit facility from proceeds from the sale of Idaho Pacific Holdings, Inc. (IPH) in May 2011.

35

Income Taxes – Continuing Operations

	Three Months Ended September 30,
(in thousands)	2011			2010			Variance
Income Before Income Taxes – Continuing Operations	$	8,983		$	3,454		$	5,529
Income Tax Expense (Benefit) - Continuing Operations		2,109			(607	)		2,716
Effective Income Tax Rate – Continuing Operations		23.5	%		(17.6	)%

The increase in Income Tax Expense (Benefit) - Continuing Operations for the three months ended September 30, 2011 compared with the three months ended September 30, 2010 is mainly due to the increase in income before income taxes between the quarters, but is also due to DMI deferring recognition of tax benefits in the third 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 $0.5 million in the third quarter of 2011. Our effective income tax rates for the three months ended September 30, 2011 and 2010 decreased as a result of recording $1.4 million and $1.6 million, respectively, in federal production tax credits (PTCs) earned on kwhs generated from tax credit qualified wind turbines owned by OTP. Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes.

Discontinued Operations

On May 6, 2011, we 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 our existing credit agreement. In the second quarter of 2011, Wylie decided to discontinue its heavy haul and specialized shipment and transportation of wind turbine components business. In the third quarter of 2011, the IPH sales proceeds were reduced by $0.8 million related to a purchase price adjustment. The results of operations of IPH and of Wylie’s wind turbine component transport business are reported as discontinued operations in our consolidated statements of income for the three months ended September 30, 2011 and 2010 as summarized in the table below:

	Three Months Ended
	September 30, 2011									September 30, 2010
(in thousands)	IPH			Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	--		$	--		$	--		$	19,478	$	2,046	$	21,524
Income (Loss) Before Income Taxes	$	--		$	(86	)	$	(86	)	$	3,183	$	82	$	3,265
Loss on Disposition - Pretax		(756	)		--			(756	)		--		--		--
Income Tax Expense (Benefit)		(302	)		(34	)		(336	)		1,192		33		1,225
Net Income (Loss)	$	(454	)	$	(52	)	$	(506	)	$	1,991	$	49	$	2,040

36

Comparison of the Nine Months Ended September 30, 2011 and 2010

Consolidated operating revenues were $914.1 million for the nine months ended September 30, 2011 compared with $754.0 million for the nine months ended September 30, 2010. Operating income was $47.7 million for the nine months ended September 30, 2011 compared with operating income of $11.1 million for the nine months ended September 30, 2010. The Company recorded diluted earnings per share from continuing operations of $0.50 for the nine months ended September 30, 2011 compared with $(0.26) for the nine months ended September 30, 2010 and total diluted earnings per share of $0.83 for the nine months ended September 30, 2011 compared with $(0.11) for the nine months ended September 30, 2010.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the nine month periods ended September 30, 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)	September 30, 2011		September 30, 2010
Operating Revenues:
Electric	$	181	$	164
Nonelectric		4,855		4,251
Cost of Goods Sold		4,667		3,875
Other Nonelectric Expenses		369		540

Electric

	Nine Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Retail Sales Revenues	$	224,371	$	226,945	$	(2,574	)		(1.1	)
Wholesale Revenues – Company Generation		12,406		16,506		(4,100	)		(24.8	)
Net Revenue – Energy Trading Activity		1,570		2,765		(1,195	)		(43.2	)
Other Revenues		16,452		12,078		4,374			36.2
Total Operating Revenues	$	254,799	$	258,294	$	(3,495	)		(1.4	)
Production Fuel		55,737		55,611		126			0.2
Purchased Power – System Use		27,759		32,730		(4,971	)		(15.2	)
Other Operation and Maintenance Expenses		84,718		84,817		(99	)		(0.1	)
Depreciation and Amortization		30,105		30,111		(6	)		--
Property Taxes		7,427		7,222		205			2.8
Operating Income	$	49,053	$	47,803	$	1,250			2.6

The $2.6 million decrease in retail sales revenues mainly is due to the following: (1) a $2.2 million reduction in retail revenue related to the recovery of lower fuel and purchased power costs, (2) a $1.4 million net reduction in revenues related to a $2.5 million increase in Minnesota revenues collected under interim rates net of a $3.9 million refund accrual for excess amounts collected under interim rates since June 2010, (3) a $1.2 million reduction in Minnesota resource recovery and transmission rider revenues, (4) a $0.8 million decrease in North Dakota resource recovery rider revenues, and (5) a $0.4 million decrease related to a North Dakota rate of return refund in the second quarter of 2011, partially offset by (6) a $3.4 million increase in revenues mainly due to a 1.8% increase in retail kwh sales driven by colder weather in the first half of 2011 compared with the first half of 2010, as indicated by a 17.0% increase in heating degree days between those periods.

37

Wholesale electric revenues from company-owned generation decreased $4.1 million due to a 17.2% decrease in wholesale kwh sales combined with a 9.2% decrease in revenue per wholesale kwh sold as a result of a 3.8% reduction in kwh generation from OTP’s generating units and lower demand in wholesale markets. Net gains from energy trading activities, including net mark-to-market gains on forward energy contracts, decreased $1.2 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 $4.4 million as a result of: (1) a $2.0 million increase in transmission tariff and services revenue between the periods, (2) $1.3 million in payments from a transmission cooperative to Otter Tail Energy Services Company (OTESCO) in 2011 for access rights and assistance in obtaining easements from landowners to construct a high voltage transmission line through a wind farm site where OTESCO owns development rights, and (3) a June 2010 refund accrual of $1.1 million for excess overhead charged to Big Stone II partners.

The $0.1 million increase in fuel costs reflects a 5.6% increase in the cost of fuel per kwh generated, offset by 5.1% reduction in kwhs generated from OTP’s steam-powered and combustion turbine generators. The cost of purchased power for retail sales decreased $5.0 million mainly as a result of a 14.0% decrease in the cost per kwh purchased due to lower market prices for electricity combined with a 1.4% decrease in kwhs purchased.

Wind Energy

	Nine Months Ended
	September 30,									%
(in thousands)	2011			2010			Change			Change
Wind Tower Revenues	$	154,605		$	105,934		$	48,671			45.9
Transportation Revenues		32,929			28,830			4,099			14.2
Total Operating Revenues	$	187,534		$	134,764			52,770			39.2
Cost of Goods Sold		152,621			100,504			52,117			51.9
Operating Expenses		41,568			35,767			5,801			16.2
Depreciation and Amortization		8,588			8,279			309			3.7
Operating Loss	$	(15,243	)	$	(9,786	)	$	(5,457	)		55.8

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

● Revenues at DMI increased as a result of a 47.6% increase in tower production.

● Revenues at Wylie increased mainly as a result of an increase in fuel surcharge revenues related to a 34.3% increase in the average cost per gallon of fuel consumed and also due to a $0.6 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 $51.9 million reflecting $46.8 million in increased costs related to the increase in towers produced, a $2.8 million increase in outsourced quality control costs to satisfy expanded customer requirements, productivity losses of $1.1 million due to rework and underutilization of plant capacity, and $1.1 million from the absorption of higher steel costs when a supplier did not fulfill its delivery requirements.

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

● Operating expenses at DMI decreased $0.2 million as a result of a decrease in expenditures for building repairs and maintenance.

● Operating expenses at Wylie increased $6.0 million as a result of increases in fuel prices, subcontractor and brokerage fees, repairs and maintenance expenses and insurance costs.

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Manufacturing

	Nine Months Ended
	September 30,								%
(in thousands)	2011		2010			Change			Change
Operating Revenues	$	170,486	$	130,880		$	39,606			30.3
Cost of Goods Sold		129,617		98,121			31,496			32.1
Operating Expenses		17,533		20,532			(2,999	)		(14.6	)
Asset Impairment Charge		--		19,740			(19,740	)		--
Depreciation and Amortization		9,634		9,684			(50	)		(0.5	)
Operating Income (Loss)	$	13,702	$	(17,197	)	$	30,899			179.7

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

● Revenues at BTD increased $34.1 million as a result of higher sales volume due to improved customer demand for products and services.

● Revenues at ShoreMaster increased $4.2 million mainly as a result of increased sales of both residential and commercial products due to improving dealer confidence and expanded distribution.

● Revenues at T.O. Plastics increased by $1.3 million due to increased sales of horticultural and industrial products.

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

● Cost of goods sold at BTD increased $27.0 million mainly as a result of increased sales volume.

● Cost of goods sold at ShoreMaster increased $3.2 million related to an increase in product sales.

● Cost of goods sold at T.O. Plastics increased $1.3 million as a result of the increase in sales of horticultural and industrial products and lower productivity.

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

● Operating expenses at BTD increased $1.3 million mainly due to increased salary and benefit costs related to workforce expansion.

● Operating expenses at ShoreMaster decreased $4.7 million, reflecting a $2.7 million increase to its allowance for doubtful accounts in the first nine months of 2010, a $0.6 million decrease to its allowance for doubtful accounts in the first nine months of 2011, a $0.7 million decrease in sales and marketing expenses, a $0.4 million decrease in benefit expenses and a $0.2 million gain on the sale of fixed assets in the first nine months of 2011.

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

ShoreMaster recorded a $19.7 million asset impairment charge in the second quarter of 2010. In light of ongoing economic uncertainty and delayed economic recovery, ShoreMaster revised its sales and operating cash flow projections downward in the second quarter of 2010, which resulted in a reassessment of the carrying value of its recorded goodwill. The fair value determination indicated ShoreMaster’s goodwill and other intangible assets were 100% impaired and its long-lived assets were partially impaired.

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Construction

	Nine Months Ended
	September 30,								%
(in thousands)	2011		2010			Change			Change
Operating Revenues	$	139,895	$	84,808		$	55,087			65.0
Cost of Goods Sold		129,137		75,849			53,288			70.3
Operating Expenses		9,184		9,294			(110	)		(1.2	)
Depreciation and Amortization		1,463		1,466			(3	)		(0.2	)
Operating Income (Loss)	$	111	$	(1,801	)	$	1,912			106.2

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

● Revenues at Foley Company increased $54.3 million due to an increase in the magnitude and volume of jobs in progress.

● Revenues at Aevenia increased $0.8 million mainly due to increased revenue from electrical and data wiring work.

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

● Cost of goods sold at Foley Company increased $51.7 million, mainly in the areas of material and subcontractor costs related to the increase in Foley’s work volume between the periods.

● Cost of goods sold at Aevenia increased $1.6 million between the periods, mainly in labor and material costs, as a result of increased construction activity.

Plastics

	Nine Months Ended
	September 30,						%
(in thousands)	2011		2010		Change		Change
Operating Revenues	$	99,082	$	76,562	$	22,520		29.4
Cost of Goods Sold		82,896		66,710		16,186		24.3
Operating Expenses		4,413		4,028		385		9.6
Depreciation and Amortization		2,518		2,417		101		4.2
Operating Income	$	9,255	$	3,407	$	5,848		171.6

Operating revenues for the Plastics segment increased as result of 13.3% increase in pounds of pipe sold combined with a 14.2% increase in the price per pound of pipe sold. The increase in costs of goods sold was due to the increase in pounds of pipe sold combined with a 9.6% increase in the cost per pound of pipe sold. The increase in operating expenses is mostly due to an increase in commissions paid to independent sales representatives.

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Health Services

	Nine Months Ended
	September 30,							%
(in thousands)	2011		2010		Change			Change
Operating Revenues	$	67,331	$	73,116	$	(5,785	)		(7.9	)
Cost of Goods Sold		44,899		55,590		(10,691	)		(19.2	)
Operating Expenses		13,761		13,115		646			4.9
Depreciation and Amortization		6,025		4,050		1,975			48.8
Operating Income	$	2,646	$	361	$	2,285			633.0

Revenues from scanning and other related services decreased $5.3 million due to a 11.3% decrease in scans performed, reflecting the planned discontinuance of portable x-ray services, partially offset by a 6.0% increase in revenue per scan. Revenues from equipment sales decreased $0.5 million. The decrease in cost of goods sold includes a $1.9 million reduction in materials, service labor and repairs and maintenance costs and an $8.6 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. The increase in operating expenses reflects a $0.7 million gain on the sale of fixed assets in the first nine months of 2010. No comparable gain was recorded in the first nine months of 2011. 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.

	Nine Months Ended
	September 30,						%
(in thousands)	2011		2010		Change		Change
Operating Expenses	$	11,380	$	11,331	$	49		0.4
Depreciation and Amortization		415		397		18		4.5

Interest Charges

Interest charges decreased $0.4 million in the first nine months of 2011 compared with the first nine months of 2010as a result of a $19.4 million decrease in the average balance of short-term debt and current maturities of long-term debt outstanding between the periods, due in part to the pay down of borrowings under our line of credit facility from proceeds from the sale of IPH in May 2011.

Other Income

Other income increased $1.0 million in the first nine months of 2011 compared with the first nine months of 2010as a result of a $0.6 million increase in allowance for equity funds used during construction at OTP and a $0.4 million decrease in foreign currency transaction losses in the Canadian operations of DMI between the periods.

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Income Taxes – Continuing Operations

	Nine Months Ended September 30,
(in thousands)	2011			2010			Variance
Income (Loss) Before Income Taxes – Continuing Operations	$	22,700		$	(15,379	)	$	38,079
Income Tax Expense (Benefit) - Continuing Operations		4,194			(6,625	)		10,819
Effective Income Tax Rate – Continuing Operations		18.5	%		43.1	%

The increase in Income Tax Expense (Benefit) - Continuing Operations for the nine months ended September 30, 2011 compared with the nine months ended September 30, 2010 is mainly due to the increase in income before income taxes between the periods.  Also, only $2.8 million of ShoreMaster’s $12.2 million second quarter 2010 goodwill impairment loss was deductible for income taxes and DMI has deferred recognition of tax benefits in the first nine months of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s 2011 deferred tax benefits totaled $2.4 million through September 30, 2011. Our effective income tax rates for the nine months ended September 30, 2011 and 2010 were decreased as a result of recording $5.3 million and $4.7 million, respectively, in federal PTCs earned on kwhs generated from tax credit qualified wind turbines owned by OTP. Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes.

Discontinued Operations

The results of operations of IPH and of Wylie’s wind turbine component transport business are reported as discontinued operations in our consolidated statements of income for the nine months ended September 30, 2011 and 2010 as summarized in the table below:

	Nine Months Ended
	September 30, 2011								September 30, 2010
(in thousands)	IPH		Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	28,125	$	5,448		$	33,573		$	56,648	$	4,700	$	61,348
Income (Loss) Before Income Taxes	$	3,840	$	(4,650	)	$	(810	)	$	8,306	$	129	$	8,435
Gain on Disposition - Pretax		16,011		--			16,011			--		--		--
Income Tax Expense (Benefit)		4,675		(1,860	)		2,815			3,029		52		3,081
Net Income (Loss)	$	15,176	$	(2,790	)	$	12,386		$	5,277	$	77	$	5,354

FINANCIAL POSITION

The following table presents the status of our lines of credit as of September 30, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on September 30, 2011		Restricted due to Outstanding Letters of Credit		Available on September 30, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	20,000	$	1,374	$	178,626	$	144,350
OTP Credit Agreement		170,000		19,010		1,050		149,940		144,436
Total	$	370,000	$	39,010	$	2,424	$	328,566	$	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.

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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 sales agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement is subject to renewal in March 2012. The current discount rate is 3-month LIBOR plus 4%. Accounts receivable totaling $48.8 million were sold in the first nine months of 2011. Discounts, fees and commissions charged to operating expense for the nine months ended September 30, 2011 and 2010 were $406,000 and $152,000, respectively. The balance of receivables sold that was outstanding to the buyer as of September 30, 2011 was $20.4 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 $78.0 million for the nine months ended September 30, 2011 compared with cash provided by operating activities from continuing operations of $56.9 million for the nine months ended September 30, 2010. Cash provided by operating activities from continuing operations was $21.1 million more in the nine months ended September 30, 2011 than in the nine months ended September 30, 2010 mainly as a result of the $20 million discretionary contribution made to our pension plan in September 2010.

Net cash used in investing activities of continuing operations was $68.0 million for the nine months ended September 30, 2011 compared to $60.3 million for the nine months ended September 30, 2010. The $7.7 million increase in cash used for investing activities includes a $13.5 million increase in cash used for capital expenditures at OTP, offset by a $3.5 million reduction in capital expenditures at our nonelectric companies and a $1.9 million decrease in cash used for other investments between the periods. The increase in capital expenditures at OTP is mainly related to expenditures for the Bemidji to Grand Rapids and Fargo to St. Cloud CapX2020 transmission line construction projects.

Net cash used in financing activities from continuing operations increased $80.3 million in the nine months ended September 30, 2011 compared with the nine months ended September 30, 2010 mainly due to a $82.9 million decrease 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 periods. We paid $59.2 million to retire long-term debt in the first nine months of 2010 but increased short-term borrowings by $86.4 million over the same period. Cash used to repay short-term borrowings and checks written in excess of cash totaled $50.4 million in the first nine months of 2011. The cash used to pay down short-term debt in the first nine months of 2011 came from $84.3 million in net proceeds from the sale of IPH in May 2011.

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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 $45.0 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 $5.7 million in 2011 and $13.5 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 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.

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On March 18, 2011 we borrowed $1.5 million under a Partnership in Assisting Community Expansion loan to finance capital investments at Northern Pipe Products, Inc. (NPP), our polyvinyl chloride (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. On April 6, 2011 we borrowed $0.5 million under a North Dakota Development Fund loan to finance additional capital investments at NPP. The seven-year unsecured note bears interest at 3.95% with monthly principal and interest payments through April 1, 2018.

On July 29, 2011, OTP entered into a Note Purchase Agreement (the 2011 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers in a private placement transaction $140 million aggregate principal amount of OTP’s 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes).  The 2021 Notes are expected to be issued on December 1, 2011, subject to the satisfaction of certain customary conditions to closing. OTP intends to use a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of OTP’s 6.63% Senior Notes due December 1, 2011 (the 2011 Notes) and $10.4 million aggregate principal amount of its pollution control refunding revenue bonds due December 1, 2012. The 2011 Notes remain classified as long-term debt because OTP has made arrangements to refinance this debt with borrowings under the 2011 Note Purchase Agreement.

The note purchase agreement relating to the 2011 Notes, 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), 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) and the 2011 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, the 2001 Note Purchase Agreement and the 2011 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 and the 2011 Note Purchase Agreement each also states that OTP 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 OTP. The 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement, the Cascade Note Purchase Agreement and the 2011 Note Purchase Agreement each contains 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.

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Financial Covenants

As of September 30, 2011 the Company and OTP were each in compliance with the financial statement covenants that existed in their respective 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 and OTP’s borrowing agreements require us and OTP, respectively, to comply with certain financial covenants, and upon the issuance of the 2021 Notes, the 2011 Note Purchase Agreement will require OTP to comply with similar 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 September 30, 2011 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 1.78 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 September 30, 2011 our Interest Charges Coverage Ratio calculated under the requirements of the Cascade Note Purchase Agreement was 1.66 to 1.00.

·   Under the OTP Credit Agreement and, upon the issuance of the 2021 Notes, under the 2011 Note Purchase 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 related agreement. As of September 30, 2011 OTP’s Interest and Dividend Coverage Ratio calculated under the requirements of each such agreement was 3.33 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, the 2007 Note Purchase Agreement and, upon the issuance of the 2021 Notes, under the 2011 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 September 30, 2011 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of each such agreement was 3.33 to 1.00.

As of September 30, 2011 our interest-bearing debt to total capitalization was 0.43 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 $10.1 million, but our line of credit borrowing limits are only restricted by $2.4 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.

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2011 BUSINESS OUTLOOK

The following updated 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.

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

2011 Earnings Per Share Guidance Range
	Previous Guidance						Current Guidance
	Low			High			Low			High
Electric	$	1.01		$	1.06		$	1.05		$	1.10
Wind Energy		(.80	)		(.50	)		(.70	)		(.55	)
Manufacturing		.25			.30			.23			.28
Construction		.05			.08			.00			.03
Plastics		.10			.13			.12			.15
Health Services		.01			.05			.01			.05
Corporate		(.20	)		(.18	)		(.23	)		(.21	)
Total – Continuing Operations	$	.42		$	.94		$	.48		$	.85
Earnings – Discontinued Operations:
IPH		.07			.07			.07			.07
E.W. Wylie Wind-Heavy Haul		(.12	)		(.08	)		(.10	)		(.08	)
Gain on Sale of IPH		.35			.37			.32			.35
Total	$	.72		$	1.30		$	.77		$	1.19

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

·   We expect an increase in net income from our Electric segment over our previous guidance and for 2011 compared to 2010. This is based on sales growth, rate and rider recovery increases and an increase in capitalized interest costs related to larger construction expenditures along with stable operating and maintenance expenses in 2011 compared with 2010.

·   Our 2011 earnings guidance for our Wind Energy segment reflects the following factors:

o      While DMI has been able to stabilize production, improve productivity, align headcount with the year’s remaining production demands and eliminate the need for outsourced quality assurance staffing, we expect a 2011 loss primarily as a result of the challenges faced in the first half of the year. In spite of soft demand in the wind industry, order backlog has solidified for the remainder of 2011 supporting full load of current plant staffing at DMI’s Tulsa and West Fargo plants. DMI continues to experience increased pricing pressure on new orders due to overcapacity in the U.S. market and significantly lower steel costs available to Asian manufacturers. Potential exposure to liquidated damages, warranty claims, or remediation costs related to past production issues remain.

o      We exited Wylie’s wind-heavy haul business in the second quarter of 2011. Accordingly, the results of operations from this part of the business have been reclassified to discontinued operations. We expect the continuing flatbed trucking operations to record a loss in 2011 given the net loss that occurred in the third quarter, which is not expected to be recovered from fourth quarter operating results. This current operating loss could be an indicator of lower-than-expected future profitability and could result in reductions in anticipated future cash flows from transportation operations, which may indicate the fair value of Wylie is less than its carrying value. While not reflected in current guidance, this could result in a future impairment and corresponding charge against earnings of all or a portion of the $6.7 million of goodwill recorded on our balance sheet related to the acquisition of Wylie. We continue to explore remedies to maximize the performance and value of this business.

o      Backlog in the Wind Energy segment is $33 million for 2011 compared with $23 million one year ago.

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·   We expect earnings from our Manufacturing segment to decrease from our previous guidance based on third quarter results being below expectations. However, we still expect an increase from our original 2011 guidance as a result of increased order volume and continuing improvement in economic conditions in the industries BTD serves. We are expecting significantly improved performance at ShoreMaster as a result of bringing costs in line with current revenue levels and absent last year’s $15.6 million net-of-tax noncash impairment charge. We expect T.O. Plastics to have earnings at the same level as 2010. Backlog for the manufacturing companies is approximately $34 million for 2011 compared with $33 million one year ago.

·   We expect slightly 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. The reduction in guidance from the previous quarter relates to cost overruns on a Foley project that contributed to a $0.6 million reduction in net income at Foley Company in the third quarter, along with continued poor performance on construction contracts at Aevenia. Backlog for the construction businesses is $47 million for 2011 compared with $48 million one year ago.

·   We are increasing our earnings expectations for our Plastics segment given its strong 2011 year-to-date performance.

·   We still expect an increase in earnings from our Health Services segment in 2011 compared with 2010 as the benefits of implementing its asset reduction plan continue to be realized. Significant improvements have been made in the utilization of its fleet through a better mix of assets and cost reductions. However, our Health Services business continues to operate in a difficult economic environment with much uncertainty about the health care industry. Although not factored into current guidance, continued economic recovery concerns and the recent negative impact the stock markets have had on market capitalizations of certain publicly traded companies in this sector could be an indication the fair value of our Health Services segment is less than its carrying value. This could result in a future impairment and corresponding charge against earnings of all or a portion of the $23.7 million of goodwill recorded on our balance sheet related to acquisitions of our Health Services businesses. We continue to evaluate strategies to maximize the performance and value of this business.

·   Our expectations for corporate general and administrative cost have been revised upward as a result of the incurrence of termination benefits related to the resignation of our chief executive officer in the third quarter of 2011, but overall 2011 expenses are still expected to be less than 2010 expenses as a result of reductions in employee count and associated decreases in benefit costs.

·   The net earnings and the gain on sale of IPH are reflective of the actual results as the sale of the business closed in May 2011. In addition, we exited the wind-heavy haul operations of Wylie in the second quarter of 2011. The net loss reflected in the guidance table is the result of actual operating activity of this businessand an estimate of any other potential costs that could occur as the business winds down. There was no gain or loss incurred on disposal of the asset fleet associated with Wylie’s wind-heavy haul business.

The sale of IPH was 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. 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. Future IPH earnings forfeited through the sale of IPH are expected to be replaced by increased utility earnings 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, OTP, 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 2015:

(in millions)	2011		2012		2013		2014		2015
Capital Expenditures:
Electric Segment:
Transmission	$	23	$	31	$	65	$	48	$	22
Environmental		4		49		97		80		40
Other		40		50		57		54		64
Total Electric Segment	$	67	$	130	$	219	$	182	$	126
Nonelectric Segments		40		41		48		44		43
Total Capital Expenditures	$	107	$	171	$	267	$	226	$	169
Total Electric Utility Average Rate Base	$	651	$	722	$	876	$	1,057	$	1,299

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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 2015 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 authorized 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, as the U.S. economy slowly recovers. 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 our 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, contingent liabilities, 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 September 30, 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.

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·   We may, from time to time, sell one or more of our nonelectric businesses to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any business sold.

·   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 are not currently required to make any contributions to our defined benefit pension plan in 2011. We could make discretionary contributions to the plan or 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 income.

·   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 realign our diversified business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance.

·   Our plans to 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 in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition. Also, 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 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.

·   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.

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·   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.

·   Prolonged periods of low utilization of DMI’s wind tower production plants, due to a continuing softening of demand for its product, could cause DMI to idle certain facilities. Should this softened demand for wind towers continue, these events may result in impairment charges on certain of DMI’s facilities if future cash flow estimates, based on information available to management at the time, indicate that the plants carrying values may not be recoverable or, if any plant assets are sold below their carrying values, significant losses may be incurred.

·   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.

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Item 3.  Quantitative and Qualitative Disclosures about Market Risk

At September 30, 2011 we had exposure to market risk associated with interest rates because we had $20.0 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 $19.0 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 September 30, 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.

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 September 30, 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 September 30, 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 polyvinyl chloride (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 September 30, 2011 OTP had recognized, on a pretax basis, $974,000 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 purchase and sales contracts that are marked to market as of September 30, 2011 are 97% offsetting 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 September 30, 2011 because the open purchases were not at the same delivery points as the open sales.

52

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 September 30, 2011 and December 31, 2010, and the change in our consolidated balance sheet position from December 31, 2010 to September 30, 2011:

(in thousands)	September 30, 2011			December 31, 2010
Other Current Assets – Marked-to-Market Gain	$	3,929		$	6,875
Regulatory Assets – Deferred Marked-to-Market Loss		13,560			12,054
Total Assets		17,489			18,929
Derivative Liabilities – Marked-to-Market Loss		(16,390	)		(17,991	)
Regulatory Liabilities – Deferred Marked-to-Market Gain		(125	)		(175	)
Total Liabilities		(16,515	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	974		$	763

(in thousands)	Year-to-Date September 30, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(225	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(28	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		(14	)
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(72	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		424
Changes in Fair Value of Contracts Entered into in 2011		550
Net Fair Value End of Period	$	974

The $974,000 in recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on September 30, 2011 is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	4th Quarter 2011		2012		Total
Net Gain	$	354	$	620	$	974

The following realized and unrealized net gains on forward energy contracts are included in electric operating revenues on our consolidated statements of income:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Net Gains on Forward Electric Energy Contracts	$	456	$	144	$	587	$	1,945

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 September 30, 2011 was $372,000. As of September 30, 2011 OTP had a net credit risk exposure of $792,000 from five counterparties with investment grade credit ratings. OTP had no exposure at September 30, 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 $792,000 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 September 30, 2011. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

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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 September 30, 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 September 30, 2011.

During the fiscal quarter ended September 30, 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

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, as updated in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 under Part II, Item 1A, “Risk Factors” to add the following risk factor:

We may, from time to time, sell one or more of our nonelectric businesses to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any business sold.

As part of our business strategy, we intend to realign our business portfolio by divesting of some of our nonelectric businesses and building our electric utility’s earnings base in order to lower our overall risk. A loss on the sale of a business would be recognized if a company is sold for less than its book value.

54

Item 6.     Exhibits

4.1 Note Purchase Agreement dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 3, 2011).

10.1 Nonqualified Retirement Savings Plan (2011 Restatement).

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.

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:  November 9, 2011

55

EXHIBIT INDEX

Exhibit Number	Description
4.1	Note Purchase Agreement dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 3, 2011).
10.1	Nonqualified Retirement Savings Plan (2011 Restatement).
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.

EX-10.1

Exhibit 10.1

OTTER TAIL CORPORATION

NONQUALIFIED RETIREMENT PLAN

2011 RESTATEMENT

Prepared By:

Leonard, Street and Deinard

Professional Association/AMB

150 S. Fifth Street #2300

Minneapolis, MN 55402

 (612) 335-1500

TABLE OF CONTENTS

ARTICLE 1.	DEFINITIONS, GENDER, AND NUMBER.	1
Section 1.1.	Definitions	1
Section 1.2.	Gender and Number	14
ARTICLE 2.	DEFERRED COMPENSATION ACCOUNTS	14
Section 2.1.	Establishment of Accounts	14
Section 2.2.	Property of Company	14
ARTICLE 3.	PARTICIPATION	14
Section 3.1.	Who May Participate	14
Section 3.2.	Time and Conditions of Participation	14
Section 3.3.	Termination of Participation	15
Section 3.4.	Missing Persons	15
Section 3.5.	Relationship to Other Plans	16
ARTICLE 4.	ENTRIES TO THE ACCOUNT	16
Section 4.1.	Deferrals	16
Section 4.2.	Company Contributions	18
Section 4.3.	Disability	18
Section 4.4.	Change in Eligibility Status	19
Section 4.5.	Allocation to Accounts	19
Section 4.6.	Earnings Crediting	19
ARTICLE 5.	DISTRIBUTION OF BENEFITS	21
Section 5.1.	Election of Benefit Commencement	21
Section 5.2.	Benefit Commencement	22
Section 5.3.	Form of Benefit Payment	25
Section 5.4.	Death Benefits	26
Section 5.5.	Change in Elections	27
Section 5.6.	Confidentiality	28
Section 5.7.	Competition	29
Section 5.8.	Forfeiture for Cause	30
Section 5.9.	Minimum Amount and Frequency of Payments	30
Section 5.10.	Section 162(m) of the Code	30
Section 5.11.	Acceleration of Distributions	31
Section 5.12.	Unforeseeable Emergencies	31
Section 5.13.	Deferred Election Termination	32
Section 5.14.	Limitation on Payment	32

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Section 5.15.	Delay of Distribution	32
Section 5.16.	Distributions on Plan Termination	33
Section 5.17.	Claims Procedure	33
ARTICLE 6.	FUNDING	38
Section 6.1.	Source of Benefits.	38
Section 6.2.	No Claim on Specific Assets	38
ARTICLE 7.	ADMINISTRATION AND FINANCES	38
Section 7.1.	Administration	38
Section 7.2.	Powers of Committee	38
Section 7.3.	Actions of the Committee	39
Section 7.4.	Delegation	39
Section 7.5.	Reports and Records	40
ARTICLE 8.	AMENDMENTS AND TERMINATION.	40
Section 8.1.	Amendments	40
Section 8.2.	Termination	40
ARTICLE 9.	MISCELLANEOUS	42
Section 9.1.	No Guarantee of Employment	42
Section 9.2.	Release	43
Section 9.3.	Notices	43
Section 9.4.	Nonalienation	43
Section 9.5.	Tax Liability	44
Section 9.6.	Parachute and Other Payments	44
Section 9.7.	Indemnification	44
Section 9.8.	Captions	44
Section 9.9.	Applicable Law	44

ii

OTTER TAIL CORPORATION

NONQUALIFIED RETIREMENT PLAN

2011 RESTATEMENT

Effective January 1, 2005, the Otter Tail Corporation Revised Nonqualified Retirement Plan became effective. This document restates the Plan as the “Otter Tail Corporation Nonqualified Retirement Plan 2011 Restatement,” generally effective January 1, 2011, except as otherwise set forth herein. This restatement does not eliminate or reduce the account balance of any Participant or Beneficiary eligible for benefits as of the date of that this restatement is signed. The Plan continues to be a nonqualified deferred compensation plan for the benefit of certain executive employees of Otter Tail Corporation and its subsidiaries. The Plan is intended to comply with Section 409A of the Code. It continues to apply to amounts previously deferred under the Otter Tail Corporation Nonqualified Retirement Plan effective January 1, 2003, that were not earned and vested as of December 31, 2004, as well as to amounts deferred under the Otter Tail Revised Nonqualified Retirement Plan effective January 1, 2005. The Plan is intended to be an unfunded plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees, as described in Sections 201(2), 301(a)(3) and 401(a)(1) of Title I of ERISA.

ARTICLE 1.DEFINITIONS, GENDER, AND NUMBER.

Section 1.1.       Definitions. Whenever used in the Plan, the following words and phrases shall have the meanings set forth below unless the context plainly requires a different meaning, and when a defined meaning is intended, the term is capitalized.

1.1.1.           “Account” means the bookkeeping account used to measure and determine the amount of deferred compensation to be paid to a Participant or Beneficiary under the Plan, consisting of one or more of the Company Account, the Retirement Account, or a

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Scheduled Withdrawal Account. Accounts that had been opened under the Otter Tail Corporation Nonqualified Retirement Plan with respect to amounts not earned and vested as of December 31, 2004 became Accounts of the same kind (Company Account, Retirement Account or Scheduled Withdrawal Account) under this Plan and elections made with respect to such Accounts shall continue in effect as elections made under this Plan unless and until changed as permitted under this Plan.

1.1.2.           “Affiliates” means any entity that employs employees and in which the Company has a controlling interest.  In addition, “Affiliates” includes any entity affiliated with the Company that the Company determines is an Affiliate under this Plan for legitimate business reasons consistent with the provisions of Section 409A of the Code. With respect to the definition of “employer” under Section 409A of the Code, the language “at least 50%” shall be used each place where it appears in Section 1563(a)(1), (2), and (3) of the Code to determine a controlled group of corporations under Section 414(b) of the Code and in applying Regulation Section 1.414(c)-2 to determine whether trades or businesses are under common control. Affiliates as of the date that this restated Plan is adopted are listed on Appendix A to the Plan.

1.1.3.           “Base Salary” of a Participant for any Plan Year means the total annual salary and wages paid by the Company or an Affiliate to such individual for such Plan Year, including any amount which would be included in the definition of Base Salary but for the individual's election to defer some of the individual’s compensation pursuant to this Plan or any other deferred compensation plan established by the Company or an Affiliate; but excluding any other remuneration paid by the Company or an Affiliate, such as bonuses, commissions, overtime, Incentive Compensation, equity-based

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compensation, including, but not limited to stock options, restricted stock or stock-based units, distributions of compensation previously deferred, allowances for expenses (including moving expenses, travel expenses, and automobile allowances), and fringe benefits, whether payable in cash or in a form other than cash. In the case of an individual who is a participant in a plan sponsored by the Company or an Affiliate which is described in Section 401(k), 125 or 132(f) of the Code, the term Base Salary shall include any amount which would be included in the definition of Base Salary but for the individual's election to reduce the individual’s compensation and have the amount of the reduction contributed to or used to purchase benefits under such plan.

1.1.4.           “Beneficiary” or “Beneficiaries” means the persons or trusts designated by a Participant in writing pursuant to Section 5.4.1 of the Plan as being entitled to receive any benefit payable under the Plan by reason of the death of a Participant, or, in the absence of such designation, the persons specified in Section 5.4.2 of the Plan.

1.1.5.           “Board” means the Board of Directors of the Company as constituted at the relevant time.

1.1.6.           “Cause” means the occurrence of one of the following: (a) a Participant’s violation in any material respect of any agreement or representation set forth in any employment or other agreement, if any, between the Company or an Affiliate and the Participant; (b) the occurrence of an event that would constitute “cause” (or any similar concept) under any employment or other agreement, plan, or program that governs the Participant or by which the Participant is bound; (c) a Participant’s willful violation of any material rule or policy of the Company or an Affiliate or any theft or defalcation of property committed against the Company or an Affiliate; (d) any continual willful or

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material failure by a Participant to comply with a reasonable and lawful direction of the Board or any duly authorized committee of the Board or the chief executive officer of the Company or an Affiliate, or the willful misconduct by Participant in the responsibilities reasonably assigned to the Participant; (e) conviction of or plea of nolo contendere by a Participant to a felony or other actions or omissions that reflect moral turpitude or threaten to materially and adversely reflect on the Company or an Affiliate in the conduct of its business; or (f) violation of the confidentiality provisions of Section 5.6 or the noncompetition provisions of Section 5.7.

1.1.7.           “Change in Control” of the Company means:

(a)         Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) is or becomes within a 12 month period ending on the date of the most recent acquisition the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, of securities of the Company representing 35% or more of the combined voting power of the Company’s then outstanding securities; or

(b)         Within a 12 month period the Continuing Directors cease to constitute a majority of the Company’s Board of Directors; provided that such change is the direct or indirect result of a proxy fight and contested election or elections for positions on the Board of Directors.

(c)         With respect to a Plan Participant, a Change in Control event must relate to: (i) the corporation for which the Participant is performing services at the time of the Change in Control event; (ii) the corporation that is liable for the payment of the deferred compensation (or all corporations liable for the payment

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if more than one corporation is liable); or (iii) a corporation that is a majority shareholder of a corporation identified in part (i) or part (ii) above, or any corporation in a chain of corporations in which each corporation is a majority shareholder of another corporation in the chain, ending in a corporation identified in part (i) or part (ii) above. For purposes of this provision, a majority shareholder is a shareholder owning more than 50% of the total fair market value and total voting power of such corporation. Also, for purposes of this provision, Section 318(a) of the Code applies to determine stock ownership.

(d)         The provisions of this Section 1.1.7 regarding the definition of the term “Change in Control,” shall be determined and administered in accordance with Section 409A of the Code so that no Change in Control shall be considered to have occurred unless and until it is also a change in control under Section 409A of the Code. Provided, however, that a Change in Control must relate to the Company and not to Affiliates, and a Sale is not a Change in Control of the Company under the Plan.

1.1.8.           “Code” means the Internal Revenue Code of 1986, as amended from time to time and any successor statute. References to a Code section shall be deemed to be to that section or to any successor to that section and to the guidance issued under that section.

1.1.9.           “Committee” means the Committee of one or more persons appointed by the Company's Board, or any person or entity designated by the Committee to administer the Plan pursuant to Section 7.4. In the absence of an appointed Committee, the Board shall serve as the Committee. Until changed by the Board the Committee shall consist of

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the Vice President and Chief Financial Officer; the Vice President of Human Resources and Strategy; and the Manager of Compensation and Benefits.

1.1.10.           “Company” means Otter Tail Corporation, a Minnesota corporation. Prior to July 1, 2009, “Company” meant Otter Tail Corporation, a Minnesota corporation doing business as Otter Tail Power Company. Effective July 1, 2009, that Otter Tail Corporation became a wholly owned subsidiary of a new holding company in a reverse triangular merger pursuant to which the new holding company took the name “Otter Tail Corporation,” which is now the “Company” under the Plan, and the subsidiary took the name “Otter Tail Power Company.”

1.1.11.           “Company Account” means a bookkeeping account established for a Participant for Company Contributions made to the Plan under Section 4.2.

1.1.12.           “Company Contribution” means the contribution of the Company to a Participant’s Company Account under Section 4.2.

1.1.13.           “Compensation” with respect to a Participant for any period means the sum of such Participant's Base Salary paid and Incentive Compensation accrued with respect to such period.

1.1.14.            “Confidential Information” means unique, confidential and proprietary systems, records, customer lists, product information and other information of the Participant’s Employer that derives value from not being generally known to the public and with respect to which the Employer takes reasonable steps to keep confidential.

1.1.15.           “Continuing Director” means any person who is a member of the Board of Directors of the Company, while such person is a member of the Board of Directors, and who (a) was a member of the Board of Directors on the Effective Date or (b)

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subsequently becomes a member of the Board of Directors, if such person’s nomination for election or initial election to the Board of Directors is recommended or approved by a majority of the Continuing Directors.

1.1.16.           “Crediting Rate” with respect to any Plan Year means the rate or rates established by the Company in its sole discretion to determine earnings and losses with respect to an Account. The Company may select any investment index (i.e., mutual funds, annuities, bank collective funds or an insurance company dividend rate) as a Crediting Rate to be applied to amounts credited to a Participant’s Accounts as set forth in Section 4.6. The Company may change such indices at any time or from time to time and can restrict or limit at any time and from time to time the Account(s) eligible for any Crediting Rate. The Company has the discretion to determine the exact manner in which any Crediting Rate shall be calculated and applied to an Account. The Company also has the discretion to determine the Crediting Rate to apply as a default Crediting Rate to any Account for which a Participant fails or refuses to select a Crediting Rate. The Company shall not be liable to any person or entity, including the Participant, for losses or reduced gains associated with or relating to the selection or application of a particular Crediting Rate, whether as a default rate or otherwise.

1.1.17.           “Deferral Account” means one or more of the Retirement Account or a Scheduled Withdrawal Account, according to the context.

1.1.18.           “Disabled” or “Disability” means, with respect to a Participant, that the Participant (a) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months; (b) by

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 reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, is receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Company; or (c) has been determined to be totally disabled by the Social Security Administration. Disability under subsections (a) and (b) shall be determined by a physician selected by the Company. A Participant shall cooperate with the Company, including making the Participant reasonably available for examination by physicians at the Company’s request and at the Company’s expense to determine whether or not the Participant is Disabled.

1.1.19.           “Early Retirement” means a Participant’s termination of employment with the Company and Affiliates before the Participant’s Retirement and before there has occurred a Sale or Change in Control, but only if before the Participant’s termination of employment or within 30 days thereafter, the Committee determines in its sole discretion to consider the termination an Early Retirement. The sole effect of a determination that the termination is an Early Retirement is that the Participant shall become vested in the Company Account. Provided, however, that a Participant will not be considered to have attained “Early Retirement” if the Participant is or could have been terminated from employment for Cause. Provided further, that a Participant shall not be considered to have terminated employment with the Company and Affiliates unless and until the Participant terminates employment with the Company and Affiliates and with any entity that is the parent company of the Company or an entity that is affiliated with the Company or the Affiliates or the parent company of the Company, and a transfer of employment between or among such entities shall not be considered a termination of

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employment under this Plan. In determining whether an entity is affiliated with the Company, the Company shall include all members of a controlled group of corporations and all trades or businesses under common control. The language “at least eighty percent” used in applying the concepts of Section 1563 of the Internal Revenue Code and Section 414(b) and (c) of the Internal Revenue Code shall be replaced by “at least fifty percent.” Any termination of employment under this Plan must also constitute a separation from service under the provisions of Section 409A of the Code.

1.1.20.           “Effective Date” means January 1, 2005, the date on which this Plan becomes effective. The effective date of this restatement of the Plan is January 1, 2011.

1.1.21.           “Eligible Executive” means any employee of the Company or an Affiliate who is designated by the Committee, in its sole discretion, as an Eligible Executive. An employee shall cease to be an Eligible Executive if the Committee, in its sole discretion, determines not to designate the employee as an Eligible Executive for the year; or if the Committee, in its sole discretion, determines at any time that the employee should no longer participate in the Plan. The Committee shall notify any employee who has been an Eligible Executive and who is no longer an Eligible Executive.

1.1.22.           “Eligible Pay” with respect to a Participant for any Plan Year, means the taxable income reported on the Participant’s Form W-2 for the Plan Year, reduced by income attributable to taxable fringe benefits, including, but not limited to automobile allowances, excess life insurance coverage, moving expenses, travel expenses, amounts realized on the sale or disposition of qualified or nonqualified stock options or stock purchases, or amounts realized on the inclusion in income of property under Section 83 of the Code. Eligible Pay shall include any amount which would be included in the

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definition of Eligible Pay but for the individual's election to defer some of the individual’s compensation pursuant to this Plan or any other deferred compensation plan established by the Company or an Affiliate; and shall exclude distributions of compensation previously deferred. In the case of an individual who is a participant in a plan sponsored by the Company or an Affiliate which is described in Section 401(k), 125, 132(f) of the Code, the term Eligible Pay shall include any amount which would be included in the definition of Eligible Pay but for the individual's election to reduce the individual’s compensation and have the amount of the reduction contributed to or used to purchase benefits under such plan. Eligible Pay for any Participant for a Plan Year may be limited to such amount as the Committee shall determine.

1.1.23.           “Employer” means with respect to a Participant the Company or Affiliate that employs that Participant.

1.1.24.           “Enrollment Period” means the period during each Plan Year designated by the Committee during which new Accounts may be opened and deferral elections may be changed for Compensation payable with respect to the immediately succeeding Plan Year. The Enrollment Period for a Plan Year with respect to Base Salary and Incentive Compensation shall end no later than December 31 preceding the first day of the Plan Year for which the election is to be effective and any deferral election shall become irrevocable as of such December 31 (or such earlier date as established by the Committee). Provided, however, that for the initial year that an Employee is selected as an Eligible Executive, the Enrollment Period shall be such period of time following selection as the Committee shall determine consistent with the requirements of Section 409A of the Code and Section 4.1.

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1.1.25.           “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time and any successor statute. References to an ERISA section shall be deemed to be to that section or to any successor to that section and to the guidance issued under that section.

1.1.26.           “Incentive Compensation” of a Participant for any Plan Year means the total remuneration paid to such Participant under the various incentive compensation programs maintained by the Company or an Affiliate with respect to that Plan Year, including any amount which would be included in the definition of Incentive Compensation but for the Participant's election to defer some or all of the Participant’s Incentive Compensation pursuant to this Plan or some other deferred compensation plan established by the Company or an Affiliate; but excluding any other remuneration paid by the Company or an Affiliate, such as Base Salary, overtime, net commissions, equity-based compensation including, but not limited to, stock options, restricted stock or stock-based units, distributions of compensation previously deferred, allowances for expenses (including moving expenses, travel expenses, and automobile allowances), and fringe benefits whether payable in cash or in a form other than cash. In the case of an individual who is a participant in a plan sponsored by the Company or an Affiliate which is described in Section 401(k), 125, or 132(f) of the Code, the term Incentive Compensation shall include any amount which would be included in the definition of Incentive Compensation but for the individual's election to reduce the individual’s compensation and have the amount of the reduction contributed to or used to purchase benefits under such plan.

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1.1.27.           “Maximum Annual Deferral” with respect to a Participant for a Plan Year means the sum of (a) 50% of the Participant's Base Salary paid for such Plan Year; and (b) 100% of the Participant's Incentive Compensation accrued for such Plan Year.

1.1.28.           “Participant” means an Eligible Executive who has satisfied the requirements of Article 3.

1.1.29.           “Plan” means the “Otter Tail Corporation Nonqualified Retirement Plan 2011 Restatement” (formerly known as the Otter Tail Corporation Revised Nonqualified Retirement Plan effective January 1, 2005), as set forth herein and as amended or restated from time to time.

1.1.30.           “Plan Year” means January 1 through December 31.

1.1.31.           “Retirement” means a Participant’s termination of employment with the Company and Affiliates at any age as a result of death or Disability; or a Participant’s termination of employment with the Company and Affiliates on or after age 58. Provided, however, that a Participant will not be considered to have attained “Retirement” if the Participant is or could have been terminated from employment for Cause. Provided further, that a Participant shall not be considered to have terminated employment with the Company and Affiliates unless and until the Participant terminates employment with the Company and Affiliates and with any entity that is the parent company of the Company or an entity that is affiliated with the Company or the Affiliates or the parent company of the Company, and a transfer of employment between or among such entities shall not be considered a termination of employment under this Plan. In determining whether an entity is affiliated with the Company, the Company shall include all members of a controlled group of corporations and all trades or businesses under common control. The

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 language “at least eighty percent” used in applying the concepts of Section 1563 of the Internal Revenue Code and Section 414(b) and (c) of the Internal Revenue Code shall be replaced by “at least fifty percent.” Any termination of employment under this Plan must also constitute a separation from service under the provisions of Section 409A of the Code.

1.1.32.           “Retirement Account” means a bookkeeping account that a Participant may have established for deferral of Compensation made to the Plan under Section 4.1.3.

1.1.33.           “Sale” means the occurrence of an event pursuant to which the Participant’s Employer is sold or transferred to an entity that is not the Company or an Affiliate; however, no Sale shall be considered to have occurred unless and until it is also a change in control under Section 409A of the Code.

1.1.34.           “Scheduled Withdrawal Account” means a bookkeeping account that a Participant may have established for deferral of Compensation made to the Plan under Section 4.1.3. When a Participant opens a Scheduled Withdrawal Account, the Participant shall establish the Specified Year in which benefits are to commence pursuant to Section 5.1.2. Effective with respect to deferrals of Compensation during the Plan Year beginning January 1, 2011, a Participant may have open no more than two Scheduled Withdrawal Accounts with positive balances at any time.

1.1.35.           “Specified Year” means the year in which the Participant wishes to receive distributions from a Scheduled Withdrawal Account, as specified at the time that the Participant opens the Account.

1.1.36.           “Trust” means the Trust under the Otter Tail Corporation Revised Nonqualified Retirement Plan (or the Otter Tail Corporation Nonqualified Retirement

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 Account 2011 Restatement, if the Trust name is so amended), as amended from time to time.

Section 1.2.     Gender and Number. Except as otherwise indicated by context, masculine terminology used herein also includes the feminine and neuter, and terms used in the singular may also include the plural.

ARTICLE 2.DEFERRED COMPENSATION ACCOUNTS.

Section 2.1.Establishment of Accounts. The Company shall establish one or more (but no more than four) Accounts for each Participant which shall be utilized solely as a device to measure and determine the amount of deferred compensation to be paid under the Plan to the Participant or the Participant’s Beneficiaries.

Section 2.2.Property of Company. Any amounts so set aside for benefits payable under the Plan are the property of the Company, except, and to the extent, provided in the Trust.

ARTICLE 3.PARTICIPATION.

Section 3.1.Who May Participate. Participation in the Plan is limited to those Eligible Executives selected by the Committee for participation in the Plan. Unless specifically excluded by the Committee, Eligible Executives participating in the Otter Tail Corporation Nonqualified Retirement Plan as of December 31, 2004, shall participate in the Plan, and Eligible Executives participating in the Otter Tail Corporation Revised Nonqualified Retirement Plan effective January 1, 2005, shall continue to participate in the Plan.

Section 3.2.Time and Conditions of Participation. An Eligible Executive shall become a Participant only upon the Eligible Executive’s compliance with such terms and conditions as the Committee may from time to time establish for the implementation of the Plan, including but not limited to, any condition the Committee may deem necessary or appropriate for the Company

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to meet its obligations under the Plan. The Company may, in its sole discretion, purchase insurance on the lives of each Participant. The Committee may, in its sole discretion, reject for participation in the Plan Eligible Executives who fail or refuse to cooperate with the Company in obtaining insurance on their lives.

Section 3.3.Termination of Participation. Once an individual has become a Participant in the Plan, participation shall continue until the first to occur of (a) payment in full of all benefits to which the Participant or the Participant’s Beneficiary is entitled under the Plan, or (b) the occurrence of the event specified in Section 3.4 which results in loss of benefits. Except as otherwise specified in the Plan, the Company may not terminate an individual's participation in the Plan; provided, however, that if the Committee, in its discretion, determines that it is likely that a Participant would not be considered to be a member of a select group of management or highly compensated employees, within the meaning of Sections 201(2), 301(a)(3) and 401(a)(l) of ERISA, for any period, the Committee may require that no contributions be made to the Plan by or on behalf of such Participant during such period, at the time and to the extent consistent with Section 409A of the Code.

Section 3.4.Missing Persons. If the Company is unable to locate the Participant or the Participant’s Beneficiary for purposes of making a distribution, the amount of a Participant's benefits under the Plan that would otherwise be considered as nonforfeitable shall be forfeited on the first to occur of the following dates: (a) effective one year after the Participant’s termination from employment; (b) effective on the date of termination of the Plan; or (c) effective at such time as is required under Section 409A of the Code. If a person is located after the date of such forfeiture, the benefits for such Participant or Beneficiary shall not be reinstated under the Plan.

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Section 3.5.Relationship to Other Plans. Participation in the Plan shall not preclude participation of the Participant in any other fringe benefit program or plan sponsored by the Company for which such Participant would otherwise be eligible.

ARTICLE 4.ENTRIES TO THE ACCOUNT.

Section 4.1.Deferrals.

4.1.1.Deferral Elections. Each Participant wishing to defer Compensation under the Plan shall enter into a deferral election, which shall specify the amount of Compensation the Participant wishes to have deducted from the Participant’s pay and contributed to the Plan. Deferral elections with respect to Base Salary must specify the percentage (stated as an integer) of the Compensation that the Participant wishes to have deducted from Base Salary. Deferral elections with respect to Incentive Compensation must specify either the percentage (stated as an integer) or the dollar amount, or a combination of percentage and dollar amount, as determined by the Committee in its discretion, of the Compensation that the Participant wishes to have deducted from Incentive Compensation.

4.1.2.Timing of Elections. To the extent permissible under Section 409A of the Code, Eligible Executives who first become eligible to participate in the Plan may make a deferral election with respect to Base Salary and Incentive Compensation within 30 days after the date the Eligible Executive becomes eligible to participate in the Plan. Such election shall apply with respect to Base Salary to be paid after the date of the election. However, with respect to Incentive Compensation, the deferral election shall apply to the total amount of the Incentive Compensation accrued for the Plan Year in which the initial election is made multiplied by a fraction, the numerator of which is the number of days

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remaining in the performance period after the election and the denominator of which is the total number of days in the performance period. The election shall become irrevocable as of the date that it is made. Eligible Executives after their first year of selection must make a deferral election with respect to Base Salary and Incentive Compensation during the Enrollment Period preceding the beginning of a Plan Year. The Participant’s deferral election shall remain in effect unless and until terminated or changed by the Participant in accordance with the terms of the Plan and consistent with Section 409A of the Code.

4.1.3.Allocation Between Accounts. At the time a Participant makes the Participant’s initial deferral election, the Participant shall specify the Deferral Account(s) the Participant wishes to open in the Plan. A Participant with a deferral election shall always have at least one Deferral Account in the Plan and may, at the Participant’s election, have up to three Deferral Accounts, specifically, a Retirement Account and two Scheduled Withdrawal Accounts. A Participant may open a new Deferral Account (up to a total of three Deferral Accounts) during an Enrollment Period. A Participant shall specify in the Participant’s deferral election the proportions in which the Participant’s deferrals are to be allocated between the Participant’s Retirement Account and the Participant’s Scheduled Withdrawal Account(s). Provided, however, that no deferrals may be contributed to a Participant’s Scheduled Withdrawal Account in the calendar year in which a distribution is to be made from said Account.

4.1.4.Limitation on Deferral Elections. A Participant may make a deferral election for any Plan Year provided that: (a) in no event may the amount deferred by a Participant for a Plan Year under the Participant’s Deferral Account(s) exceed the

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Maximum Annual Deferral; and (b) the Participant's remaining Compensation, after all deferrals, is sufficient to enable the Employer to withhold from the Participant's Compensation (i) any amounts necessary to satisfy withholding requirements under applicable tax law; (ii) the amount of any contributions which the Participant may be required to make or may have elected to make under the various benefit plans of the Company or an Affiliate; and (iii) any other payroll deduction from Compensation required by law or authorized by the Participant.

Section 4.2.Company Contributions. For each Plan Year that commences on or after the Effective Date, the Company and/or any Affiliate may, but is not required to credit a contribution to the Plan on behalf of any Participant who was an Eligible Employee during the Plan Year. The amount of the contribution credited shall be the amount determined by the Company or Affiliate in its sole discretion. Such amount is not required to be uniform among the Eligible Employees, and the Company or Affiliate is permitted to credit Company Contributions for some Eligible Employees and not for other Eligible Employees. Such Company Contributions can be expressed as a fixed dollar amount; a percentage of Compensation, Base Salary, Incentive Compensation or Eligible Pay; or as a matching contribution based on the Deferrals made by the Eligible Employee. A Company Contribution on behalf of a Participant pursuant to this Section 4.2 shall be allocated to the Company Account of the Participant on whose behalf the contribution is made. Provided, however, that at the discretion of the Committee exercised at the time the Contribution is credited, the contribution may be allocated to the Participant’s Retirement Account.

Section 4.3.Disability. If a Participant becomes Disabled, deferrals and Company Contributions, if any, shall continue to be allocated as described in Sections 4.1 and 4.2 during

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the period in which the Participant is entitled to receive Compensation or Eligible Pay from the Company or an Affiliate, other than compensation under a long term disability plan. If a Participant continues to be Disabled after such period, deferrals and other Plan contributions will cease.

Section 4.4.Change in Eligibility Status. If a Participant in the Plan ceases to be an Eligible Executive for a Plan Year, the Participant’s deferrals to the Plan shall cease. No further Company Contributions under Section 4.2 shall be made to the Plan unless and until the employee again becomes an Eligible Executive. The Participant’s Account shall continue to be credited with earnings and losses under Section 4.6 and shall be paid in accordance with Article 5.

Section 4.5.Allocation to Accounts. During each Plan Year, the Company shall post to the appropriate Deferral Account(s) of each Participant the amount of Base Salary and Incentive Compensation to be deferred under such Deferral Account(s) as designated by the Participant in the Participant’s deferral election in effect for that Plan Year. Such allocation shall occur as of the dates that the Base Salary and Incentive Compensation would have been paid to the Participant. The Company shall also post to the Company Account amounts to be allocated to the Participant pursuant to Sections 4.2 and 4.3.

Section 4.6.Earnings Crediting.

4.6.1.Earnings Credits for Company Account. During each Plan Year a Participant's Company Account will be credited with interest at the Crediting Rate in effect for the Company Account for the Plan Year.

4.6.2.Earnings Credits for Deferral Accounts. Each Participant may request that a Scheduled Withdrawal Account or the Retirement Account be allocated to one or more

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investment indices selected by the Committee and credited or debited, as the case may be, with such earnings or losses as the Account would have been credited or debited had it been actually invested in such investment indices. The initial allocation request may be made at the time of opening of an Account. Once made, an investment allocation request shall remain in effect for all subsequent contributions until changed by the Participant. The Participant may change the investment allocation election by submitting a written request to the Committee. Participants may change elections no more than once in any calendar quarter. Such changes shall become effective as of the first day of the next quarter that is administratively feasible after the Committee receives such written request. Provided, however, that during the Plan Year in which a final distribution of a Participant’s Deferral Account is expected to occur, the Committee may apply to that Deferral Account the Crediting Rate applicable to Company Accounts for that Plan Year. Allocation requests shall be subject to such other requirements as established by the Committee.

4.6.3.Period of Crediting Rates. Crediting Rates shall continue to be credited or debited until the first to occur of (a) the Participant’s termination of employment that is not a Retirement under the Plan or (b) payment of all amounts owed to the Participant under all Account(s).

4.6.4.No Guarantee of Account Value. The Participant agrees on behalf of the Participant and any Beneficiary to assume all risk in connection with any decrease in value of the Deferral Accounts resulting from the Participant’s request and selection of any particular investment index under the Plan or from the application of any default Crediting Rate in accordance with the terms of the Plan.

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4.6.5.No Actual Investment. The Company is under no obligation to make investments or change investments in a manner consistent with the investment indices available under the Plan. The elections made by the Participant are for purposes of determining earnings and losses to be credited to the Accounts and not for the purpose of determining any actual investment of the assets of the Company or the Trust, if any.

4.6.6.Participant Statements. At least annually, the Company shall provide each Participant with a statement of the Participant’s Account(s).

ARTICLE 5.DISTRIBUTION OF BENEFITS.

Section 5.1.Election of Benefit Commencement.

5.1.1.Distribution on Change in Control. During a Participant’s first Enrollment Period under this Plan, the Participant may elect to commence distribution of all Accounts upon a Change in Control, if such a Change in Control should occur before the Account would otherwise be payable under this Plan. If such election is not made at such time, then no acceleration of any Account shall occur upon a Change in Control under the Plan. If such an election is made and if distribution of an Account has commenced in installments before a Change in Control, the balance of the Account shall be paid in a lump sum within 90 days of the date of the Change in Control. Provided, however, that except as otherwise provided in Section 5.5.2, a Participant who was first eligible under the Otter Tail Corporation Nonqualified Retirement Plan or the Varistar Corporation Incentive and Deferral Plan may not make an election under this Section 5.1.1, but the election made by such Participant under the Otter Tail Corporation Nonqualified Retirement Plan or the Varistar Corporation Incentive and Deferral Plan, as the case may

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be, with respect to a distribution of all Accounts upon a Change in Control shall be considered an election under this Plan.

5.1.2.Scheduled Withdrawal Account. At the time a Participant opens a Scheduled Withdrawal Account under the Plan, the Participant shall establish the Specified Year for that Account. The Specified Year must be a year that is at least two years following the beginning of the Plan Year in which deferrals to the Scheduled Withdrawal Account commence.

Section 5.2.Benefit Commencement.

5.2.1.Scheduled Withdrawal Account. Distribution of a Scheduled Withdrawal Account will be made in a lump sum during March of the Specified Year unless any of the following occurs before January 1 of the Specified Year: (a) the Participant terminates employment for reason other than Retirement, in which event distributions will be made in a lump sum within 90 days following the Participant’s termination of employment; (b) the Participant dies, in which event distributions will commence in the manner specified in Section 5.4.4; or (c) there occurs a Change in Control and the Participant requested distribution to commence upon the Change in Control (as described in Section 5.1.1), in which event distribution will be made in a lump sum within 90 days following the Change in Control; (d) the Participant’s Retirement occurs (other than by reason of death), in which event distribution will be made in a lump sum within 90 days following the date of Retirement; or (e) the Plan terminates, in which event distributions will be made in the manner specified in Section 8.2. Provided, however, that a Participant who transfers employment between or among the Company, an Affiliate, the parent company of the Company or an Affiliate, or any entity affiliated with any of the

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foregoing as determined under Section 1.1.30 shall not be considered to have terminated employment for purposes of this Section.

5.2.2.Retirement Account. Distribution of a Retirement Account will commence in January of the Plan Year following Retirement (other than by reason of death) unless any of the following occurs before the Participant’s Retirement (other than by reason of death): (a) the Participant terminates employment for reasons other than Retirement, in which event distribution will be made in a lump sum within 90 days following the Participant’s termination of employment (including Early Retirement); (b) the Participant dies, in which event distribution will commence in the manner specified in Section 5.4.4; or (c) there occurs a Change in Control and the Participant requested distribution to commence upon the Change in Control (as described in Section 5.1.1), in which event distribution will be made in a lump sum within 90 days following the Change in Control; or (d) the Plan terminates, in which event distributions will be made in the manner specified in Section 8.2. Provided, however, that a Participant who transfers employment between or among the Company, an Affiliate, the parent company of the Company or an Affiliate, or any entity affiliated with any of the foregoing as determined under Section 1.1.30 shall not be considered to have terminated employment for purposes of this Section.

5.2.3.Company Account. Distribution of a Company Account will be made only if the Participant remains employed with the Company or an Affiliate until Early Retirement, Retirement, Sale, or a Change in Control. In such event, distribution will commence in accordance with the following: (a) if the Participant reaches Early Retirement or Retirement (other than by reason of Disability or death), the first month of

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Plan Year following the later of the Participant’s 58th birthday or termination of employment; (b) in the event of Disability or Sale, within 90 days following the Disability or Sale, as the case may be; (c) if the Participant dies, in the manner specified in Section 5.4.4; or (d) if there occurs a Change in Control and the Participant requested to commence distribution upon the Change in Control (as described in Section 5.1.1), in a lump sum within 90 days following the Change in Control; or (e) the Plan terminates, in which event distributions will be made in the manner specified in Section 8.2. Provided, however, that a Participant who transfers employment between or among the Company, an Affiliate, the parent company of the Company or an Affiliate, or any entity affiliated with any of the foregoing as determined under Section 1.1.30 shall not be considered to have terminated employment for purposes of this Section. Any portion not payable as of the Participant’s termination of employment shall be forfeited.

5.2.4.Special Rule in Event of Sale. If a Participant remains employed with the Company or an Affiliate until the Sale of the Participant’s Employer and if after the Sale, the Participant is no longer employed by the Company, an Affiliate, or the parent company of the Company or an Affiliate, or any entity affiliated with any of the foregoing as determined under Section 1.1.30, the Sale shall be a distribution event with respect to a Participant’s Scheduled Withdrawal Accounts and Retirement Account, including that portion of such Accounts with respect to which distribution has commenced in installments on or before the Sale, but only with respect to amounts deferred under the Plan on or after January 1, 2011. Such distribution shall be made in a lump sum within 90 days following the Sale. The Plan shall separately account for

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amounts deferred on or before December 31, 2010 and on or after January 1, 2011, under a Participant’s Scheduled Withdrawal Accounts and Retirement Account.

Section 5.3.Form of Benefit Payment. At the time that a Retirement Account or Company Account is first opened under the Plan for a Participant, the Participant shall select the period over which payments from both Accounts will be made, and an election made with respect to one Account shall apply with respect to the other Account even if the other Account has not yet been opened. Provided, however, that if the Company Account is the first Account of the two to be opened, an election with respect to that Company Account must be made either before the Company Account is opened or, if made after the Account has been opened, only if the Participant will not be vested in the Account for at least 12 months from the date of the election and only if the election is made within 30 days of the date that the Account is opened. If made after the Account is opened, the election made will not be effective until 12 months after the date of the election. The Participant may elect to receive payment in the form of a lump sum or in monthly installments over 10, 15 or 20 years, or in a combination of lump sum and installments except that a distribution upon a Change in Control or Sale or upon termination of employment (including Early Retirement, but not including Retirement) will be distributed in the form of a lump sum only. If no valid election is made, the Participant shall be deemed to have made an election to receive payments from the Retirement Account and Company Account in a lump sum. A Participant's Account will continue to be credited during the payment period with earnings and losses as set forth in Section 4.6, except that earnings and losses shall not be credited after termination of employment other than Early Retirement (with respect to the Company Account only), Retirement, Sale or Change in Control.

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Section 5.4.Death Benefits.

5.4.1.Beneficiary Designation. At the time a Participant begins participation in the Plan, the Participant may designate primary and contingent Beneficiaries for death benefits payable under the Plan. Such Beneficiaries may be individuals or trusts for the benefit of individuals. If the Participant is married at the time of the Participant’s death, the designation of a primary Beneficiary other than the Participant’s spouse as sole primary Beneficiary shall be valid only if the Participant’s spouse has consented in writing to the naming of such primary Beneficiary and only if the spouse’s consent has been notarized. A Beneficiary designation by a Participant shall be in writing on a form acceptable to the Committee and shall only be effective upon delivery to the Committee. A Beneficiary designation may be revoked by a Participant at any time by delivering to the Company a new Beneficiary designation form. The Beneficiary designation form last delivered to the Committee before the death of a Participant, if valid, shall control.

5.4.2.Failure to Designate. If there is no valid Beneficiary designation on file with the Company, or if all Beneficiaries designated by a Participant have predeceased the Participant, the benefits payable under the Plan by reason of the death of the Participant shall be paid to the Participant's spouse, if living; if the Participant does not leave a surviving spouse, to the Participant's issue by right of representation; or, if there are no such issue then living, to the Participant's estate. If there are benefits remaining unpaid at the death of a sole Beneficiary (who died after the Participant) under the Plan and if no successor Beneficiary has been designated, the remaining balance of the benefits under the Plan shall be paid to the deceased Beneficiary's estate, unless the Beneficiary designation form provides to the contrary. If there are benefits remaining

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unpaid at the death of a Beneficiary (who died after the Participant) who is one of multiple concurrent Beneficiaries, such remaining benefits shall be paid proportionally to the surviving Beneficiaries, unless the Beneficiary designation form provides to the contrary.

5.4.3.Death After Benefit Commencement. If a Participant dies after benefits have commenced pursuant to Section 5.2, the Participant's Account balance(s), if any, shall be paid to the Participant's Beneficiary in the same manner that benefits would have been paid to the Participant had the Participant survived.

5.4.4.Death Before Benefit Commencement. If the Participant dies before distribution has commenced to the Participant, distribution to the Beneficiary shall be in the form of a lump sum. Distribution shall be made as soon as administratively practicable following the Participant's death, but in no event later than 90 days following the date of death.

5.4.5.Marital Deduction. If any benefits are payable under the Plan to the surviving spouse of a deceased Participant, the estate of the Participant's spouse shall be entitled to all remaining benefits, if any, at the spouse’s death, unless specifically directed to the contrary by an effective Beneficiary designation.

Section 5.5.Change in Elections. A Participant may change a distribution election only in conformance with the provisions of Section 409A of the Code. Specifically, a change in distribution election must conform to the following: (a) The change cannot be effective for 12 months after the election is made, or such later date as the Participant specifies in the election; (b) The change in election must be made at least 12 months before the date that the distribution was otherwise to commence; and (c) The commencement date of the distribution must be

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delayed for at least five years. For purposes of this provision, an installment payment shall be deemed to be a single payment so that a change in a payment election relating to installment payments shall apply to all installments. A change in election cannot be made after benefit payments have begun to the Participant or Beneficiary and cannot be made after the Participant or Beneficiary is in constructive receipt of the benefit payments to be changed.

Section 5.6.Confidentiality. By accepting benefits under this Plan, a Participant recognizes that the Participant’s knowledge of the Employer’s Confidential Information is of great value to the Employer. Therefore, each Participant shall be bound by the following provisions:

Section 5.6.1.Duty of Confidentiality. The Participant shall not, during the Participant’s employment, or at any time thereafter, use, divulge or disclose to any person, firm, corporation or other entity, any Confidential Information, except in the performance of the Participant’s duties for the Employer

Section 5.6.2.Injunctive Relief. Recognizing that damages at law would be difficult to ascertain, a Participant consents to the granting of equitable relief by way of restraining order or injunction in any court of competent jurisdiction to prevent the breach or threatened breach of the covenants contained in this Section 5.6.

Section 5.6.3.Forfeiture of Account for Breach of Confidentiality Covenant. In addition to injunctive relief, if the Participant breaches or threatens to breach the covenants contained in this Section 5.6, the Participant shall forfeit 100% of the Company Account under this Plan.

Section 5.6.4.Costs of Suit. The Participant shall pay all costs of any suit brought to enforce the provisions of this Section 5.6, including, but not limited to, reasonable attorneys’ fees.

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Section 5.7.Competition. By accepting benefits under this Plan, a Participant recognizes that the Participant’s knowledge of the business, customers, suppliers and employees of the Participant’s Employer is of great value to the Employer. The Participant understands that the Company and the Employer are willing to make the full benefit of the Plan available to a Participant only if the Participant does not reduce that value to the Company and the Employer through Competition as defined in Sections 5.7.1 and 5.7.2. The Company and the Participants understand that the provisions of this Section 5.7 do not prevent the Participant from taking any of the actions set forth below. The consequence of the Participant’s engaging in Competition as set forth below is the forfeiture of the Accounts as set forth in Section 5.7.3.

5.7.1.Employment by Competition. A Participant shall be considered to be in Competition for purposes of this Plan if during the Participant’s employment or during any of the three year period beginning on the date that the Participant leaves the employ of the Employer, the Participant enters the employ or is engaged as an officer or director of any person, firm, corporation or other entity, or engages, directly or indirectly, as a proprietor, partner, shareholder, member, agent, officer, director, independent contractor, financier, or co-investor in a business competitive with that of the Employer, as such business is now or may hereafter be conducted in the United States, other than as the owner of less than 5% of the securities of a publicly-traded corporation.

5.7.2.Solicitation of Customers, Suppliers or Employees. A Participant shall be considered to be in Competition for purposes of this Plan if during the Participant’s employment or during any of the three year period beginning on the date the Participant leaves the employ of the Employer, the Participant solicits for business, directly or indirectly, otherwise than on behalf of the Employer, any person, firm, corporation or other

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entity which is or was a customer or supplier of the Employer at any time during the Participant’s employment or which the Employer is or was actively soliciting as a customer or supplier during said time, or if the Participant solicits for business or for employment, directly or indirectly, any person who is or was an employee of the Employer at the time or during the six month period preceding the date the Participant leaves the employ of the Employer.

Section 5.7.3.Forfeiture of Account for Breach of Competition Covenants. The Company’s remedy for any Competition by the Participant under Section 5.7.1 or 5.7.2 is the forfeiture of 100% of the Company Account under this Plan. Neither the Company nor the Employer can obtain injunctive relief for Competition by the Participant under this Section 5.7.

Section 5.7.4.Costs of Suit. The Participant shall pay all costs of any suit brought to enforce the provisions of this Section 5.7, including, but not limited to, reasonable attorneys’ fees.

Section 5.8.Forfeiture for Cause. Anything in this Plan to the contrary notwithstanding, the Participant shall forfeit 100% of the unpaid portion of the Company Account if the Participant is or could have been terminated from employment for Cause.

Section 5.9.Minimum Amount and Frequency of Payments. If the value of all Accounts at the date of initial distribution is less than $50,000, then, notwithstanding any other provision of the Plan to the contrary, the Committee shall pay the Accounts in a lump sum.

Section 5.10.Section 162(m) of the Code. Notwithstanding anything to the contrary in this Plan, a Participant’s Employer may defer payment of any amounts otherwise required to be

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paid under this Plan in order to preserve the deduction for such payment under Section 162(m) of the Code, but only to the extent permitted by and consistent with Section 409A of the Code.

Section 5.11.Acceleration of Distributions. If the Internal Revenue Service determines that the Plan violates Section 409A of the Code and has made a final assessment of an income tax deficiency with respect to such determination or if a final judicial determination has been entered that the Plan violates Section 409A of the Code with respect to a Participant or Beneficiary, the Committee shall distribute to such Participant or Beneficiary an amount equal to the taxable income recognized.

Section 5.12.Unforeseeable Emergencies. Upon the application of any Participant, the Committee may permit such Participant to withdraw some or all of the amount in one or more of the Participant’s Deferral Accounts. A Participant must provide the Committee with a written petition of the intent to withdraw from the Participant’s Deferral Accounts at least 60 days (or such shorter time as permitted by the Committee in its discretion) before the date of withdrawal. No withdrawal shall be made under the provisions of this Section except for the purpose of enabling a Participant to meet immediate needs created by a severe financial hardship to the Participant or resulting from an illness or accident of the Participant or of the spouse or dependent (as determined under Section 152 of the Code, without regard to Section 152(b)(1), (b)(2) and (d)(3)(B)) or Beneficiary of the Participant, loss of the property of the Participant due to casualty, the Disability of the Participant, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The circumstances that will constitute a severe financial hardship will depend upon the facts of each case, but, in any case, payment may not be made to the extent that such hardship is or may be relieved: (a) through reimbursement or compensation through insurance or otherwise; (b) by

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liquidation of the Participant’s assets, to the extent such liquidation would not itself cause a severe financial hardship; or (c) by termination of deferrals under the Plan, which termination shall be required. If a withdrawal is permitted, the amount of the withdrawal, which may include amounts reasonably anticipated as needed to pay applicable federal, state or local taxes and penalties, shall be distributed to the Participant in a lump sum as soon as is administratively practicable following the requested withdrawal date. If the deferral election of the Participant is terminated under this Section the Participant may not enter into a new deferral election until a Plan Year that begins at least 12 months following the date of the withdrawal and then only at a time consistent with Section 4.1. and Section 409A of the Code.

Section 5.13.Deferral Election Termination. Notwithstanding any provision of this Plan to the contrary, a Participant’s deferral election shall be terminated if the Participant receives a hardship withdrawal distribution from a plan described in Section 401(k) of the Code in which the Participant participates, but only if the terms of such 401(k) plan require that the deferral election under this Plan be terminated. The Participant may not enter into a new deferral election until at least six months following the effective date of the termination of the deferral election and then only at a time consistent with Section 4.1 and Section 409A of the Code.

Section 5.14.Limitation on Payment. Notwithstanding any provision in the Plan to the contrary, the payment of a benefit payable under the Plan to a Participant or Beneficiary may be deferred or limited in order to comply with applicable securities laws, tax laws, judicial determinations or orders, bank covenants, or any other applicable law as permitted under Section 409A of the Code.

Section 5.15.Delay of Distribution. Notwithstanding any other provision of the Plan to the contrary, distribution on separation from service, as defined under Code Section 409A, shall

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be delayed until the first day of the month following the six month anniversary of the Participant’s separation from service, or if earlier, the death of the Participant, but only with respect to a specified employee, as defined in Code Section 409A. If such distribution is delayed, then the first payment under the Plan shall include all amounts that were otherwise scheduled to be paid but for the required delay. Earnings shall be credited on such amounts as calculated under Section 4.6.

Section 5.16.Distributions on Plan Termination. Notwithstanding anything in Article 5 to the contrary, if the Plan is terminated, distributions shall be made in accordance with Section 8.2.

Section 5.17.Claims Procedure.

5.17.1.Initial Claim for Benefits. The following shall apply with respect to claims of Participants for benefits under the Plan, other than claims governed by Section 5.17.3 below. The Committee shall give notice to a Participant within 90 days of the Participant's written application for benefits of the Participant’s eligibility or noneligibility for benefits under the Plan. If the Committee determines that a Participant is not eligible for benefits or full benefits, the notice shall set forth (a) the specific reasons for such denial, (b) a specific reference to the provision of the Plan on which the denial is based, (c) a description of any additional information or material necessary for the claimant to perfect the claim, and a description of why it is needed, and (d) an explanation of the Plan's claims review procedure and other appropriate information as to the steps to be taken if the Participant wishes to have the claim reviewed. If the Committee determines that there are special circumstances requiring additional time to make a decision, the Committee shall give notice to the Participant of the special

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circumstances and the date by which a decision is expected to be made, and may extend the time for up to an additional 90-day period.

5.17.2.Appeal of Claim Denial. If a Participant is determined by the Committee under Section 5.17.1 above to be not eligible for benefits, or if the Participant believes that the Participant is entitled to greater or different benefits, the Participant shall have the opportunity to have the claim reviewed by filing a petition for review within 60 days after the Participant has been given the notice issued by the Committee. If there is no Trust in place with respect to the Participant’s benefit, or if there is a Trust, but the Trustee has not agreed to determine appeals from denials of claims for benefits under the Plan, then the petition shall be filed with the Committee. If there is a Trust in place with respect to the Participant’s benefit and if the Trustee has agreed to determine appeals from denials of claims for benefits under the Plan, then the petition shall be filed with the Trustee of the Trust. A petition shall state the specific reasons the Participant believes that the Participant is entitled to benefits or greater or different benefits. Within 60 days after the petition has been filed, the Committee or the Trustee, as the case may be, shall afford the Participant an opportunity to present the Participant’s position to the Committee or the Trustee, as the case may be, in writing, and the Participant shall have the right to review pertinent documents. The Committee or the Trustee, as the case may be, shall give notice to the Participant of its decision in writing within said 60-day period, stating specifically the basis of the decision written in a manner calculated to be understood by the Participant and the specific provisions of the Plan on which the decision is based. If because of special circumstances, the 60-day period is not sufficient, the decision may be deferred for up to another 60-day period at the election of the

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Committee or the Trustee, as the case may be, but notice of this deferral shall be given to the Participant.

5.17.3.Disability Claim for Benefits. If a Participant makes a claim for benefits under the Plan that is contingent on the Committee determining that the Participant is Disabled, the Committee will give notice to the Participant within 45 days of the Participant's written application for benefits of the Participant’s eligibility or noneligibility for benefits under the Plan. If special circumstances require an extension, the Committee will notify the Participant within the 45-day processing period that additional time is needed. The notice will specify the circumstances requiring the extension and the date a decision can be expected. The extension notice will also: (a) explain the standards for approving a disability claim; (b) state the unresolved issue(s) that prevent the Committee from reaching a decision; and (c) describe any additional information needed to resolve the issue(s). If the Committee requests the Participant to provide additional information so it can process the claim, the Participant will be given at least 45 days in which to provide the information. Otherwise, the initial extension cannot exceed 30 days. If circumstances require further extension, the Committee will notify the Participant before the end of the initial 30-day extension. The notice will specify the circumstances requiring the further extension and the date a decision can be expected. In no event will a decision be postponed beyond an additional 30 days after the end of the first 30-day extension. If the disability claim is denied based on an internal rule, guideline, protocol, or other similar provision, in addition to the notice provisions described in this section, the Committee’s notice will provide that a copy of such rule, guideline, protocol or other similar provision is available upon request and free of charge.

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The notice will also identify any medical or vocational experts consulted on the claim. The Participant may obtain reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits and may request, in writing, a list of medical or vocational experts consulted.

5.17.4. Review of a Denied Disability Claim. A Participant may request a review of the Committee’s decision regarding a disability claim within 180 days after receipt of the denial of the disability claim. This request must be in writing and addressed to the Plan Administrator. The Participant may, but is not required to, submit written comments, documents, records and other information relating to the claim for benefits. The review will take into account any such comments, documents, records and other information submitted by the Participant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The review will be conducted by a Plan fiduciary different from the fiduciary who originally denied the claim. This fiduciary cannot be a subordinate of the fiduciary who originally denied the claim. If the original denial of the claim was based on a medical judgment, the reviewing fiduciary will consult with an appropriate health care professional who was not consulted on the original claim and who is not subordinate to someone who was. The Participant will receive notice of the reviewing fiduciary's final decision regarding the disability claim within 45 days of the request for review.

5.17.5. Deadline to File Claim. To be considered timely under the Plan’s Claims Procedures, a claim must be filed under Section 5.17.1 or 5.17.3 within one year after the claimant knew or reasonably should have known of the principal facts upon which the

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claim is based. Knowledge of all facts that the Participant knew or reasonably should have known shall be imputed to the claimant for the purpose of applying this deadline.

5.17.6. Exhaustion of Administrative Remedies. The exhaustion of the Plan’s claims procedures is mandatory for resolving every claim and dispute arising under this Plan. As to such claims and disputes: (a) No claimant shall be permitted to commence any legal action to recover Plan benefits or to enforce or clarify rights under the Plan under Section 502 or Section 510 of ERISA or under any other provision of law, whether or not statutory, until the claims procedures have been exhausted in their entirety; and (b) In any such legal action all explicit and all implicit determinations by the Committee, Trustee or Plan Administrator, as the case may be, (including, but not limited to, determinations as to whether the claim, or a request for a review of a denied claim, was timely filed) shall be afforded the maximum deference permitted by law.

5.17.7. Deadline to File Legal Action. No legal action to recover Plan benefits or to enforce or clarify rights under the Plan under Section 502 or Section 510 of ERISA or under any other provision of law, whether or not statutory, may be brought by any claimant on any matter pertaining to this Plan unless the legal action is commenced in the proper forum before the earlier of: (a) 30 months after the claimant knew or reasonably should have known of the principal facts on which the claim is based, or (b) six months after the claimant has exhausted the claims procedure under this Plan. Knowledge of all facts that the Participant knew or reasonably should have known shall be imputed to every claimant who is or claims to be a beneficiary of the Participant or otherwise claims to derive an entitlement by reference to the Participant for the purpose of applying the previously specified periods.

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5.17.8. Committee Discretion; Court Review. The Committee and all persons determining or reviewing claims have full discretion to determine benefit claims under the Plan. Any interpretation, determination or other action of such persons shall be subject to review only if it is arbitrary or capricious or otherwise an abuse of discretion. Any review of a final decision or action of the persons reviewing a claim shall be based only on such evidence presented to or considered by such persons at the time they made the decision that is the subject of review.

ARTICLE 6.FUNDING.

Section 6.1.Source of Benefits. All benefits under the Plan shall be paid when due by the Company out of its assets or from the Trust.

Section 6.2.No Claim on Specific Assets. No Participant shall be deemed to have, by virtue of being a Participant in the Plan, any claim on any specific assets of the Company such that the Participant would be subject to income taxation on the Participant’s benefits under the Plan before distribution. The rights of Participants and Beneficiaries to benefits to which they are otherwise entitled under the Plan shall be those of an unsecured general creditor of the Company. 

ARTICLE 7.ADMINISTRATION AND FINANCES.

Section 7.1.Administration. The Plan shall be administered by the Committee. The Company shall bear all administrative costs of the Plan other than those specifically charged to a Participant or Beneficiary.

Section 7.2.Powers of Committee. In addition to the other powers granted under the Plan, the Committee shall have all powers necessary to administer the Plan, including, without limitation, power exercisable in its sole discretion (a) to interpret the provisions of the Plan; (b) to determine the rights of employees, Participants and Beneficiaries to benefits under the Plan;

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(c) to establish and revise the method of accounting for the Plan; (d) to maintain the Accounts; (e) to determine Crediting Rates for the Accounts; (f) to establish rules for the administration of the Plan; and (g) to prescribe any forms required to administer the Plan.

Section 7.3.Actions of the Committee. Except as modified by the Board, the Committee (including any person or entity to whom the Committee has delegated duties, responsibilities or authority, to the extent of such delegation) has total and complete discretionary authority to determine conclusively for all parties all questions arising in the administration of the Plan, to interpret and construe the terms of the Plan, and to determine all questions of eligibility and status of employees, Participants and Beneficiaries under the Plan and their respective interests. Subject to the claims procedures of Section 5.17, all determinations, interpretations, rules and decisions of the Committee (including those made or established by any person or entity to whom the Committee has delegated duties, responsibilities or authority, if made or established pursuant to such delegation) are conclusive and binding upon all persons having or claiming to have any interest or right under the Plan.

Section 7.4.Delegation. The Committee, or any officer designated by the Committee, shall have the power to delegate specific duties and responsibilities to officers or other employees of the Company or other individuals or entities. Any delegation may be rescinded by the Committee at any time. Each person or entity to whom a duty or responsibility has been delegated shall be responsible for the exercise of such duty or responsibility and shall not be responsible for any act or failure to act of any other person or entity. All delegations made under the Otter Tail Corporation Nonqualified Retirement Plan effective January 1, 2003 shall also apply under this Plan.

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Section 7.5.Reports and Records. The Committee, and those to whom the Committee has delegated duties under the Plan, shall keep records of all their proceedings and actions and shall maintain books of account, records, and other data as shall be necessary for the proper administration of the Plan and for compliance with applicable law.

ARTICLE 8.AMENDMENTS AND TERMINATION.

Section 8.1.Amendments. The Company, by action of the Board, or the Committee to the extent authorized by the Board, may amend the Plan, in whole or in part, at any time and from time to time. Provided, however, that for a period of 24 months following a Change in Control, no amendment shall be effective without the approval of a majority of the Participants in the Plan (so long as there is more than one Participant). Any amendment shall be filed with the Plan documents. No amendment, however, may be effective to eliminate or reduce any Account balance, determined as of the date of such amendment, of any Participant or of any Beneficiary then eligible for benefits, without such Participant's or Beneficiary's consent.

Section 8.2.Termination.

8.2.1.Termination of Plan. The Company reserves the right to terminate the Plan at any time by action of the Board. Provided, however, that for a period of 24 months following a Change in Control, no termination shall be effective without the approval of a majority of the Participants in the Plan (so long as there is more than one Participant). Upon termination of the Plan, all deferrals and Company Contributions will cease and no future deferrals or Company Contributions will be made. Termination of the Plan shall not operate to eliminate or reduce any Account balance, determined as of the date of such termination, of any Participant or of any Beneficiary then eligible for benefits, without such Participant's or Beneficiary's consent. If the Company desires to distribute benefits

40

on termination of the Plan, the Company must also meet the following requirements: (a) The distribution must not occur proximate to a downturn in the financial health of the Company; (b) The Company must terminate all arrangements of a type similar to the Plan; (c) No distributions may be made as a result of the termination within 12 months of the termination of all the arrangements; (d) All distributions must be made in a lump sum within 24 months of the termination of the Plan; and (e) The Company may not adopt a new arrangement of the same type covering any of the Participants at any time within three years following the date of termination of the Plan. Provided, however, that if the termination occurs within 12 months following a Change in Control, then in lieu of the requirements of the foregoing sentence, the Company must terminate the arrangement for all Participants affected by the Change in Control and distribution must be made in a lump sum as soon as administratively practicable (but in no event longer than 90 days) following the termination and in no event later than 12 months following the Change in Control. Accounts shall be credited with earnings during the payment period in accordance with Section 4.6 and 5.3. Each Participant who has not terminated employment shall become entitled to 100% of the amount in all the Participant’s Accounts on Plan termination. These termination provisions shall be interpreted in a manner consistent with Section 409A of the Code.

8.2.2.Termination of Portion of Plan after a Sale. The Company reserves the right to terminate that portion of the Plan applicable to Participants employed by an Employer that is the subject of a Sale to an entity that is not the Company or an Affiliate so long as the Sale is considered a change in control under Section 409A of the Code with respect to the Participants whose Accounts shall be paid in connection with the

41

termination. The Company may terminate and liquidate that portion of the Plan pursuant to irrevocable action taken within 30 days preceding or 12 months following the Sale. Provided, however, that all agreements, methods, programs and other arrangements sponsored by the Company and its Affiliates immediately after the Sale with respect to which deferrals of compensation are treated as having been deferred under a single plan under Section 409A of the Code are terminated and liquidated with respect to each Participant that experienced the Sale so that all such Participants receive all amounts of compensation under the Plan and all such agreements, methods, programs and other arrangements. Such payment shall be made within 12 months of the date the Company irrevocably takes all necessary action to terminate and liquidate such portion of the Plan and all other arrangements. The Company may take this action only if the Company remains primarily liable after the Sale for the payment of the deferred compensation under the Plan. Accounts under this Plan to be liquidated shall be credited with earnings during the period between the action taken to terminate the portion of the Plan and the distribution in accordance with Sections 4.6 and 5.3. This termination provision shall be interpreted in a manner consistent with Section 409A of the Code and shall be effective on the date the restated Plan is adopted by the Company.

ARTICLE 9.MISCELLANEOUS.

Section 9.1.No Guarantee of Employment. Neither the adoption and maintenance of the Plan nor the execution by the Company of a deferral or Account election with any Participant shall be deemed to be a contract of employment between the Company or any Affiliate and any Participant. Nothing contained herein shall give any Participant the right to be retained in the employ of the Company or any Affiliate or to interfere with the right of the Company or any

42

Affiliate to discharge any Participant at any time, nor shall it give the Company or any Affiliate the right to require any Participant to remain in its employ or to interfere with the Participant's right to terminate the Participant’s employment at any time.

Section 9.2.Release. Any payment of benefits to or for the benefit of a Participant or a Participant's Beneficiaries that is made in good faith by the Company in accordance with the Company's interpretation of its obligations hereunder shall be in full satisfaction of all claims against the Company or an Affiliate for benefits under this Plan to the extent of such payment.

Section 9.3.Notices. Any notice or communication permitted or required under the Plan shall be in writing and shall be delivered personally, or sent by registered or certified mail, return receipt requested, postage prepaid, or sent by nationally recognized overnight carrier, postage prepaid, or sent by facsimile transmission to the principal office of the Company, if to the Company, or to the address last shown on the records of the Company or an Affiliate, if to a Participant or Beneficiary. Such notice or communication shall be deemed given (a) when delivered if personally delivered; (b) five mailing days after having been placed in the mail, if delivered by registered or certified mail; (c) the business day after having been placed with a nationally recognized overnight carrier, if delivered by nationally recognized overnight carrier, and (d) the business day after transmittal when transmitted with electronic confirmation of receipt, if transmitted by facsimile. Any party may change the address or facsimile number to which notices or communications are to be sent to it by giving notice of such change in the manner herein provided for giving notice.

Section 9.4.Nonalienation. No benefit payable at any time under this Plan shall be subject in any manner to alienation, sale, transfer, assignment, pledge, levy, attachment, or encumbrance of any kind by any Participant or Beneficiary.

43

Section 9.5.Tax Liability. The Company may withhold or direct the trustee of the Trust to withhold from any payment of benefits (or from any other amounts to be paid to the Participant or Beneficiaries) such amounts as the Company determines are reasonably necessary to pay any taxes (and interest thereon) required to be withheld or for which the trustee of the Trust may become liable under applicable law. The Company may also forward or direct the trustee of the Trust to forward to the appropriate taxing authority any amounts required to be paid by the Company or the Trust under the preceding sentence.

Section 9.6.Parachute and Other Payments. No gross up or other recalculations of amounts owed under this Plan shall be made to avoid excess parachute payments under Section 280G of the Code or excise tax liability under Section 4999 of the Code or liability under Section 409A of the Code.

Section 9.7.Indemnification. The Company shall indemnify and defend to the fullest extent permitted by law any employee or former employee serving or formerly serving as a member of the Committee against all liabilities, damages, costs and expenses (including attorneys' fees and amounts paid in settlement of any claims approved by the Company) occasioned by any act or omission to act in connection with the Plan, if such act or omission is in good faith.

Section 9.8.Captions. Article and section headings and captions are provided for purposes of reference and convenience only and shall not be relied upon to construe, define, modify, limit, or extend the scope of any provision of the Plan.

Section 9.9.Applicable Law. The Plan and all rights hereunder shall be governed by and construed according to the laws of the State of Minnesota, except to the extent such laws are preempted by the laws of the United States of America. The Plan shall be interpreted in a manner

44

consistent with all applicable laws, including the Americans with Disabilities Act and Section 409A of the Code. The restatement of the Plan shall be interpreted in a manner that does not change the time or form of distribution of any deferrals made to the Plan before the effective date of the restatement.

IN WITNESS WHEREOF, Otter Tail Corporation has caused this Plan to be executed and has confirmed the joinder of the Affiliates listed on the attached Appendix A by its duly authorized officers this 28 day of October, 2010.

OTTER TAIL CORPORATION
By:	/s/ Michelle Kommer
Its	SVP  HR

45

APPENDIX A

AFFILIATES

 The following entities are Affiliates under the Plan as of the date of adoption of the restated Plan:

 Aevenia, Inc.

 BTD Manufacturing, Inc.

 DMI Industries, Inc.

 DMS Health Technologies, Inc.

 E.W. Wylie Corporation

 Foley Company

 Idaho Pacific Holdings, Inc.

 Northern Pipe Products, Inc.

 Otter Tail Energy Services Company, Inc.

 Otter Tail Power Company

 ShoreMaster, Inc.

 T.O. Plastics, Inc.

 Vinyltech Corporation

46

EX-31.1

    Exhibit 31.1

           CERTIFICATION PURSUANT TO

      SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Edward J. McIntyre, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2011

/s/  Edward J. McIntyre

Edward J. McIntyre

Interim Chief Executive Officer and President

EX-31.2

    Exhibit 31.2

        CERTIFICATION PURSUANT TO

          SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Moug, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2011

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward J. McIntyre, Interim Chief Executive Officer and President of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Edward J. McIntyre

Edward J. McIntyre

Interim Chief Executive Officer and President

November 9, 2011

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Kevin G. Moug  

Kevin G. Moug

Chief Financial Officer

November 9, 2011

XML

Major Components of Assets and Liabilities of Discontinued Operations (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets	$ 2	$ 27,297
Goodwill		24,324
Other Intangibles - Net		10,852
Net Plant	75	31,310
Assets of Discontinued Operations	77	93,783
Current Liabilities	77	10,989
Deferred Income Taxes		11,553
Long-Term Debt		634
Liabilities of Discontinued Operations	77	23,176
Wylie-Wind
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets	2	2,461
Net Plant	75	638
Assets of Discontinued Operations	77	3,099
Current Liabilities	77	4,150
Liabilities of Discontinued Operations	77	4,150
IPH
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets		24,836
Goodwill		24,324
Other Intangibles - Net		10,852
Net Plant		30,672
Assets of Discontinued Operations		90,684
Current Liabilities		6,839
Deferred Income Taxes		11,553
Long-Term Debt		634
Liabilities of Discontinued Operations		$ 19,026

XML

Supplemental Disclosure of Cash Flow Information (Detail) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Schedule of Cash Flow, Supplemental [Line Items]
Increases in Accounts Payable Related to Capital Expenditures	$ 1,790	$ 63

XML

Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Common Shares, Par Value	$ 5	$ 5
Common Shares, Authorized	50,000,000	50,000,000
Common Shares, Outstanding	36,062,023	36,002,739
Cumulative Preferred Shares
Cumulative Shares, Authorized	1,500,000	1,500,000
Cumulative Shares, Without Par Value	$ 0	$ 0
Cumulative Shares, Outstanding	155,000	155,000
Cumulative Preference Shares
Cumulative Shares, Authorized	1,000,000	1,000,000
Cumulative Shares, Without Par Value	$ 0	$ 0
Cumulative Shares, Outstanding	0	0

XML

Consolidated Statements of Income (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues
Electric	$ 85,117	$ 89,272	$ 254,618	$ 258,130
Nonelectric	230,641	170,474	659,473	495,879
Total Operating Revenues	315,758	259,746	914,091	754,009
Operating Expenses
Production Fuel - Electric	19,080	18,210	55,737	55,611
Purchased Power - Electric System Use	7,488	10,254	27,759	32,730
Electric Operation and Maintenance Expenses	27,323	27,098	84,718	84,817
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)	184,964	138,403	534,503	392,899
Other Nonelectric Expenses	37,163	32,298	97,470	93,527
Asset Impairment Charge				19,740
Depreciation and Amortization	19,937	19,175	58,748	56,404
Property Taxes - Electric	2,601	2,271	7,427	7,222
Total Operating Expenses	298,556	247,709	866,362	742,950
Operating Income	17,202	12,037	47,729	11,059
Other Income	489	704	2,317	1,269
Interest Charges	8,708	9,287	27,346	27,707
Income (Loss) Before Income Taxes - Continuing Operations	8,983	3,454	22,700	(15,379)
Income Tax Expense (Benefit) - Continuing Operations	2,109	(607)	4,194	(6,625)
Net Income (Loss) from Continuing Operations	6,874	4,061	18,506	(8,754)
Discontinued Operations
Income (Loss) from Discontinued Operations net of income tax (benefit) expense of $(34), $1,225, $(398), and $3,081 for the respective periods	(52)	2,040	(412)	5,354
Gain (Loss) on Disposition of Discontinued Operations net of income tax (benefit) expense of $(302), $0, $3,213, and $0 for the respective periods	(454)		12,798
Net Income (Loss) from Discontinued Operations	(506)	2,040	12,386	5,354
Total Net Income (Loss)	6,368	6,101	30,892	(3,400)
Preferred Dividend Requirement and Other Adjustments	184	187	874	650
Earnings Available for Common Shares	$ 6,184	$ 5,914	$ 30,018	$ (4,050)
Average Number of Common Shares Outstanding-Basic	35,933,003	35,806,453	35,911,993	35,775,418
Average Number of Common Shares Outstanding-Diluted	36,171,555	36,076,421	36,150,545	35,775,418
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$ 0.18	$ 0.11	$ 0.50	$ (0.26)
Discontinued Operations (net of other adjustments)	$ (0.01)	$ 0.06	$ 0.34	$ 0.15
Earnings Per Share, Basic, Total	$ 0.17	$ 0.17	$ 0.84	$ (0.11)
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$ 0.18	$ 0.11	$ 0.50	$ (0.26)
Discontinued Operations (net of other adjustments)	$ (0.01)	$ 0.05	$ 0.33	$ 0.15
Earnings Per Share, Diluted, Total	$ 0.17	$ 0.16	$ 0.83	$ (0.11)
Dividends Declared Per Common Share	$ 0.2975	$ 0.2975	$ 0.8925	$ 0.8925

XML

Status of Lines of Credit (Detail) (USD $) In Thousands	Sep. 30, 2011	Mar. 03, 2011	Dec. 31, 2010
Line of Credit Facility [Line Items]
Line Limit	$ 370,000
In Use	39,010
Restricted due to Outstanding Letters of Credit	2,424
Available	328,566		288,786
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	200,000
In Use	20,000
Restricted due to Outstanding Letters of Credit	1,374
Available	178,626		144,350
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000	170,000
In Use	19,010
Restricted due to Outstanding Letters of Credit	1,050
Available	$ 149,940		$ 144,436

XML

Information for the Business Segments (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating Revenue	$ 315,758	$ 259,746	$ 914,091	$ 754,009
Interest Charges	8,708	9,287	27,346	27,707
Income Tax Expense (Benefit) - Continuing Operations	2,109	(607)	4,194	(6,625)
Earnings Available for Common Shares	6,184	5,914	30,018	(4,050)
Assets	1,711,984		1,711,984		1,770,555
Electric
Segment Reporting Information [Line Items]
Operating Revenue	85,172	89,315	254,799	258,294
Interest Charges	4,796	5,172	14,874	15,791
Income Tax Expense (Benefit) - Continuing Operations	3,364	4,257	5,972	8,562
Earnings Available for Common Shares	10,900	12,265	29,428	24,188
Assets	1,101,146		1,101,146		1,106,261
Wind Energy
Segment Reporting Information [Line Items]
Operating Revenue	65,007	40,389	187,534	134,764
Interest Charges	1,925	1,641	5,806	4,511
Income Tax Expense (Benefit) - Continuing Operations	(863)	(3,529)	(4,676)	(5,053)
Earnings Available for Common Shares	(3,497)	(7,120)	(16,443)	(9,755)
Assets	169,138		169,138		172,753
Manufacturing
Segment Reporting Information [Line Items]
Operating Revenue	55,815	43,342	170,486	130,880
Interest Charges	1,323	1,298	3,984	3,839
Income Tax Expense (Benefit) - Continuing Operations	591	(349)	3,650	(4,800)
Earnings Available for Common Shares	1,083	(383)	6,071	(16,234)
Assets	152,693		152,693		144,272
Construction
Segment Reporting Information [Line Items]
Operating Revenue	53,247	36,885	139,895	84,808
Interest Charges	251	190	698	463
Income Tax Expense (Benefit) - Continuing Operations	(115)	435	(195)	(872)
Earnings Available for Common Shares	(179)	645	(320)	(1,337)
Assets	74,639		74,639		60,978
Plastics
Segment Reporting Information [Line Items]
Operating Revenue	36,231	26,736	99,082	76,562
Interest Charges	411	403	1,176	1,194
Income Tax Expense (Benefit) - Continuing Operations	1,295	238	3,198	873
Earnings Available for Common Shares	1,970	367	4,908	1,380
Assets	84,463		84,463		73,508
Health Services
Segment Reporting Information [Line Items]
Operating Revenue	21,853	24,300	67,331	73,116
Interest Charges	451	377	1,295	902
Income Tax Expense (Benefit) - Continuing Operations	115	311	863	(66)
Earnings Available for Common Shares	125	421	1,155	(235)
Assets	72,566		72,566		75,898
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(1,567)	(1,221)	(5,036)	(4,415)
Interest Charges	(449)	206	(487)	1,007
Corporate
Segment Reporting Information [Line Items]
Income Tax Expense (Benefit) - Continuing Operations	(2,278)	(1,970)	(4,618)	(5,269)
Earnings Available for Common Shares	(3,712)	(2,319)	(6,845)	(7,313)
Assets	57,262		57,262		43,102
Discontinued Operations
Segment Reporting Information [Line Items]
Earnings Available for Common Shares	(506)	2,038	12,064	5,256
Assets	$ 77		$ 77		$ 93,783

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Percentage of Consolidated Sales Revenue by Country

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
United States of America		98.2	%		98.9	%		98.2	%		98.2	%
Canada		1.3	%		0.9	%		1.5	%		1.6	%
All Other Countries		0.5	%		0.2	%		0.3	%		0.2	%

Information for the Business Segments

Information for the business segments for three and nine month periods ended September 30, 2011 and 2010 and total assets by business segment as of September 30, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	85,172		$	89,315		$	254,799		$	258,294
Wind Energy		65,007			40,389			187,534			134,764
Manufacturing		55,815			43,342			170,486			130,880
Construction		53,247			36,885			139,895			84,808
Plastics		36,231			26,736			99,082			76,562
Health Services		21,853			24,300			67,331			73,116
Corporate Revenues and Intersegment Eliminations		(1,567	)		(1,221	)		(5,036	)		(4,415	)
Total	$	315,758		$	259,746		$	914,091		$	754,009

Interest Charges

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Electric	$	4,796		$	5,172	$	14,874		$	15,791
Wind Energy		1,925			1,641		5,806			4,511
Manufacturing		1,323			1,298		3,984			3,839
Construction		251			190		698			463
Plastics		411			403		1,176			1,194
Health Services		451			377		1,295			902
Corporate and Intersegment Eliminations		(449	)		206		(487	)		1,007
Total	$	8,708		$	9,287	$	27,346		$	27,707

Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	3,364		$	4,257		$	5,972		$	8,562
Wind Energy		(863	)		(3,529	)		(4,676	)		(5,053	)
Manufacturing		591			(349	)		3,650			(4,800	)
Construction		(115	)		435			(195	)		(872	)
Plastics		1,295			238			3,198			873
Health Services		115			311			863			(66	)
Corporate		(2,278	)		(1,970	)		(4,618	)		(5,269	)
Total	$	2,109		$	(607	)	$	4,194		$	(6,625	)

Earnings Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	10,900		$	12,265		$	29,428		$	24,188
Wind Energy		(3,497	)		(7,120	)		(16,443	)		(9,755	)
Manufacturing		1,083			(383	)		6,071			(16,234	)
Construction		(179	)		645			(320	)		(1,337	)
Plastics		1,970			367			4,908			1,380
Health Services		125			421			1,155			(235	)
Corporate		(3,712	)		(2,319	)		(6,845	)		(7,313	)
Discontinued Operations		(506	)		2,038			12,064			5,256
Total	$	6,184		$	5,914		$	30,018		$	(4,050	)

Total Assets

	September 30,		December 31,
(in thousands)	2011		2010
Electric	$	1,101,146	$	1,106,261
Wind Energy		169,138		172,753
Manufacturing		152,693		144,272
Construction		74,639		60,978
Plastics		84,463		73,508
Health Services		72,566		75,898
Corporate		57,262		43,102
Discontinued Operations		77		93,783
Total	$	1,711,984	$	1,770,555

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Discontinued Operations - Additional Information (Detail) (USD $)	9 Months Ended	0 Months Ended
	Sep. 30, 2011	May 06, 2011 IPH
Proceeds from Sale of Discontinued Operations	$ 84,330,000	$ 87,000,000
Proceeds from sale of discontinued operations, deposited in an escrow account		$ 3,000,000

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Document and Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 31, 2011
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Trading Symbol	OTTR
Entity Registrant Name	OTTER TAIL CORP
Entity Central Index Key	0001466593
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		36,062,023

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Schedule of Estimated Amortization Expense (Detail) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011
Expected Amortization Expense [Line Items]
2011	$ 887
2012	911
2013	947
2014	947
2015	$ 931

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Common Shares and Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Reconciliation of the Company's Common Shares Outstanding

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2010 through September 30, 2011:

Common Shares Outstanding, December 31, 2010	36,002,739
Issuances:
Restricted Stock Issued to Employees	24,600
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	17,325
Retirements:
Shares Withheld for Individual Income Tax Requirements	(6,641	)
Common Shares Outstanding, September 30, 2011	36,062,023

Stock Options with Exercise Prices Greater than the Market Price Excluded from the Calculation of Diluted Earnings per Common 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 prices:

Three Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

Nine Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

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Amortization Expense - Intangible Assets (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Finite-Lived Intangible Assets [Line Items]
Amortization Expense - Intangible Assets	$ 220	$ 238	$ 668	$ 784

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Fair Value of Financial Instruments (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Short-Term Investments	$ 6,604
Long-Term Debt	(433,454)	(434,812)
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Short-Term Investments	6,604
Long-Term Debt	$ (479,567)	$ (474,307)

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Common Shares and Earnings Per Share

9 Months Ended

Sep. 30, 2011

Common Shares and Earnings Per Share

6.  Common Shares and Earnings Per Share

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2010 through September 30, 2011:

Common Shares Outstanding, December 31, 2010	36,002,739
Issuances:
Restricted Stock Issued to Employees	24,600
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	17,325
Retirements:
Shares Withheld for Individual Income Tax Requirements	(6,641	)
Common Shares Outstanding, September 30, 2011	36,062,023

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 prices:

Three Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

Nine Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

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Share-Based Payments (Tables)

9 Months Ended

Sep. 30, 2011

Stock Incentive Awards

On April 11, 2011 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors, executive officers and key employees under the 1999 Stock Incentive Plan, as amended:

Award	Shares/Units Granted		Grant-Date Fair Value per Share		Vesting
Restricted Stock Granted to Nonemployee Directors		24,000	$	22.51	25% per year through April 8, 2015
Restricted Stock Granted to Executive Officers		24,600	$	22.51	25% per year through April 8, 2015
SStock Performance Awards Granted to Executive Officers		48,600	$	23.61	December 31, 2013
Restricted Stock Units Granted to Employees		19,800	$	18.03	100% on April 8, 2015

Amounts of Compensation Expense Recognized under the Company's Stock-Based Payment Programs

Compensation expense recognized under the Company’s stock-based payment programs:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011		2010			2011		2010
Employee Stock Purchase Plan (15% discount)	$	51	$	64		$	185	$	205
Restricted Stock Granted to Directors		185		148			571		446
Restricted Stock Granted to Employees		511		239			759		519
Stock Performance Awards Granted to Executive Officers		1,766		722			1,766		879
Restricted Stock Units Granted to Employees		92		(20	)		244		137
Totals	$	2,605	$	1,153		$	3,525	$	2,186

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Corrected Classification Resulting in Increases in Operating Revenues and Operating Income and Decreases in Other Income (Detail) (USD $) In Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2010
MNCIP Incentives reclassified from Other Income to Operating Revenue	$ 550	$ 2,151

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
DMI Industries, Inc
Significant Accounting Policies [Line Items]
Receivable Sales Agreement	$ 40
Receivables sales agreement, discount rate basis description	The current discount rate is 3-month LIBOR plus 4%.
Receivables sales agreement, spread rate	4.00%
Minimum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	1 year
Maximum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	15 years

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Forward Contracts Classified as Derivatives (Tables)

9 Months Ended

Sep. 30, 2011

Balance Sheet Location and Fair Values of Forward Contracts for the Purchase and Sale of Electricity

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 September 30, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to September 30, 2011:

(in thousands)	September 30, 2011			December 31, 2010
Other Current Assets – Marked-to-Market Gain	$	3,929		$	6,875
Regulatory Assets – Deferred Marked-to-Market Loss		13,560			12,054
Total Assets		17,489			18,929
Derivative Liabilities – Marked-to-Market Loss		(16,390	)		(17,991	)
Regulatory Liabilities – Deferred Marked-to-Market Gain		(125	)		(175	)
Total Liabilities		(16,515	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	974		$	763

Change in the Company's Consolidated Balance Sheet Position on Forward Contracts for the Purchase and Sale of Electricity

(in thousands)	Year-to-Date September 30, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(225	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(28	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		(14	)
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(72	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		424
Changes in Fair Value of Contracts Entered into in 2011		550
Net Fair Value End of Period	$	974

Recognized but Unrealized Net Gains on the Forward Energy and Capacity Purchases and Sales Expected to be Realized on Settlement

The September 30, 2011 balance of recognized but unrealized net mark-to-market gains on the forward energy and capacity purchases and sales is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	4th Quarter 2011	2012	Total
Net Gain	$ 354	$ 620	$ 974

Realized and Unrealized Net (Losses)/Gains on Forward Energy Contracts Included in Electric Operating Revenues

The following realized and unrealized net gains on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(in thousands)	2011	2010	2011	2010
Net Gains on Forward Electric Energy Contracts	$  456	$  144	$  587	$1,945

Information on OTP's Credit Risk Exposure on Delivered and Marked-to-market Forward Contracts

The following table provides information on OTP’s credit risk exposure on delivered and marked-to-market forward contracts as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	792		5	$	1,129		4
Net Credit Risk to Single Largest Counterparty	$	372			$	585

Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in a Marked-to-market Loss Position

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2011 and December 31, 2010:

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2011			December 31, 2010
Loss Contracts Covered by Deposited Funds	$	2,551		$	427
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,803			10,904
Loss Contracts with No Ratings Triggers or Deposit Requirements		36			6,660
Total Current Liability – Marked-to-Market Loss	$	16,390		$	17,991
1   Certain 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.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,803		$	10,904
Offsetting Gains with Counterparties under Master Netting Agreements		(3,411	)		(6,219	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,392		$	4,685

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Pension Plan and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2011

Pension Plan and Other Postretirement Benefits

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 September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	961		$	997		$	3,311		$	3,491
Interest Cost on Projected Benefit Obligation		3,150			2,990			9,500			9,050
Expected Return on Assets		(3,530	)		(3,483	)		(10,605	)		(10,283	)
Amortization of Prior-Service Cost		125			172			325			512
Amortization of Net Actuarial Loss		663			511			1,963			1,501
Net Periodic Pension Cost	$	1,369		$	1,187		$	4,494		$	4,271

The Company did not make a contribution to its pension plan in the nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Service Cost—Benefit Earned During the Period	$	20	$	165	$	61	$	495
Interest Cost on Projected Benefit Obligation		407		417		1,223		1,253
Amortization of Prior-Service Cost		18		19		55		55
Amortization of Net Actuarial Loss		62		120		184		358
Net Periodic Pension Cost	$	507	$	721	$	1,523	$	2,161

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 September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	425		$	375		$	1,275		$	1,225
Interest Cost on Projected Benefit Obligation		850			855			2,550			2,405
Amortization of Transition Obligation		187			187			561			561
Amortization of Prior-Service Cost		50			58			150			158
Amortization of Net Actuarial Loss		213			248			639			624
Effect of Medicare Part D Expected Subsidy		(525	)		(558	)		(1,575	)		(1,558	)
Net Periodic Postretirement Benefit Cost	$	1,200		$	1,165		$	3,600		$	3,415

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Segment Information

9 Months Ended

Sep. 30, 2011

Segment Information

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 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. One customer of DMI has accounted for 11.2% of the Company’s consolidated revenues in the first nine months of 2011. 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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
United States of America		98.2	%		98.9	%		98.2	%		98.2	%
Canada		1.3	%		0.9	%		1.5	%		1.6	%
All Other Countries		0.5	%		0.2	%		0.3	%		0.2	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for three and nine month periods ended September 30, 2011 and 2010 and total assets by business segment as of September 30, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	85,172		$	89,315		$	254,799		$	258,294
Wind Energy		65,007			40,389			187,534			134,764
Manufacturing		55,815			43,342			170,486			130,880
Construction		53,247			36,885			139,895			84,808
Plastics		36,231			26,736			99,082			76,562
Health Services		21,853			24,300			67,331			73,116
Corporate Revenues and Intersegment Eliminations		(1,567	)		(1,221	)		(5,036	)		(4,415	)
Total	$	315,758		$	259,746		$	914,091		$	754,009

Interest Charges

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Electric	$	4,796		$	5,172	$	14,874		$	15,791
Wind Energy		1,925			1,641		5,806			4,511
Manufacturing		1,323			1,298		3,984			3,839
Construction		251			190		698			463
Plastics		411			403		1,176			1,194
Health Services		451			377		1,295			902
Corporate and Intersegment Eliminations		(449	)		206		(487	)		1,007
Total	$	8,708		$	9,287	$	27,346		$	27,707

Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	3,364		$	4,257		$	5,972		$	8,562
Wind Energy		(863	)		(3,529	)		(4,676	)		(5,053	)
Manufacturing		591			(349	)		3,650			(4,800	)
Construction		(115	)		435			(195	)		(872	)
Plastics		1,295			238			3,198			873
Health Services		115			311			863			(66	)
Corporate		(2,278	)		(1,970	)		(4,618	)		(5,269	)
Total	$	2,109		$	(607	)	$	4,194		$	(6,625	)

Earnings Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Electric	$	10,900		$	12,265		$	29,428		$	24,188
Wind Energy		(3,497	)		(7,120	)		(16,443	)		(9,755	)
Manufacturing		1,083			(383	)		6,071			(16,234	)
Construction		(179	)		645			(320	)		(1,337	)
Plastics		1,970			367			4,908			1,380
Health Services		125			421			1,155			(235	)
Corporate		(3,712	)		(2,319	)		(6,845	)		(7,313	)
Discontinued Operations		(506	)		2,038			12,064			5,256
Total	$	6,184		$	5,914		$	30,018		$	(4,050	)

Total Assets

	September 30,		December 31,
(in thousands)	2011		2010
Electric	$	1,101,146	$	1,106,261
Wind Energy		169,138		172,753
Manufacturing		152,693		144,272
Construction		74,639		60,978
Plastics		84,463		73,508
Health Services		72,566		75,898
Corporate		57,262		43,102
Discontinued Operations		77		93,783
Total	$	1,711,984	$	1,770,555

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Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Uncompleted Contracts [Line Items]
Costs Incurred on Uncompleted Contracts	$ 525,259	$ 460,125
Less Billings to Date	(507,751)	(430,471)
Plus Estimated Earnings Recognized	26,756	31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$ 44,264	$ 60,885

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies

9.  Commitments and Contingencies

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

In the first quarter of 2011, OTP entered into additional energy purchase agreements increasing its commitments for capacity and energy requirements. Amounts of commitments for OTP’s capacity and energy requirements under agreements extending through 2032 were as follows:

Capacity and Energy Requirements (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	21,268	$	20,134	$	1,134
2012		25,025		21,637		3,388
2013		21,868		16,492		5,376
2014		24,701		15,388		9,313
2015		18,915		12,307		6,608
Beyond 2015		78,879		78,879		--
Total	$	190,656	$	164,837	$	25,819

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. In the first half of 2011, OTP extended its contract for the purchase of coal for Hoot Lake Plant resulting in an increase in minimum purchase commitments. OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP is now committed to the minimum purchase, dating from January 1, 2011, or to make payments in lieu thereof in the following amounts:

Coal and Freight Purchase Commitments (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	52,819	$	47,122	$	5,697
2012		48,444		34,958		13,486
2013		9,855		9,855		--
2014		9,854		9,854		--
2015		9,854		9,854		--
Beyond 2015		4,106		4,106		--
Total	$	134,932	$	115,749	$	19,183

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 September 30, 2011 will not be material.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood that a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to product warranty, environmental remediation, litigation matters, possible liquidated damages and the resolution of matters related to open tax years. Should any of these items result in a liability being incurred, the range of loss could be as high as $9.0 million. Additionally, we may become subject to significant claims of which we are unaware, or the claims of which we are aware may result in our incurring a significantly greater liability than we anticipate.

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Income Tax Expense (Benefit) - Continuing Operations

9 Months Ended

Sep. 30, 2011

Income Tax Expense (Benefit) - Continuing Operations

15. Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Income (Loss) Before Income Taxes – Continuing Operations	$	8,983		$	3,454		$	22,700		$	(15,379	)
Income Tax Expense (Benefit) – Continuing Operations		2,109			(607	)		4,194			(6,625	)
Effective Income Tax Rate – Continuing Operations		23.5	%		(17.6	)%		18.5	%		43.1	%

The increase in Income Tax Expense (Benefit) - Continuing Operations for the three months ended September 30, 2011 compared with the three months ended September 30, 2010 is mainly due to the increase in income before income taxes between the quarters, but also due to DMI deferring recognition of tax benefits in the third 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 $0.5 million in the third quarter of 2011. The Company’s effective income tax rates for the three months ended September 30, 2011 and 2010 were decreased as a result of recording $1.4 million and $1.6 million, respectively, in federal production tax credits (PTCs) earned on kilowatt-hours (kwhs) generated from tax credit qualified wind turbines owned by OTP.

The increase in Income Tax Expense (Benefit) - Continuing Operations for the nine months ended September 30, 2011 compared with the nine months ended September 30, 2010 is mainly due to the increase in income before income taxes between the periods.  Also, only $2.8 million of ShoreMaster’s $12.2 million second quarter 2010 goodwill impairment loss was deductible for income taxes and DMI is deferring recognition of tax benefits in the first nine months of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s 2011 deferred tax benefits totaled $2.4 million through September 30, 2011. The Company’s effective income tax rates for the nine months ended September 30, 2011 and 2010 were decreased as a result of recording $5.3 million and $4.7 million, respectively, in federal PTCs earned on kwhs generated from tax credit qualified wind turbines owned by OTP.

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Breakdown of the Assignment of the Company's Consolidated Short-Term and Long-Term Debt Outstanding (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Short-Term Debt	$ 39,075	$ 79,490
Long-Term Debt	436,744	435,421
Current Maturities	3,286	604
Unamortized Debt Discount	4	5
Total Long-Term Debt	433,454	434,812
Total Short-Term and Long-Term Debt (with current maturities)	475,815	514,906
Otter Tail Power Company
Short-Term Debt	19,010	25,314
Long-Term Debt	280,595	280,715
Total Long-Term Debt	280,595	280,715
Total Short-Term and Long-Term Debt (with current maturities)	299,605	306,029
Otter Tail Power Company | Senior Unsecured Notes 6.63%, due December 1, 2011
Long-Term Debt	90,000	90,000
Otter Tail Power Company | Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012
Long-Term Debt	10,400	10,400
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Long-Term Debt	33,000	33,000
Otter Tail Power Company | Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
Long-Term Debt	5,090	5,100
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Long-Term Debt	30,000	30,000
Otter Tail Power Company | Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
Long-Term Debt	20,105	20,215
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Long-Term Debt	42,000	42,000
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Long-Term Debt	50,000	50,000
Varistar Corporation
Short-Term Debt	65
Long-Term Debt	4,220	4,706
Current Maturities	3,124	604
Total Long-Term Debt	1,096	4,102
Total Short-Term and Long-Term Debt (with current maturities)	4,285	4,706
Varistar Corporation | Other Obligations - Various up to 13.31%
Long-Term Debt	4,220	4,706
Otter Tail Corporation
Short-Term Debt	20,000	54,176
Long-Term Debt	151,929	150,000
Current Maturities	162
Unamortized Debt Discount	4	5
Total Long-Term Debt	151,763	149,995
Total Short-Term and Long-Term Debt (with current maturities)	171,925	204,171
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Long-Term Debt	100,000	100,000
Otter Tail Corporation | Senior Unsecured Note 8.89%, due November 30, 2017
Long-Term Debt	50,000	50,000
Otter Tail Corporation | Other Obligations - Various up to 13.31%
Long-Term Debt	1,929
Senior Unsecured Notes 6.63%, due December 1, 2011
Long-Term Debt	90,000	90,000
Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012
Long-Term Debt	10,400	10,400
9.000% Notes, due December 15, 2016
Long-Term Debt	100,000	100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Long-Term Debt	33,000	33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
Long-Term Debt	5,090	5,100
Senior Unsecured Note 8.89%, due November 30, 2017
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Long-Term Debt	30,000	30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
Long-Term Debt	20,105	20,215
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Long-Term Debt	50,000	50,000
Other Obligations - Various up to 13.31%
Long-Term Debt	$ 6,149	$ 4,706

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Short-Term and Long-Term Borrowings

9 Months Ended

Sep. 30, 2011

Short-Term and Long-Term Borrowings

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on September 30, 2011		Restricted due to Outstanding Letters of Credit		Available on September 30, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	20,000	$	1,374	$	178,626	$	144,350
OTP Credit Agreement		170,000		19,010		1,050		149,940		144,436
Total	$	370,000	$	39,010	$	2,424	$	328,566	$	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 at Northern Pipe Products, Inc. (NPP), 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. On April 6, 2011 Otter Tail Corporation borrowed $0.5 million under a North Dakota Development Fund loan to finance additional capital investments at NPP. The seven-year unsecured note bears interest at 3.95% with monthly principal and interest payments through April 1, 2018.

On July 29, 2011, OTP entered into a Note Purchase Agreement with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers in a private placement transaction $140 million aggregate principal amount of OTP’s 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes).  The 2021 Notes are expected to be issued on December 1, 2011, subject to the satisfaction of certain customary conditions to closing.  OTP intends to use a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of OTP’s 6.63% Senior Notes due December 1, 2011 and $10.4 million aggregate principal amount of its pollution control refunding revenue bonds due December 1, 2012.  The remaining proceeds of the 2021 Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the 2021 Notes and for other general corporate purposes.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	19,010	$	65		$	20,000	$	39,075
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011	$	90,000						$	90,000
Pollution Control Refunding Revenue Bonds,   Variable, 1.50% at September 30, 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		20,105							20,105
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 September 30, 2011				$	4,220		1,929		6,149
Total	$	280,595		$	4,220	$	151,929	$	436,744
Less: Current Maturities		--			3,124		162		3,286
Unamortized Debt Discount		--			--		4		4
Total Long-Term Debt	$	280,595		$	1,096	$	151,763	$	433,454
Total Short-Term and Long-Term Debt (with current maturities)	$	299,605		$	4,285	$	171,925	$	475,815

December 31, 2010 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	25,314	$	--		$	54,176	$	79,490
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 December 31, 2010, due December 1, 2012		10,400							10,400
9.000% Notes, due December 15, 2016						$	100,000		100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000							33,000
Grant County, South Dakota Pollution Control    Refunding Revenue Bonds 4.65%, due September 1, 2017		5,100							5,100
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 December 31, 2010				$	4,706				4,706
Total	$	280,715		$	4,706	$	150,000	$	435,421
Less: Current Maturities		--			604		--		604
Unamortized Debt Discount		--			--		5		5
Total Long-Term Debt	$	280,715		$	4,102	$	149,995	$	434,812
Total Short-Term and Long-Term Debt (with current maturities)	$	306,029		$	4,706	$	204,171	$	514,906

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Income Tax Expense (Benefit) - Continuing Operations (Tables)

9 Months Ended

Sep. 30, 2011

Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate

Income Tax Expense (Benefit) – Continuing Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Income (Loss) Before Income Taxes – Continuing Operations	$	8,983		$	3,454		$	22,700		$	(15,379	)
Income Tax Expense (Benefit) – Continuing Operations		2,109			(607	)		4,194			(6,625	)
Effective Income Tax Rate – Continuing Operations		23.5	%		(17.6	)%		18.5	%		43.1	%

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Share-Based Payments

9 Months Ended

Sep. 30, 2011

Share-Based Payments

7.  Share-Based Payments

The Company has five share-based payment programs.

Stock Incentive Awards

On April 11, 2011 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors, executive officers and key employees under the 1999 Stock Incentive Plan, as amended:

Award	Shares/Units Granted		Grant-Date Fair Value per Share		Vesting
Restricted Stock Granted to Nonemployee Directors		24,000	$	22.51	25% per year through April 8, 2015
Restricted Stock Granted to Executive Officers		24,600	$	22.51	25% per year through April 8, 2015
SStock Performance Awards Granted to Executive Officers		48,600	$	23.61	December 31, 2013
Restricted Stock Units Granted to Employees		19,800	$	18.03	100% on April 8, 2015

The restricted shares granted to the Company’s nonemployee directors and executive officers (which includes OTP’s president) are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was the average of the high and low market price per share on the date of grant.

Under the performance share 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 measurement 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 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.

The grant date fair value of each restricted stock unit was based on the market value of one share of the Company’s common stock on the grant date, discounted for the value of the dividend exclusion over the four-year vesting period.

As of September 30, 2011 the remaining unrecognized compensation expense related to stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.6 years.

Compensation expense recognized under the Company’s stock-based payment programs:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011		2010			2011		2010
Employee Stock Purchase Plan (15% discount)	$	51	$	64		$	185	$	205
Restricted Stock Granted to Directors		185		148			571		446
Restricted Stock Granted to Employees		511		239			759		519
Stock Performance Awards Granted to Executive Officers		1,766		722			1,766		879
Restricted Stock Units Granted to Employees		92		(20	)		244		137
Totals	$	2,605	$	1,153		$	3,525	$	2,186

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Percentage of Consolidated Sales Revenue by Country (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
United States of America
Percentage of sales revenue	98.20%	98.90%	98.20%	98.20%
Canada
Percentage of sales revenue	1.30%	0.90%	1.50%	1.60%
All Other Countries
Percentage of sales revenue	0.50%	0.20%	0.30%	0.20%

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Consolidated Statements of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash Flows from Operating Activities
Net Income (Loss)	$ 30,892	$ (3,400)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations	(12,798)
Net Loss (Income) from Discontinued Operations	412	(5,354)
Depreciation and Amortization	58,748	56,404
Asset Impairment Charge		19,740
Deferred Tax Credits	(1,834)	(2,037)
Deferred Income Taxes	10,144	17,373
Change in Deferred Debits and Other Assets	11,844	(1,298)
Discretionary Contribution to Pension Fund		(20,000)
Change in Noncurrent Liabilities and Deferred Credits	1,742	5,534
Allowance for Equity (Other) Funds Used During Construction	(576)	(8)
Change in Derivatives Net of Regulatory Deferral	(177)	202
Stock Compensation Expense - Equity Awards	1,760	1,973
Other-Net	(301)	(444)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(25,251)	(47,442)
Change in Inventories	(11,845)	87
Change in Other Current Assets	11,038	4,586
Change in Payables and Other Current Liabilities	3,463	1,103
Change in Interest Payable and Income Taxes Receivable/Payable	764	29,886
Net Cash Provided by Continuing Operations	78,025	56,905
Net Cash Provided by Discontinued Operations	2,347	3,970
Net Cash Provided by Operating Activities	80,372	60,875
Cash Flows from Investing Activities
Capital Expenditures	(71,337)	(61,382)
Proceeds from Disposal of Noncurrent Assets	3,055	2,709
Net Decrease (Increase) in Other Investments	234	(1,669)
Net Cash Used in Investing Activities - Continuing Operations	(68,048)	(60,342)
Net Proceeds from Sale of Discontinued Operations	84,330
Net Cash Used in Investing Activities - Discontinued Operations	(6,065)	(1,485)
Net Cash Provided by (Used in) Investing Activities	10,217	(61,827)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(10,031)	4,528
Net Short-Term Borrowings	(40,415)	86,388
Proceeds from Issuance of Common Stock		549
Proceeds from Issuance of Class B Stock of Subsidiary		158
Common Stock Issuance Expenses		(142)
Payments for Retirement of Common Stock	(152)	(401)
Payments for Retirement of Class B Stock of Subsidiary		(1,017)
Proceeds from Issuance of Long-Term Debt	2,007	95
Short-Term and Long-Term Debt Issuance Expenses	(1,577)	(1,699)
Payments for Retirement of Long-Term Debt	(683)	(59,166)
Dividends Paid and Other Distributions	(33,011)	(32,824)
Net Cash Used in Financing Activities - Continuing Operations	(83,862)	(3,531)
Net Cash Provided by Financing Activities - Discontinued Operations	201	256
Net Cash Used in Financing Activities	(83,661)	(3,275)
Cash and Cash Equivalents at Beginning of Period - Discontinued Operations		(609)
Effect of Foreign Exchange Rate Fluctuations on Cash - Discontinued Operations	(324)	(205)
Net Change in Cash and Cash Equivalents	6,604	(5,041)
Cash and Cash Equivalents at Beginning of Period		5,041
Cash and Cash Equivalents at End of Period	$ 6,604

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Pro forma Summary Presentations of the Company's Consolidated Income Statements Reflecting the Classification of IPH's Results as Discontinued Operations (Detail) (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010 As Previously Reported	Dec. 31, 2009 As Previously Reported	Dec. 31, 2010 IPH		Dec. 31, 2009 IPH		Dec. 31, 2010 With IPH classified as Discontinued Operations	Dec. 31, 2009 With IPH classified as Discontinued Operations
Operating Revenues	$ 315,758	$ 259,746	$ 914,091	$ 754,009	$ 1,119,084	$ 1,039,512	$ 77,202	[1]	$ 78,632	[1]	$ 1,041,882	$ 960,880
Operating Expenses:
Cost of Goods Sold	184,964	138,403	534,503	392,899	600,956	565,192	56,619	[1]	58,718	[1]	544,337	506,474
Other Operating Expenses					402,919	355,322	3,729	[1]	3,330	[1]	399,190	351,992
Depreciation Expense	19,937	19,175	58,748	56,404	80,696	73,608	4,703	[1]	4,333	[1]	75,993	69,275
Total Operating Expenses	298,556	247,709	866,362	742,950	1,084,571	994,122	65,051	[1]	66,381	[1]	1,019,520	927,741
Operating Income	17,202	12,037	47,729	11,059	34,513	45,390	12,151	[1]	12,251	[1]	22,362	33,139
Other Income (Deductions)	489	704	2,317	1,269	5,126	4,550	(408)	[1]	(404)	[1]	5,534	4,954
Interest Charges	8,708	9,287	27,346	27,707	37,032	28,514	29	[1]	30	[1]	37,003	28,484
Income Tax Expense (Benefit)	2,109	(607)	4,194	(6,625)	3,951	(4,605)	3,716	[1]	4,410	[1]	235	(9,015)
Net Income (Loss) from Continuing Operations	6,874	4,061	18,506	(8,754)	(1,344)	26,031	7,998	[1]	7,407	[1]	(9,342)	18,624
Net Income - Discontinued Operations	(506)	2,040	12,386	5,354							7,998	7,407
Total Net Income (Loss)	6,368	6,101	30,892	(3,400)	(1,344)	26,031	7,998	[1]	7,407	[1]	(1,344)	26,031
Preferred Dividend Requirements					833	736					833	736
Earnings Available for Common Shares	$ 6,184	$ 5,914	$ 30,018	$ (4,050)	$ (2,177)	$ 25,295	$ 7,998	[1]	$ 7,407	[1]	$ (2,177)	$ 25,295
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$ 0.18	$ 0.11	$ 0.50	$ (0.26)	$ (0.06)	$ 0.71	$ 0.22	[1]	$ 0.21	[1]	$ (0.28)	$ 0.50
Discontinued Operations	$ (0.01)	$ 0.06	$ 0.34	$ 0.15							$ 0.22	$ 0.21
Earnings Per Share, Basic	$ 0.17	$ 0.17	$ 0.84	$ (0.11)							$ (0.06)	$ 0.71
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)	$ 0.18	$ 0.11	$ 0.50	$ (0.26)	$ (0.06)	$ 0.71	$ 0.22	[1]	$ 0.21	[1]	$ (0.28)	$ 0.50
Discontinued Operations	$ (0.01)	$ 0.05	$ 0.33	$ 0.15							$ 0.22	$ 0.21
Earnings Per Share, Diluted	$ 0.17	$ 0.16	$ 0.83	$ (0.11)							$ (0.06)	$ 0.71

[1] Includes reinstatement of intercompany eliminations related to intercompany transactions with IPH.

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Rate and Regulatory Matters

9 Months Ended

Sep. 30, 2011

Rate and Regulatory Matters

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% base rate increase as well as a 3.8% interim rate increase.On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates, and approving the interim rate increase, as requested, 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. The MPUC authorized a revenue increase of approximately $5.0 million, or 3.76% in base rate revenues, excluding the effect of moving recovery of wind investments to base rates. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years (see discussion below), (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of MNCIP costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota fuel clause adjustment (FCA). Final rates went into effect October 1, 2011. The overall increase to customers will be approximately 1.6% compared to the authorized interim rate increase of 3.8%,which resulted in an interim rate refund of approximately $3.9 million. As of September 30, 2011, OTP had recognized a $3.9 million refund liability for revenue billed under interim rates from June 1, 2010 through September 30, 2011. On October 31, 2011 OTP issued the interim rate refund, including interest, to Minnesota customers. 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 has a regulatory asset of $3.5 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 September 30, 2011. The recovery of MNRRA costs was moved to base rates as of October 1, 2011 under the MPUC’s April 25, 2011 general rate case order with the exception of the remaining balance of this regulatory asset.

In its April 25, 2011 general rate case order, 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. Final rates went into effect on October 1, 2011. The Company will continue to utilize the rider cost recovery mechanism until the remaining balance of the current transmission projects has been collected as well as to recover costs associated with approved regional projects. OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. Comments and reply comments have been filed but the MPUC has not yet scheduled a hearing on the request.

Conservation Improvement Program—OTP has a regulatory asset of $7.2 million for allowable costs and financial incentives that are eligible for recovery through the MNCIP rider that have not been billed to Minnesota customers as of  September 30, 2011. OTP has recognized $3.7 million in financial incentives relating to 2010. A final decision regarding the 2010 MNCIP financial incentive is expected in December 2011. OTP currently has $1.3 million of income recognized relating to the 2011 MNCIP financial incentive. 

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. The request is under review by the NDPSC.

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 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. On April 21, 2011, the SDPUC issued its written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50 percent for the interim rates and final rates. Final rates were effective with bills rendered on and after June 1, 2011.

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 has been assigned to an SDPUC outside consultant and likely will not  be on an SDPUC agenda until later this year.

Capacity Expansion 2020 (CapX2020)

CapX2020 is a joint initiative of 11 investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kiloVolt (kV) Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji – Grand Rapids Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project.

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

The Fargo Project—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 Fargo Project, was accepted by the Federal Energy Regulatory Commission (FERC) in the third quarter of 2010. The Monticello to St. Cloud portion of the Fargo Project is scheduled for completion in December 2011.

The Minnesota route permit application for the St. Cloud to Fargo portion of the Fargo Project was filed on October 1, 2009. Minnesota State Environmental Impact Statement (EIS) scoping meetings were held in September 2010 and public hearings were held in November 2010. The MPUC approved the route permit on June 24, 2011. The agreements for Phase 2, which consists of the line section between St. Cloud and Alexandria, Minnesota were signed by all of the participants on August 3, 2011. Easement acquisition discussions with landowners are underway. Construction is expected to begin in November 2011.

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 Project. The NDPSC approved the CPCN in January 2011. The application for the North Dakota Certificate of Corridor Compatibility (CCC) was filed on December 30, 2010 and was revised in March 2011. The June 23, 2011 hearing for the North Dakota CCC application was postponed. A combined North Dakota CCC and route permit application was submitted to the NDPSC on October 3, 2011.

The Brookings Project—The Minnesota route permit application for the Brookings Project was filed in the fourth quarter of 2008. The MPUC approved the final line segment route permit for the Brookings 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 the South Dakota route permit was approved in June 2011. The MISO board of directors granted conditional approval of the Multi-Value Project (MVP) cost allocation designation under the MISO Tariff for the Brookings Project. Once the MISO board finalizes its analysis of all of the MVP projects in its study portfolio, the MISO board will be in a position to remove the condition, which is anticipated to occur in December 2011. Easement acquisition discussions with landowners are underway.

The Bemidji Project—OTP serves as the lead utility for the Bemidji Project, which has an expected in-service date in late 2012. 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 and approved on October 28, 2010.  The joint state and federal EIS was published by 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 the 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 Leech Lake Reservation. The owners of the Bemidji Project, including OTP, filed reply comments in opposition to the LLBO’s request. On April 25, 2011, the Bemidji Project owners filed a declaratory judgment in the U.S. District Court for Minnesota against the LLBO seeking that no consent from the LLBO is required for the project to run through the LLBO reservation boundaries since the project is located exclusively on non LLBO lands. On June 22, 2011, Federal District Judge Frank issued a preliminary injunction which ordered the LLBO to cease and desist from pursuing its claims of jurisdiction over the project in tribal court or the MPUC or from taking any other actions to interfere with the routing or construction of the project. The parties had engaged in court supervised mediation; however, no agreement was reached. The preliminary injunction remains in place prohibiting the LLBO from interfering with project construction.

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: the Fargo Project, the Brookings Project and the Bemidji Project. 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 issued 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 Project and its associated impact on North Dakota. On April 29, 2011, OTP filed its compliance filing with the NDPSC, seeking a determination of continued prudence for OTP’s investment in the Brookings Project. The NDPSC hearing occurred on July 25, 2011. On August 23, 2011, an executed settlement agreement on continued prudence was filed and the hearing for consideration of the settlement agreement on continued prudence was held on October 26, 2011.  A final decision is expected later this year.

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 developed and submitted its implementation plan and associated implementation rules to the EPA on January 21, 2011. The DENR and EPA have agreed on non-substantive rule revisions, which were adopted by the Board of Minerals and Environment and became effective on September 19, 2011. South Dakota developed and submitted its revised implementation plan and associated implementation rules to EPA on September 19, 2011. Under the South Dakota implementation plan, and its implementing rules, 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 (ADP) 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. On June 1, 2011, the MPUC referred the matter to the Office of Administrative Hearings for contested case proceedings before an administrative law judge (ALJ). Evidentiary hearings took place on September 14 and 15, 2011 with an ALJ report and recommendation expected by November 9, 2011. A decision by the MPUC is expected in December. OTP filed an application for an ADP with the NDPSC on May 20, 2011 with a decision expected by December 20, 2011. North Dakota has hired a consulting firm to evaluate the ADP request. Evidentiary hearings are scheduled for November 29 and 30, 2011. 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 which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers was $3,199,000 (which excludes $3,246,000 of project transmission-related costs). 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 South Dakota portion of 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.

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Accounts Receivable Retained by Customers Pending Project Completion (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable Retained by Customers	$ 12,447	$ 11,848

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value of Financial Instruments

The Company’s long-term debt subject to variable interest rates approximates fair value.

	September 30, 2011						December 31, 2010
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Short-Term Investments	$	6,604		$	6,604		$	--		$	--
Long-Term Debt		(433,454	)		(479,567	)		(434,812	)		(474,307	)

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Change in the Company's Consolidated Balance Sheet Position on Forward Contracts for the Purchase and Sale of Electricity (Detail) (Forward Contracts, USD $) In Thousands			9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Contracts Entered into in 2009 and Settled in 2011	Sep. 30, 2011 Contracts Entered into in 2010 and Settled in 2011	Sep. 30, 2011 Contracts Entered into in 2009 in 2011	Sep. 30, 2011 Contracts Entered into in 2010 in 2011	Sep. 30, 2011 Contracts Entered into in 2009 and 2010	Sep. 30, 2011 Contracts Entered into in 2011
Derivatives, Fair Value [Line Items]
Fair Value at Beginning of Year	$ 974	$ 763					$ 424	$ 550
Net Fair Value End of Period	974	763					424	550
Amounts Realized			(225)	(28)
Changes in Fair Value					$ (14)	$ (72)

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Realized and Unrealized Net (Losses)/Gains on Forward Energy Contracts Included in Electric Operating Revenues (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Net Gains on Forward Electric Energy Contracts	$ 456	$ 144	$ 587	$ 1,945

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Segment Information - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2011
Segment Reporting Information [Line Items]
Percentage of revenue of one customer of DMI	11.20%

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Stock Options with Exercise Prices Greater than the Market Price Excluded from the Calculation of Diluted Earnings per Common Share (Detail) (Stock Options, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options Outstanding	170,960	383,460	170,960	383,460
Range of Exercise Prices, Lower Range	$ 24.93	$ 24.93	$ 24.93	$ 24.93
Range of Exercise Prices, Upper Range	$ 31.34	$ 31.34	$ 31.34	$ 31.34

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities

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:

	September 30,		December 31,		Remaining Recovery/
(in thousands)	2011		2010		Refund Period
Regulatory Assets – Current:
Accrued Cost-of-Energy Revenue	$	2,552	$	2,387	23 months
Regulatory Assets – Long Term:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	70,265	$	74,156	see notes
Deferred Marked-to-Market Losses		13,560		12,054	47 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		7,158		6,655	21 months
Minnesota Renewable Resource Rider Accrued Revenues		3,452		6,834	30 months
Big Stone II Unrecovered Project Costs – Minnesota		2,758		6,445	60 months
Debt Reacquisition Premiums		2,582		3,107	252 months
Accumulated ARO Accretion/Depreciation Adjustment		2,545		2,218	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		2,508		3,460	22 months
Deferred Income Taxes		2,025		5,785	asset lives
North Dakota Renewable Resource Rider Accrued Revenues		1,379		2,415	27 months
General Rate Case Recoverable Expenses		1,189		1,773	28 months
Big Stone II Unrecovered Project Costs – South Dakota		936		1,419	112 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		436		717	14 months
South Dakota – Asset-Based Margin Sharing Shortfall		257		501	5 months
Minnesota Transmission Rider Accrued Revenues		252		34	15 months
Deferred Holding Company Formation Costs		152		193	33 months
Total Regulatory Assets – Long Term	$	111,454	$	127,766
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	64,031	$	61,740	asset lives
Deferred Income Taxes		3,691		4,289	asset lives
Minnesota Transmission Rider Accrued Refund		1,081		--	see notes
Deferred Marked-to-Market Gains		125		175	35 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		124		128	267 months
South Dakota – Nonasset-Based Margin Sharing Excess		61		84	15 months
Total Regulatory Liabilities	$	69,113	$	66,416
Net Regulatory Asset Position	$	44,893	$	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 September 30, 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 September 30, 2011.

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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 252 months.

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

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.

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.

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 September 30, 2011.

General Rate Case Recoverable Expenses relate to expenses incurred during the rate case proceedings that are eligible for recovery.

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 September 30, 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.

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Components of Net Periodic Benefit Cost (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Funded Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	$ 961	$ 997	$ 3,311	$ 3,491
Interest Cost on Projected Benefit Obligation	3,150	2,990	9,500	9,050
Expected Return on Assets	(3,530)	(3,483)	(10,605)	(10,283)
Amortization of Prior-Service Cost	125	172	325	512
Amortization of Net Actuarial Loss	663	511	1,963	1,501
Net Periodic Cost	1,369	1,187	4,494	4,271
Unfunded Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	20	165	61	495
Interest Cost on Projected Benefit Obligation	407	417	1,223	1,253
Amortization of Prior-Service Cost	18	19	55	55
Amortization of Net Actuarial Loss	62	120	184	358
Net Periodic Cost	507	721	1,523	2,161
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	425	375	1,275	1,225
Interest Cost on Projected Benefit Obligation	850	855	2,550	2,405
Amortization of Transition Obligation	187	187	561	561
Amortization of Prior-Service Cost	50	58	150	158
Amortization of Net Actuarial Loss	213	248	639	624
Effect of Medicare Part D Expected Subsidy	(525)	(558)	(1,575)	(1,558)
Net Periodic Cost	$ 1,200	$ 1,165	$ 3,600	$ 3,415

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Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Inputs, Level 1
Assets:
Money Market and Mutual Funds and Cash	$ 513	$ 800
Corporate Debt Securities	9,172	8,467
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account	3,000
Total Assets	12,709	9,325
Fair Value, Inputs, Level 1 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets	24	58
Fair Value, Inputs, Level 2
Assets:
Regulatory Asset - Deferred Mark-to-Market Losses on Forward Energy Contracts	13,560	12,054
Total Assets	17,489	18,929
Liabilities:
Regulatory Liability - Deferred Mark-to-Market Gains on Forward Energy Contracts	125	175
Total Liabilities	16,515	18,166
Fair Value, Inputs, Level 2 | Forward Energy Contracts
Assets:
Derivative Assets	3,929	6,875
Liabilities:
Derivative Liabilities	$ 16,390	$ 17,991

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2011

Amounts of Commitments for OTP's Capacity and Energy Requirements

In the first quarter of 2011, OTP entered into additional energy purchase agreements increasing its commitments for capacity and energy requirements. Amounts of commitments for OTP’s capacity and energy requirements under agreements extending through 2032 were as follows:

Capacity and Energy Requirements (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	21,268	$	20,134	$	1,134
2012		25,025		21,637		3,388
2013		21,868		16,492		5,376
2014		24,701		15,388		9,313
2015		18,915		12,307		6,608
Beyond 2015		78,879		78,879		--
Total	$	190,656	$	164,837	$	25,819

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. In the first half of 2011, OTP extended its contract for the purchase of coal for Hoot Lake Plant resulting in an increase in minimum purchase commitments. OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP is now committed to the minimum purchase, dating from January 1, 2011, or to make payments in lieu thereof in the following amounts:

Coal and Freight Purchase Commitments (thousands)	September 30, 2011		December 31, 2010		Increase
2011	$	52,819	$	47,122	$	5,697
2012		48,444		34,958		13,486
2013		9,855		9,855		--
2014		9,854		9,854		--
2015		9,854		9,854		--
Beyond 2015		4,106		4,106		--
Total	$	134,932	$	115,749	$	19,183

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Stock Incentive Awards (Detail) (USD $)	9 Months Ended
	Sep. 30, 2011
Director | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	24,000
Grant-Date Fair Value per Share	$ 22.51
Vesting percentage	25.00%
Vesting date	Apr. 08, 2015
Executive Officer | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	24,600
Grant-Date Fair Value per Share	$ 22.51
Vesting percentage	25.00%
Vesting date	Apr. 08, 2015
Executive Officer | Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	48,600
Grant-Date Fair Value per Share	$ 23.61
Vesting date	Dec. 31, 2013
Employee | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	19,800
Grant-Date Fair Value per Share	$ 18.03
Vesting percentage	100.00%
Vesting date	Apr. 08, 2015

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Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Taxes [Line Items]
Income (Loss) Before Income Taxes - Continuing Operations	$ 8,983	$ 3,454	$ 22,700	$ (15,379)
Income Tax Expense (Benefit) - Continuing Operations	$ 2,109	$ (607)	$ 4,194	$ (6,625)
Effective Income Tax Rate - Continuing Operations	23.50%	(17.60%)	18.50%	43.10%

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Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in a Marked-to-market Loss Position (Detail) (USD $) In Thousands	Sep. 30, 2011		Dec. 31, 2010
Current Liability - Marked-to-Market Loss
Loss Contracts Covered by Deposited Funds	$ 2,551		$ 427
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	13,803	[1]	10,904	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements	36		6,660
Total Current Liability - Marked-to-Market Loss	16,390		17,991
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	13,803	[1]	10,904	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	(3,411)		(6,219)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$ 10,392		$ 4,685

[1] Certain 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.

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2011

Results of Discontinued Operations

Following are summary presentations of the results of discontinued operations for the three and nine month periods ended September 30, 2011 and 2010 and of the major components of assets and liabilities of discontinued operations as of September 30, 2011 and December 31, 2010:

	Three Months Ended
	September 30, 2011									September 30, 2010
(in thousands)	IPH			Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	--		$	--		$	--		$	19,478	$	2,046	$	21,524
Income (Loss) Before Income Taxes	$	--		$	(86	)	$	(86	)	$	3,183	$	82	$	3,265
Gain (Loss) on Disposition - Pretax		(756	)		--			(756	)		--		--		--
Income Tax Expense (Benefit)		(302	)		(34	)		(336	)		1,192		33		1,225
Net Income (Loss)	$	(454	)	$	(52	)	$	(506	)	$	1,991	$	49	$	2,040

	Nine Months Ended
	September 30, 2011								September 30, 2010
(in thousands)	IPH		Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	28,125	$	5,448		$	33,573		$	56,648	$	4,700	$	61,348
Income (Loss) Before Income Taxes	$	3,840	$	(4,650	)	$	(810	)	$	8,306	$	129	$	8,435
Gain on Disposition - Pretax		16,011		--			16,011			--		--		--
Income Tax Expense (Benefit)		4,675		(1,860	)		2,815			3,029		52		3,081
Net Income (Loss)	$	15,176	$	(2,790	)	$	12,386		$	5,277	$	77	$	5,354

Major Components of Assets and Liabilities of Discontinued Operations

	September 30, 2011				December 31, 2010
(in thousands)	Wylie-Wind		Total		IPH		Wylie-Wind		Total
Current Assets	$	2	$	2	$	24,836	$	2,461	$	27,297
Goodwill		--		--		24,324		--		24,324
Other Intangibles - Net		--		--		10,852		--		10,852
Net Plant		75		75		30,672		638		31,310
Assets of Discontinued Operations	$	77	$	77	$	90,684	$	3,099	$	93,783
Current Liabilities	$	77	$	77	$	6,839	$	4,150	$	10,989
Deferred Income Taxes		--		--		11,553		--		11,553
Long-Term Debt		--		--		634		--		634
Liabilities of Discontinued Operations	$	77	$	77	$	19,026	$	4,150	$	23,176

Pro forma Summary Presentations of the Company's Consolidated Income Statements Reflecting the Classification of IPH's Results as Discontinued

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 (Loss)	(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.

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Amounts of Accounts Receivable Sold and Discounts, Fees and Commissions Paid (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Receivables [Line Items]
Accounts Receivable Sold	$ 20,662	$ 14,800	$ 48,802	$ 44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable	$ 153	$ 45	$ 406	$ 152

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Pension Plan and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Funded Defined Benefit Pension Plans

Components of Net Periodic Benefit Cost

Pension Plan—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	961		$	997		$	3,311		$	3,491
Interest Cost on Projected Benefit Obligation		3,150			2,990			9,500			9,050
Expected Return on Assets		(3,530	)		(3,483	)		(10,605	)		(10,283	)
Amortization of Prior-Service Cost		125			172			325			512
Amortization of Net Actuarial Loss		663			511			1,963			1,501
Net Periodic Pension Cost	$	1,369		$	1,187		$	4,494		$	4,271

Unfunded Defined Benefit Pension Plans

Components of Net Periodic Benefit Cost

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 September 30,				Nine Months Ended September 30,
(in thousands)	2011		2010		2011		2010
Service Cost—Benefit Earned During the Period	$	20	$	165	$	61	$	495
Interest Cost on Projected Benefit Obligation		407		417		1,223		1,253
Amortization of Prior-Service Cost		18		19		55		55
Amortization of Net Actuarial Loss		62		120		184		358
Net Periodic Pension Cost	$	507	$	721	$	1,523	$	2,161

Other Postretirement Benefit Plans, Defined Benefit

Components of Net Periodic Benefit Cost

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 September 30,						Nine Months Ended September 30,
(in thousands)	2011			2010			2011			2010
Service Cost—Benefit Earned During the Period	$	425		$	375		$	1,275		$	1,225
Interest Cost on Projected Benefit Obligation		850			855			2,550			2,405
Amortization of Transition Obligation		187			187			561			561
Amortization of Prior-Service Cost		50			58			150			158
Amortization of Net Actuarial Loss		213			248			639			624
Effect of Medicare Part D Expected Subsidy		(525	)		(558	)		(1,575	)		(1,558	)
Net Periodic Postretirement Benefit Cost	$	1,200		$	1,165		$	3,600		$	3,415

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2011

Fair Value of Financial Instruments

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.

	September 30, 2011						December 31, 2010
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Short-Term Investments	$	6,604		$	6,604		$	--		$	--
Long-Term Debt		(433,454	)		(479,567	)		(434,812	)		(474,307	)

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Regulatory Assets and Liabilities - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2011
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	252 months
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Share of actual profit margins on nonasset-based wholesale sales of electricity	25.00%

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Results of Discontinued Operations (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		$ 21,524	$ 33,573	$ 61,348
Income (Loss) Before Income Taxes	(86)	3,265	(810)	8,435
Gain (Loss) on Disposition - Pretax	(756)		16,011
Income Tax Expense (Benefit)	(336)	1,225	2,815	3,081
Net Income (Loss) from Discontinued Operations	(506)	2,040	12,386	5,354
IPH
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		19,478	28,125	56,648
Income (Loss) Before Income Taxes		3,183	3,840	8,306
Gain (Loss) on Disposition - Pretax	(756)		16,011
Income Tax Expense (Benefit)	(302)	1,192	4,675	3,029
Net Income (Loss) from Discontinued Operations	(454)	1,991	15,176	5,277
Wylie-Wind
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		2,046	5,448	4,700
Income (Loss) Before Income Taxes	(86)	82	(4,650)	129
Income Tax Expense (Benefit)	(34)	33	(1,860)	52
Net Income (Loss) from Discontinued Operations	$ (52)	$ 49	$ (2,790)	$ 77

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Breakdown of the Assignment of the Company's Consolidated Short-Term and Long-Term Debt Outstanding (Parenthetical) (Detail)		1 Months Ended	9 Months Ended	12 Months Ended	1 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended
	Mar. 18, 2011	Jul. 29, 2011 Senior Unsecured Notes 6.63%, due December 1, 2011	Sep. 30, 2011 Senior Unsecured Notes 6.63%, due December 1, 2011	Dec. 31, 2010 Senior Unsecured Notes 6.63%, due December 1, 2011	Jul. 29, 2011 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012	Sep. 30, 2011 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012	Dec. 31, 2010 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012	Sep. 30, 2011 9.000% Notes, due December 15, 2016	Dec. 31, 2010 9.000% Notes, due December 15, 2016	Sep. 30, 2011 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	Dec. 31, 2010 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	Sep. 30, 2011 Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	Dec. 31, 2010 Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	Sep. 30, 2011 Senior Unsecured Note 8.89%, due November 30, 2017	Dec. 31, 2010 Senior Unsecured Note 8.89%, due November 30, 2017	Sep. 30, 2011 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022	Dec. 31, 2010 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022	Sep. 30, 2011 Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	Dec. 31, 2010 Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	Sep. 30, 2011 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027	Dec. 31, 2010 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027	Sep. 30, 2011 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037	Dec. 31, 2010 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037	Sep. 30, 2011 Other Obligations - Various up to 13.31%	Dec. 31, 2010 Other Obligations - Various up to 13.31%
Long-Term Debt, Interest Rate	2.54%	6.63%	6.63%	6.63%		1.50%	2.50%	9.00%	9.00%	5.95%	5.95%	4.65%	4.65%	8.89%	8.89%	6.15%	6.15%	4.85%	4.85%	6.37%	6.37%	6.47%	6.47%	13.31%	13.31%
Long-Term Debt, Due Date		Dec. 01, 2011	Dec. 01, 2011	Dec. 01, 2011	Dec. 01, 2012	Dec. 01, 2012	Dec. 01, 2012	Dec. 15, 2016	Dec. 15, 2016	Aug. 20, 2017	Aug. 20, 2017	Sep. 01, 2017	Sep. 01, 2017	Nov. 30, 2017	Nov. 30, 2017	Aug. 20, 2022	Aug. 20, 2022	Sep. 01, 2022	Sep. 01, 2022	Aug. 20, 2027	Aug. 20, 2027	Aug. 20, 2037	Aug. 20, 2037

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Information on OTP's Credit Risk Exposure on Delivered and Marked-to-market Forward Contracts (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2011 Entity	Dec. 31, 2010 Entity
Forward Energy Contracts
Derivative [Line Items]
Exposure	$ 792	$ 1,129
Counterparties	5	4
Net Credit Risk to Single Largest Counterparty
Derivative [Line Items]
Exposure	$ 372	$ 585

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Forward Contracts Classified as Derivatives

9 Months Ended

Sep. 30, 2011

Forward Contracts Classified as Derivatives

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.

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.

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 September 30, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to September 30, 2011:

(in thousands)	September 30, 2011			December 31, 2010
Other Current Assets – Marked-to-Market Gain	$	3,929		$	6,875
Regulatory Assets – Deferred Marked-to-Market Loss		13,560			12,054
Total Assets		17,489			18,929
Derivative Liabilities – Marked-to-Market Loss		(16,390	)		(17,991	)
Regulatory Liabilities – Deferred Marked-to-Market Gain		(125	)		(175	)
Total Liabilities		(16,515	)		(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts	$	974		$	763

(in thousands)	Year-to-Date September 30, 2011
Fair Value at Beginning of Year	$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011		(225	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011		(28	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011		(14	)
Changes in Fair Value of Contracts Entered into in 2010 in 2011		(72	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period		424
Changes in Fair Value of Contracts Entered into in 2011		550
Net Fair Value End of Period	$	974

The September 30, 2011 balance of recognized but unrealized net mark-to-market gains on the forward energy and capacity purchases and sales is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	4th Quarter 2011	2012	Total
Net Gain	$ 354	$ 620	$ 974

The following realized and unrealized net gains on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(in thousands)	2011	2010	2011	2010
Net Gains on Forward Electric Energy Contracts	$  456	$  144	$  587	$1,945

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.

The following table provides information on OTP’s credit risk exposure on delivered and marked-to-market forward contracts as of September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	792		5	$	1,129		4
Net Credit Risk to Single Largest Counterparty	$	372			$	585

OTP had no exposure at September 30, 2011 or December 31, 2010 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The credit risk exposures include 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 subsequent to the reporting date. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2011 and December 31, 2010:

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2011			December 31, 2010
Loss Contracts Covered by Deposited Funds	$	2,551		$	427
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,803			10,904
Loss Contracts with No Ratings Triggers or Deposit Requirements		36			6,660
Total Current Liability – Marked-to-Market Loss	$	16,390		$	17,991
1   Certain 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.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,803		$	10,904
Offsetting Gains with Counterparties under Master Netting Agreements		(3,411	)		(6,219	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,392		$	4,685

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Revenue Recognition

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 the Financial Accounting Standards Board Accounting Standards Codification (ASC). 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 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. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Percentage-of-Completion Revenues		34.9	%		26.3	%		33.5	%		26.5	%

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

	September 30,			December 31,
(in thousands)	2011			2010
Costs Incurred on Uncompleted Contracts	$	525,259		$	460,125
Less Billings to Date		(507,751	)		(430,471	)
Plus Estimated Earnings Recognized		26,756			31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	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:

	September 30,			December 31,
(in thousands)	2011			2010
Costs and Estimated Earnings in Excess of Billings	$	54,309		$	67,352
Billings in Excess of Costs and Estimated Earnings		(10,045	)		(6,467	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

Included in Costs and Estimated Earnings in Excess of Billings are the following amounts at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer:

	September 30,		December 31,
(in thousands)	2011		2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	38,843	$	58,990

These amounts are 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.

Warranty Reserves

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures.

(in thousands)
Warranty Reserve Balance, December 31, 2010	$	2,676
Provision for Warranties Used During the Year		845
Less Settlements Made During the Year		991
Increase in Warranty Estimates for Prior Years		145
Warranty Reserve Balance, September 30, 2011	$	2,675

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 the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Retainage

Accounts Receivable include the following amounts, billed under contracts by the Company’s subsidiaries, that have been retained by customers pending project completion:

	September 30,		December 31,
(in thousands)	2011		2010
Accounts Receivable Retained by Customers	$	12,447	$	11,848

Sales of Receivables

Sales of Receivables

DMI is a party to a $40 million receivables sales agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement is subject to renewal in March 2012. The current discount rate is 3-month LIBOR plus 4%. 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. Following are the amounts of accounts receivable sold and discounts, fees and commissions paid under DMI’s receivables sales agreement with General Electric Capital Corporation:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Accounts Receivable Sold	$	20,662	$	14,800	$	48,802	$	44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable		153		45		406		152

Fair Value Measurements

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, requires enhanced disclosures about assets and liabilities measured at fair value and 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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash	$	513	$	--
Forward Gasoline Purchase Contracts		24
Forward Energy Contracts				3,929
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				13,560
Investments of Captive Insurance Company:
Corporate Debt Securities		9,172
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account		3,000
Total Assets	$	12,709	$	17,489
Liabilities:
Forward Energy Contracts	$	--	$	16,390
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				125
Total Liabilities	$	--	$	16,515

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

Inventories

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2011		2010
Finished Goods	$	26,218	$	29,113
Work in Process		14,248		7,171
Raw Material, Fuel and Supplies		50,648		42,986
Total Inventories	$	91,114	$	79,270

Goodwill

Goodwill

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

Accu

(in thousands)	Gross Balance December 31, 2010		Accumulated Impairments			Balance (net of impairments) December 31, 2010		Adjustments to Goodwill in 2011		Balance (net of impairments) September 30, 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

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	3,024	$	13,787	15 – 25 years
Covenants Not to Compete		1,704		1,697		7	3 – 5 years
Other Intangible Assets Including Contracts		1,030		902		128	5 – 30 years
Total	$	19,545	$	5,623	$	13,922
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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Amortization Expense – Intangible Assets	$	220	$	238	$	668	$	784

(in thousands)	2011		2012		2013		2014		2015
Estimated Amortization Expense – Intangible Assets	$	887	$	911	$	947	$	947	$	931

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Share-Based Payments - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2011 Year Project
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of share-based payment programs	5
Vesting Period for Restricted Stock Units (in years)	4
Unrecognized compensation expense related to stock-based compensation	$ 2.8
Unrecognized compensation expense related to stock-based compensation, weighted-average period of amortization	2.6
Minimum | Executive Officer | Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of actual payment of the target amount	0.00%
Maximum | Executive Officer | Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of actual payment of the target amount	200.00%
Executive Officer | Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum aggregate common shares award	97,200
Aggregate Target Common Shares Award	48,600

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Reconciliation of the Company's Common Shares Outstanding (Detail)	9 Months Ended
	Sep. 30, 2011
Common stock roll-forward [Line Items]
Common Shares Outstanding, December 31, 2010	36,002,739
Vesting of Restricted Stock Units	17,325
Shares Withheld for Individual Income Tax Requirements	(6,641)
Common Shares Outstanding, September 30, 2011	36,062,023
Employee
Common stock roll-forward [Line Items]
Restricted Stock Issued	24,600
Director
Common stock roll-forward [Line Items]
Restricted Stock Issued	24,000

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Warranty Reserves (Detail) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011
Warranty Reserve Balance, December 31, 2010	$ 2,676
Provision for Warranties Used During the Year	845
Less Settlements Made During the Year	991
Increase in Warranty Estimates for Prior Years	145
Warranty Reserve Balance, September 30, 2011	$ 2,675

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Commitments and Contingencies Disclosure [Line Items]
Loss Contingency, Range of Possible Loss, Maximum	9.0
Period 1
Commitments and Contingencies Disclosure [Line Items]
Coal purchase agreements contracts expiration year	2012
Period 2
Commitments and Contingencies Disclosure [Line Items]
Coal purchase agreements contracts expiration year	2016

XML

Short-Term and Long-Term Borrowings (Tables)

9 Months Ended

Sep. 30, 2011

Status of our Lines of Credit

The following table presents the status of our lines of credit as of September 30, 2011 and December 31, 2010:

(in thousands)	Line Limit		In Use on September 30, 2011		Restricted due to Outstanding Letters of Credit		Available on September 30, 2011		Available on December 31, 2010
Otter Tail Corporation Credit Agreement	$	200,000	$	20,000	$	1,374	$	178,626	$	144,350
OTP Credit Agreement		170,000		19,010		1,050		149,940		144,436
Total	$	370,000	$	39,010	$	2,424	$	328,566	$	288,786

Breakdown of the Assignment of the Company's Consolidated Short-term and Long-term Debt Outstanding

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	19,010	$	65		$	20,000	$	39,075
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011	$	90,000						$	90,000
Pollution Control Refunding Revenue Bonds,   Variable, 1.50% at September 30, 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		20,105							20,105
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 September 30, 2011				$	4,220		1,929		6,149
Total	$	280,595		$	4,220	$	151,929	$	436,744
Less: Current Maturities		--			3,124		162		3,286
Unamortized Debt Discount		--			--		4		4
Total Long-Term Debt	$	280,595		$	1,096	$	151,763	$	433,454
Total Short-Term and Long-Term Debt (with current maturities)	$	299,605		$	4,285	$	171,925	$	475,815

December 31, 2010 (in thousands)	OTP			Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	25,314	$	--		$	54,176	$	79,490
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 December 31, 2010, due December 1, 2012		10,400							10,400
9.000% Notes, due December 15, 2016						$	100,000		100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000							33,000
Grant County, South Dakota Pollution Control    Refunding Revenue Bonds 4.65%, due September 1, 2017		5,100							5,100
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 December 31, 2010				$	4,706				4,706
Total	$	280,715		$	4,706	$	150,000	$	435,421
Less: Current Maturities		--			604		--		604
Unamortized Debt Discount		--			--		5		5
Total Long-Term Debt	$	280,715		$	4,102	$	149,995	$	434,812
Total Short-Term and Long-Term Debt (with current maturities)	$	306,029		$	4,706	$	204,171	$	514,906

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Consolidated Statements of Income (Parenthetical) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income (Loss) from Discontinued Operations, income tax (benefit) expense	$ (34)	$ 1,225	$ (398)	$ 3,081
Gain (Loss) on Disposition of Discontinued Operations, income tax (benefit) expense	$ (302)	$ 0	$ 3,213	$ 0

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2011

Percents of the Company's Consolidated Revenues Recorded under the Percentage-of-Completion Method

Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Percentage-of-Completion Revenues		34.9	%		26.3	%		33.5	%		26.5	%

Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts

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

	September 30,			December 31,
(in thousands)	2011			2010
Costs Incurred on Uncompleted Contracts	$	525,259		$	460,125
Less Billings to Date		(507,751	)		(430,471	)
Plus Estimated Earnings Recognized		26,756			31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

Summary of Uncompleted Contracts Included in Company's Consolidated Balance Sheets

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:

	September 30,			December 31,
(in thousands)	2011			2010
Costs and Estimated Earnings in Excess of Billings	$	54,309		$	67,352
Billings in Excess of Costs and Estimated Earnings		(10,045	)		(6,467	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

Warranty Reserves

Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures.

(in thousands)
Warranty Reserve Balance, December 31, 2010	$	2,676
Provision for Warranties Used During the Year		845
Less Settlements Made During the Year		991
Increase in Warranty Estimates for Prior Years		145
Warranty Reserve Balance, September 30, 2011	$	2,675

Accounts Receivable Retained by Customers Pending Project Completion

Accounts Receivable include the following amounts, billed under contracts by the Company’s subsidiaries, that have been retained by customers pending project completion:

	September 30,		December 31,
(in thousands)	2011		2010
Accounts Receivable Retained by Customers	$	12,447	$	11,848

Amounts of Accounts Receivable Sold and Discounts, Fees and Commissions Paid

Following are the amounts of accounts receivable sold and discounts, fees and commissions paid under DMI’s receivables sales agreement with General Electric Capital Corporation:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Accounts Receivable Sold	$	20,662	$	14,800	$	48,802	$	44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable		153		45		406		152

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash	$	513	$	--
Forward Gasoline Purchase Contracts		24
Forward Energy Contracts				3,929
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				13,560
Investments of Captive Insurance Company:
Corporate Debt Securities		9,172
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account		3,000
Total Assets	$	12,709	$	17,489
Liabilities:
Forward Energy Contracts	$	--	$	16,390
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				125
Total Liabilities	$	--	$	16,515

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

Corrected Classification Resulting in Increases in Operating Revenues and Operating Income and Decreases in Other Income

The Company has corrected this classification resulting in the following increases in Operating Revenues and Operating Income and decreases in Other Income:

	Three Months Ended		Nine Months Ended
(in thousands)	September 30, 2010		September 30, 2010
MNCIP Incentives reclassified from Other Income to Operating Revenue	$	550	$	2,151

Summary of Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2011		2010
Finished Goods	$	26,218	$	29,113
Work in Process		14,248		7,171
Raw Material, Fuel and Supplies		50,648		42,986
Total Inventories	$	91,114	$	79,270

Summary of Changes to Goodwill by Business Segment

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

Accu

(in thousands)	Gross Balance December 31, 2010		Accumulated Impairments			Balance (net of impairments) December 31, 2010		Adjustments to Goodwill in 2011		Balance (net of impairments) September 30, 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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	3,024	$	13,787	15 – 25 years
Covenants Not to Compete		1,704		1,697		7	3 – 5 years
Other Intangible Assets Including Contracts		1,030		902		128	5 – 30 years
Total	$	19,545	$	5,623	$	13,922
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

Amortization Expense - Intangible Assets

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Amortization Expense – Intangible Assets	$	220	$	238	$	668	$	784

Schedule of Expected Amortization Expense

(in thousands)	2011		2012		2013		2014		2015
Estimated Amortization Expense – Intangible Assets	$	887	$	911	$	947	$	947	$	931

Comprehensive Income

Comprehensive Income

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Net Income (Loss)	$	6,368		$	6,101	$	30,892		$	(3,400	)
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gains and (Reversal of   Previously Recorded Foreign Currency Translation Gains)		--			484		(3,977	)		295
Amortization of Unrecognized Losses and Costs   Related to Postretirement Benefit Programs		47			105		(395	)		314
Unrealized Gain (Loss) on Available-for-Sale Securities		(2	)		54		6			86
Total Other Comprehensive Income (Loss)		45			643		(4,366	)		695
Total Comprehensive Income (Loss)	$	6,413		$	6,744	$	26,526		$	(2,705	)

Supplemental Disclosure of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	Nine Months Ended
	September 30,
(in thousands)	2011		2010
Increases in Accounts Payable Related to Capital Expenditures	$	1,790	$	63

DMI Industries, Inc

Costs and Estimated Earnings in Excess of Billings

Included in Costs and Estimated Earnings in Excess of Billings are the following amounts at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer:

	September 30,		December 31,
(in thousands)	2011		2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	38,843	$	58,990

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Summary of Inventories (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Schedule of Inventory [Line Items]
Finished Goods	$ 26,218	$ 29,113
Work in Process	14,248	7,171
Raw Material, Fuel and Supplies	50,648	42,986
Total Inventories	$ 91,114	$ 79,270

XML

Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Amount of Regulatory Assets and Liabilities Recorded on the Company's Consolidated Balance Sheet

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

	September 30,		December 31,		Remaining Recovery/
(in thousands)	2011		2010		Refund Period
Regulatory Assets – Current:
Accrued Cost-of-Energy Revenue	$	2,552	$	2,387	23 months
Regulatory Assets – Long Term:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	70,265	$	74,156	see notes
Deferred Marked-to-Market Losses		13,560		12,054	47 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		7,158		6,655	21 months
Minnesota Renewable Resource Rider Accrued Revenues		3,452		6,834	30 months
Big Stone II Unrecovered Project Costs – Minnesota		2,758		6,445	60 months
Debt Reacquisition Premiums		2,582		3,107	252 months
Accumulated ARO Accretion/Depreciation Adjustment		2,545		2,218	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		2,508		3,460	22 months
Deferred Income Taxes		2,025		5,785	asset lives
North Dakota Renewable Resource Rider Accrued Revenues		1,379		2,415	27 months
General Rate Case Recoverable Expenses		1,189		1,773	28 months
Big Stone II Unrecovered Project Costs – South Dakota		936		1,419	112 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		436		717	14 months
South Dakota – Asset-Based Margin Sharing Shortfall		257		501	5 months
Minnesota Transmission Rider Accrued Revenues		252		34	15 months
Deferred Holding Company Formation Costs		152		193	33 months
Total Regulatory Assets – Long Term	$	111,454	$	127,766
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	64,031	$	61,740	asset lives
Deferred Income Taxes		3,691		4,289	asset lives
Minnesota Transmission Rider Accrued Refund		1,081		--	see notes
Deferred Marked-to-Market Gains		125		175	35 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		124		128	267 months
South Dakota – Nonasset-Based Margin Sharing Excess		61		84	15 months
Total Regulatory Liabilities	$	69,113	$	66,416
Net Regulatory Asset Position	$	44,893	$	63,737

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Short-Term and Long-Term Borrowings - Additional Information (Detail) (USD $)	1 Months Ended	9 Months Ended				9 Months Ended			1 Months Ended			9 Months Ended	12 Months Ended	1 Months Ended	9 Months Ended	12 Months Ended
	Mar. 18, 2011	Sep. 30, 2011	Sep. 30, 2011 Minimum OTP Credit Agreement	Sep. 30, 2011 Maximum OTP Credit Agreement	Mar. 03, 2011 Maximum OTP Credit Agreement	Sep. 30, 2011 OTP Credit Agreement	Mar. 03, 2011 OTP Credit Agreement	Mar. 03, 2011 OTP Credit Agreement Letter of Credit	Apr. 06, 2011 North Dakota Development Fund	Jul. 29, 2011 Senior Unsecured Notes 4.63 Percent Due December 1, 2021	Jul. 29, 2011 Senior Unsecured Notes 6.63%, due December 1, 2011	Sep. 30, 2011 Senior Unsecured Notes 6.63%, due December 1, 2011	Dec. 31, 2010 Senior Unsecured Notes 6.63%, due December 1, 2011	Jul. 29, 2011 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012	Sep. 30, 2011 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012	Dec. 31, 2010 Pollution Control Refunding Revenue Bonds, Variable, 1.50% at September 30, 2011, due December 1st, 2012
Line of Credit Facility [Line Items]
Line Limit		$ 370,000,000			$ 250,000,000	$ 170,000,000	$ 170,000,000	$ 50,000,000
Line of credit interest rate						LIBOR plus 1.5%
Line of credit interest rate spread							1.50%
Amended and restated credit agreement date of expiry						2016-03-03
Line of credit covenant, debt to total capitalization ratio				0.60
Line of credit covenant, interest and dividend coverage ratio			1.50
Note payable, long term									500,000
Borrowings under a Partnership in assisting Community Expansion Loan	1,500,000
Senior Unsecured Notes amount										140,000,000
Proceeds from Senior Unsecured Notes to be used to pay debt											$ 90,000,000			$ 10,400,000
Loan expiration period, in years		10 years							7 years
Debt effective interest rate	2.54%								3.95%	4.63%	6.63%	6.63%	6.63%		1.50%	2.50%
Debt term of payment	monthly principal and interest payments								monthly principal and interest payments
Long-Term Debt, Due Date									Apr. 01, 2018	Dec. 01, 2021	Dec. 01, 2011	Dec. 01, 2011	Dec. 01, 2011	Dec. 01, 2012	Dec. 01, 2012	Dec. 01, 2012
Unsecured notes due date	2021-03
Senior Unsecured Notes, expected issuance date										Dec. 01, 2011

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Amounts of Compensation Expense Recognized under the Company's Stock-Based Payment Programs (Parenthetical) (Detail) (Employee Stock Purchase Plan)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense, discount rate	15.00%	15.00%	15.00%	15.00%

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Summary of Significant Accounting Policies

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 the Financial Accounting Standards Board Accounting Standards Codification (ASC). 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 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. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Percentage-of-Completion Revenues		34.9	%		26.3	%		33.5	%		26.5	%

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

	September 30,			December 31,
(in thousands)	2011			2010
Costs Incurred on Uncompleted Contracts	$	525,259		$	460,125
Less Billings to Date		(507,751	)		(430,471	)
Plus Estimated Earnings Recognized		26,756			31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	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:

	September 30,			December 31,
(in thousands)	2011			2010
Costs and Estimated Earnings in Excess of Billings	$	54,309		$	67,352
Billings in Excess of Costs and Estimated Earnings		(10,045	)		(6,467	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	44,264		$	60,885

Included in Costs and Estimated Earnings in Excess of Billings are the following amounts at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer:

	September 30,		December 31,
(in thousands)	2011		2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	38,843	$	58,990

These amounts are 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.

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures.

(in thousands)
Warranty Reserve Balance, December 31, 2010	$	2,676
Provision for Warranties Used During the Year		845
Less Settlements Made During the Year		991
Increase in Warranty Estimates for Prior Years		145
Warranty Reserve Balance, September 30, 2011	$	2,675

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 the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Accounts Receivable include the following amounts, billed under contracts by the Company’s subsidiaries, that have been retained by customers pending project completion:

	September 30,		December 31,
(in thousands)	2011		2010
Accounts Receivable Retained by Customers	$	12,447	$	11,848

Sales of Receivables

DMI is a party to a $40 million receivables sales agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement is subject to renewal in March 2012. The current discount rate is 3-month LIBOR plus 4%. 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. Following are the amounts of accounts receivable sold and discounts, fees and commissions paid under DMI’s receivables sales agreement with General Electric Capital Corporation:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Accounts Receivable Sold	$	20,662	$	14,800	$	48,802	$	44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable		153		45		406		152

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, requires enhanced disclosures about assets and liabilities measured at fair value and 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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash	$	513	$	--
Forward Gasoline Purchase Contracts		24
Forward Energy Contracts				3,929
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts				13,560
Investments of Captive Insurance Company:
Corporate Debt Securities		9,172
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account		3,000
Total Assets	$	12,709	$	17,489
Liabilities:
Forward Energy Contracts	$	--	$	16,390
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts				125
Total Liabilities	$	--	$	16,515

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 and nine months ended September 30, 2010 reflect the reclassifications of the assets and liabilities, operating results and cash flows of IPH and E.W. Wylie’s (Wylie) heavy haul and specialized shipment and transportation of wind turbine components business to discontinued operations as a result of second quarter 2011 sale of IPH and the Company's decision to exit the heavy haul and specialized shipment and transportation of wind turbine components business. The Company sold 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 and nine months ended September 30, 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 the following increases in Operating Revenues and Operating Income and decreases in Other Income:

	Three Months Ended		Nine Months Ended
(in thousands)	September 30, 2010		September 30, 2010
MNCIP Incentives reclassified from Other Income to Operating Revenue	$	550	$	2,151

The correction had no impact on the Company’s net income, total assets, or operating cash flows for the three and nine months ended September 30, 2010.

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2011		2010
Finished Goods	$	26,218	$	29,113
Work in Process		14,248		7,171
Raw Material, Fuel and Supplies		50,648		42,986
Total Inventories	$	91,114	$	79,270

Goodwill

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

Accu

(in thousands)	Gross Balance December 31, 2010		Accumulated Impairments			Balance (net of impairments) December 31, 2010		Adjustments to Goodwill in 2011		Balance (net of impairments) September 30, 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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortized Intangible Assets:
Customer Relationships	$	16,811	$	3,024	$	13,787	15 – 25 years
Covenants Not to Compete		1,704		1,697		7	3 – 5 years
Other Intangible Assets Including Contracts		1,030		902		128	5 – 30 years
Total	$	19,545	$	5,623	$	13,922
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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Amortization Expense – Intangible Assets	$	220	$	238	$	668	$	784

(in thousands)	2011		2012		2013		2014		2015
Estimated Amortization Expense – Intangible Assets	$	887	$	911	$	947	$	947	$	931

Comprehensive Income

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2011			2010		2011			2010
Net Income (Loss)	$	6,368		$	6,101	$	30,892		$	(3,400	)
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gains and (Reversal of   Previously Recorded Foreign Currency Translation Gains)		--			484		(3,977	)		295
Amortization of Unrecognized Losses and Costs   Related to Postretirement Benefit Programs		47			105		(395	)		314
Unrealized Gain (Loss) on Available-for-Sale Securities		(2	)		54		6			86
Total Other Comprehensive Income (Loss)		45			643		(4,366	)		695
Total Comprehensive Income (Loss)	$	6,413		$	6,744	$	26,526		$	(2,705	)

Supplemental Disclosures of Cash Flow Information

	Nine Months Ended
	September 30,
(in thousands)	2011		2010
Increases in Accounts Payable Related to Capital Expenditures	$	1,790	$	63

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Class B Stock Options of Subsidiary

9 Months Ended

Sep. 30, 2011

Class B Stock Options of Subsidiary

11. Class B Stock Options of Subsidiary

In conjunction with the sale of IPH on May 6, 2011, all 363 outstanding IPH Class B common share options were cancelled by mutual agreement between the issuer and the holders of the options and a liability to the holders of the options was established based on the fair value of the options on May 6, 2011. The liability was assumed by the new owner of IPH. The 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 on May 6, 2011. The book value of IPH Class B common share options prior to their cancellation on May 6, 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 was charged to retained earnings and earnings available for common shares were reduced by $322,000 in the second quarter of 2011.

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Amount of Regulatory Assets and Liabilities Recorded on the Company's Consolidated Balance Sheet (Detail) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Regulatory Assets - Long Term	$ 111,454	$ 127,766
Regulatory Liabilities	69,113	66,416
Net Regulatory Asset Position	44,893	63,737
Accrued Cost-of-Energy Revenue
Regulatory Assets - Current	2,552	2,387
Regulatory Assets - Current, Remaining Recovery/Refund Period	23 months
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Regulatory Assets - Long Term	70,265	74,156
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	see notes
Deferred Marked-to-Market Losses
Regulatory Assets - Long Term	13,560	12,054
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	47 months
Deferred Conservation Improvement Program Costs & Accrued Incentives
Regulatory Assets - Long Term	7,158	6,655
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	21 months
Minnesota Renewable Resource Rider Accrued Revenues
Regulatory Assets - Long Term	3,452	6,834
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	30 months
Big Stone II Unrecovered Project Costs - Minnesota
Regulatory Assets - Long Term	2,758	6,445
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	60 months
Debt Reacquisition Premiums
Regulatory Assets - Long Term	2,582	3,107
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	252 months
Accumulated ARO Accretion/Depreciation Adjustment
Regulatory Assets - Long Term	2,545	2,218
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	asset lives
Big Stone II Unrecovered Project Costs - North Dakota
Regulatory Assets - Long Term	2,508	3,460
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	22 months
Deferred Income Taxes
Regulatory Assets - Long Term	2,025	5,785
Regulatory Liabilities	3,691	4,289
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	asset lives
Regulatory Liabilities, Remaining Recovery/Refund Period	asset lives
North Dakota Renewable Resource Rider Accrued Revenues
Regulatory Assets - Long Term	1,379	2,415
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	27 months
General Rate Case Recoverable Expenses
Regulatory Assets - Long Term	1,189	1,773
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	28 months
Big Stone II Unrecovered Project Costs - South Dakota
Regulatory Assets - Long Term	936	1,419
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	112 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND
Regulatory Assets - Long Term	436	717
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	14 months
South Dakota - Asset-Based Margin Sharing Shortfall
Regulatory Assets - Long Term	257	501
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	5 months
Minnesota Transmission Rider Accrued Revenues
Regulatory Assets - Long Term	252	34
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	15 months
Deferred Holding Company Formation Costs
Regulatory Assets - Long Term	152	193
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	33 months
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Regulatory Liabilities	64,031	61,740
Regulatory Liabilities, Remaining Recovery/Refund Period	asset lives
Minnesota Transmission Rider Accrued Refund
Regulatory Liabilities	1,081
Regulatory Liabilities, Remaining Recovery/Refund Period	see notes
Deferred Marked-to-Market Gains
Regulatory Liabilities	125	175
Regulatory Liabilities, Remaining Recovery/Refund Period	35 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Regulatory Liabilities	124	128
Regulatory Liabilities, Remaining Recovery/Refund Period	267 months
South Dakota - Nonasset-Based Margin Sharing Excess
Regulatory Liabilities	$ 61	$ 84
Regulatory Liabilities, Remaining Recovery/Refund Period	15 months

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Recognized but Unrealized Net Gains on the Forward Energy and Capacity Purchases and Sales Expected to be Realized on Settlement (Detail) (USD $) In Thousands	Sep. 30, 2011
Net Gain	$ 974
4th Quarter 2011
Net Gain	354
2012
Net Gain	$ 620

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Amounts of Commitments for OTP's Capacity and Energy Requirements (Detail) (Otter Tail Power Company, USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Capacity and Energy Requirements
Unrecorded Unconditional Purchase Obligation [Line Items]
2011	$ 21,268	$ 20,134
2012	25,025	21,637
2013	21,868	16,492
2014	24,701	15,388
2015	18,915	12,307
Beyond 2015	78,879	78,879
Total	190,656	164,837
Increase
2011	1,134
2012	3,388
2013	5,376
2014	9,313
2015	6,608
Beyond 2015
Total	25,819
Coal and Freight Purchase Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
2011	52,819	47,122
2012	48,444	34,958
2013	9,855	9,855
2014	9,854	9,854
2015	9,854	9,854
Beyond 2015	4,106	4,106
Total	134,932	115,749
Increase
2011	5,697
2012	13,486
Beyond 2015
Total	$ 19,183

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Percents of the Company's Consolidated Revenues Recorded under the Percentage-of-Completion Method (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenue Recorded under Percentage of Completion Method [Line Items]
Percentage-of-Completion Revenues	34.90%	26.30%	33.50%	26.50%

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Discontinued Operations

9 Months Ended

Sep. 30, 2011

Discontinued 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. In the second quarter of 2011, Wylie decided to exit its heavy haul/specialized shipment and transportation of wind turbine components business, determining that the risks associated with continuing to provide these services outweighed any potential profits to be derived from these operations. The financial position, results of operations, and cash flows of IPH and Wylie’s specialized shipment and transportation of wind turbine components business are reported as discontinued operations in the Company’s consolidated financial statements as of September 30, 2011 and December 31, 2010, and for the three and nine month periods ended September 30, 2011 and 2010. Following are summary presentations of the results of discontinued operations for the three and nine month periods ended September 30, 2011 and 2010 and of the major components of assets and liabilities of discontinued operations as of September 30, 2011 and December 31, 2010:

	Three Months Ended
	September 30, 2011									September 30, 2010
(in thousands)	IPH			Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	--		$	--		$	--		$	19,478	$	2,046	$	21,524
Income (Loss) Before Income Taxes	$	--		$	(86	)	$	(86	)	$	3,183	$	82	$	3,265
Gain (Loss) on Disposition - Pretax		(756	)		--			(756	)		--		--		--
Income Tax Expense (Benefit)		(302	)		(34	)		(336	)		1,192		33		1,225
Net Income (Loss)	$	(454	)	$	(52	)	$	(506	)	$	1,991	$	49	$	2,040

	Nine Months Ended
	September 30, 2011								September 30, 2010
(in thousands)	IPH		Wylie-Wind			Total			IPH		Wylie-Wind		Total
Operating Revenues	$	28,125	$	5,448		$	33,573		$	56,648	$	4,700	$	61,348
Income (Loss) Before Income Taxes	$	3,840	$	(4,650	)	$	(810	)	$	8,306	$	129	$	8,435
Gain on Disposition - Pretax		16,011		--			16,011			--		--		--
Income Tax Expense (Benefit)		4,675		(1,860	)		2,815			3,029		52		3,081
Net Income (Loss)	$	15,176	$	(2,790	)	$	12,386		$	5,277	$	77	$	5,354

	September 30, 2011				December 31, 2010
(in thousands)	Wylie-Wind		Total		IPH		Wylie-Wind		Total
Current Assets	$	2	$	2	$	24,836	$	2,461	$	27,297
Goodwill		--		--		24,324		--		24,324
Other Intangibles - Net		--		--		10,852		--		10,852
Net Plant		75		75		30,672		638		31,310
Assets of Discontinued Operations	$	77	$	77	$	90,684	$	3,099	$	93,783
Current Liabilities	$	77	$	77	$	6,839	$	4,150	$	10,989
Deferred Income Taxes		--		--		11,553		--		11,553
Long-Term Debt		--		--		634		--		634
Liabilities of Discontinued Operations	$	77	$	77	$	19,026	$	4,150	$	23,176

Because IPH was a material subsidiary, the Company is providing the following pro forma summary presentations of its 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 (Loss)	(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.

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Consolidated Balance Sheets (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and Cash Equivalents	$ 6,604
Accounts Receivable:
Trade-Net	152,761	124,353
Other	16,249	19,399
Inventories	91,114	79,270
Deferred Income Taxes	11,987	11,068
Accrued Utility and Cost-of-Energy Revenues	13,446	16,323
Costs and Estimated Earnings in Excess of Billings	54,309	67,352
Income Taxes Receivable	1,530	4,146
Other	23,627	20,224
Assets of Discontinued Operations	77	93,783
Total Current Assets	371,704	435,918
Investments	11,564	9,708
Other Assets	27,109	27,356
Goodwill	69,742	69,742
Other Intangibles-Net	15,712	16,280
Deferred Debits
Unamortized Debt Expense	6,763	6,444
Regulatory Assets	111,454	127,766
Total Deferred Debits	118,217	134,210
Plant
Electric Plant in Service	1,343,080	1,332,974
Nonelectric Operations	368,739	340,167
Construction Work in Progress	67,174	42,031
Total Gross Plant	1,778,993	1,715,172
Less Accumulated Depreciation and Amortization	681,057	637,831
Net Plant	1,097,936	1,077,341
Total Assets	1,711,984	1,770,555
Current Liabilities
Short-Term Debt	39,075	79,490
Current Maturities of Long-Term Debt	3,286	604
Accounts Payable	113,966	113,761
Accrued Salaries and Wages	21,682	20,252
Accrued Taxes	10,034	11,957
Derivative Liabilities	16,390	17,991
Other Accrued Liabilities	11,368	9,546
Liabilities of Discontinued Operations	77	23,176
Total Current Liabilities	215,878	276,777
Pensions Benefit Liability	76,237	73,538
Other Postretirement Benefits Liability	43,666	42,372
Other Noncurrent Liabilities	19,813	21,043
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	178,308	162,208
Deferred Tax Credits	33,573	44,945
Regulatory Liabilities	69,113	66,416
Other	497	556
Total Deferred Credits	281,491	274,125
Capitalization
Long-Term Debt, Net of Current Maturities	433,454	434,812
Class B Stock Options of Subsidiary		525
Common Shares, Par Value $5 Per Share-Authorized, 50,000,000 Shares; Outstanding, 2011-36,062,023 Shares; 2010-36,002,739 Shares	180,310	180,014
Premium on Common Shares	252,219	251,919
Retained Earnings	196,295	198,443
Accumulated Other Comprehensive (Loss) Income	(2,879)	1,487
Total Common Equity	625,945	631,863
Total Capitalization	1,074,899	1,082,700
Total Liabilities and Equity	1,711,984	1,770,555
Cumulative Preferred Shares
Capitalization
Cumulative Shares	15,500	15,500
Cumulative Preference Shares
Capitalization
Cumulative Shares

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Summary of Uncompleted Contracts Included in Company's Consolidated Balance Sheets (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Uncompleted Contracts [Line Items]
Costs and Estimated Earnings in Excess of Billings	$ 54,309	$ 67,352
Billings in Excess of Costs and Estimated Earnings	(10,045)	(6,467)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$ 44,264	$ 60,885

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Income Taxes Expense (Benefit) - Continuing Operations - Additional Information (Detail) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Taxes [Line Items]
Federal production tax credits (PTCs) earned	$ 1.4	$ 1.6	$ 5.3	$ 4.7
Goodwill impairment loss	12.2
Goodwill impairment loss deductible for income taxes	2.8
DMI Industries, Inc
Income Taxes [Line Items]
Deferred tax benefits on Canadian operating losses	$ 0.5		$ 2.4

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Class B Stock Options of Subsidiary - Additional Information (Detail) (USD $)	9 Months Ended	1 Months Ended
	Sep. 30, 2011	May 06, 2011 Common Class B	Jun. 30, 2011 Common Class B
Class of Stock [Line Items]
Number of Common shares options cancelled	6,641	363
Common stock fair value ,per share		$ 2,973.90
Common stock value ,book value per share		$ 2,085.88
Adjustment to Retained earnings			$ (322,000)

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Comprehensive Income (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net Income (Loss)	$ 6,368	$ 6,101	$ 30,892	$ (3,400)
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gains and (Reversal of Previously Recorded Foreign Currency Translation Gains)		484	(3,977)	295
Amortization of Unrecognized Losses and Costs Related to Postretirement Benefit Programs	47	105	(395)	314
Unrealized Gain (Loss) on Available-for-Sale Securities	(2)	54	6	86
Total Other Comprehensive Income (Loss)	45	643	(4,366)	695
Total Comprehensive Income (Loss)	$ 6,413	$ 6,744	$ 26,526	$ (2,705)

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Balance Sheet Location and Fair Values of Forward Contracts for the Purchase and Sale of Electricity (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative Liabilities - Marked-to-Market Loss	$ (16,390)	$ (17,991)
Forward Contracts
Derivatives, Fair Value [Line Items]
Other Current Assets - Marked-to-Market Gain	3,929	6,875
Regulatory Assets - Deferred Marked-to-Market Loss	13,560	12,054
Total Assets	17,489	18,929
Derivative Liabilities - Marked-to-Market Loss	(16,390)	(17,991)
Regulatory Liabilities - Deferred Marked-to-Market Gain	(125)	(175)
Total Liabilities	(16,515)	(18,166)
Net Fair Value of Marked-to-Market Energy Contracts	$ 974	$ 763

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Amounts of Compensation Expense Recognized under the Company's Stock-Based Payment Programs (Detail) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	$ 2,605	$ 1,153	$ 3,525	$ 2,186
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	51	64	185	205
Employee | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	511	239	759	519
Director | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	185	148	571	446
Executive Officer | Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	1,766	722	1,766	879
Employee | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation Expense	$ 92	$ (20)	$ 244	$ 137

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Summary of Changes to Goodwill by Business Segment (Detail) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011
Goodwill [Line Items]
Gross Balance December 31, 2010	$ 82,241
Accumulated Impairments	(12,499)
Balance (net of impairments) December 31, 2010	69,742
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	69,742
Electric
Goodwill [Line Items]
Gross Balance December 31, 2010	240
Accumulated Impairments	(240)
Adjustments to Goodwill in 2011
Wind Energy
Goodwill [Line Items]
Gross Balance December 31, 2010	6,959
Balance (net of impairments) December 31, 2010	6,959
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	6,959
Manufacturing
Goodwill [Line Items]
Gross Balance December 31, 2010	24,445
Accumulated Impairments	(12,259)
Balance (net of impairments) December 31, 2010	12,186
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	12,186
Construction
Goodwill [Line Items]
Gross Balance December 31, 2010	7,630
Balance (net of impairments) December 31, 2010	7,630
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	7,630
Plastics
Goodwill [Line Items]
Gross Balance December 31, 2010	19,302
Balance (net of impairments) December 31, 2010	19,302
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	19,302
Health Services
Goodwill [Line Items]
Gross Balance December 31, 2010	23,665
Balance (net of impairments) December 31, 2010	23,665
Adjustments to Goodwill in 2011
Balance (net of impairments) September 30, 2011	$ 23,665

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Components of Intangible Assets (Detail) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2011 Year	Dec. 31, 2010 Year
Intangible Assets by Major Class [Line Items]
Amortized Intangible Assets, Gross Carrying Amount	$ 19,545	$ 19,445
Amortized Intangible Assets, Accumulated Amortization	5,623	4,955
Amortized Intangible Assets, Net Carrying Amount	13,922	14,490
Customer Relationships
Intangible Assets by Major Class [Line Items]
Amortized Intangible Assets, Gross Carrying Amount	16,811	16,811
Amortized Intangible Assets, Accumulated Amortization	3,024	2,388
Amortized Intangible Assets, Net Carrying Amount	13,787	14,423
Amortization Periods, minimum	15	15
Amortization Periods, maximum	25	25
Covenants Not to Compete
Intangible Assets by Major Class [Line Items]
Amortized Intangible Assets, Gross Carrying Amount	1,704	1,704
Amortized Intangible Assets, Accumulated Amortization	1,697	1,676
Amortized Intangible Assets, Net Carrying Amount	7	28
Amortization Periods, minimum	3	3
Amortization Periods, maximum	5	5
Other Intangible Assets Including Contracts
Intangible Assets by Major Class [Line Items]
Amortized Intangible Assets, Gross Carrying Amount	1,030	930
Amortized Intangible Assets, Accumulated Amortization	902	891
Amortized Intangible Assets, Net Carrying Amount	128	39
Amortization Periods, minimum	5	5
Amortization Periods, maximum	30	30
Brand/Trade Name
Intangible Assets by Major Class [Line Items]
Nonamortized Intangible Assets, Gross Carrying Amount	1,790	1,790
Nonamortized Intangible Assets, Net Carrying Amount	$ 1,790	$ 1,790

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Rate and Regulatory Matters - Additional Information (Detail) (USD $)	1 Months Ended									9 Months Ended	12 Months Ended						9 Months Ended
	Apr. 25, 2011 Minnesota Public Utilities Commission Otter Tail Power Company	Sep. 30, 2011 Minnesota Public Utilities Commission Otter Tail Power Company	Mar. 31, 2011 Minnesota Public Utilities Commission Otter Tail Power Company	May 27, 2010 Minnesota Public Utilities Commission Otter Tail Power Company	Apr. 02, 2010 Minnesota Public Utilities Commission Otter Tail Power Company	Sep. 30, 2011 Minnesota Public Utilities Commission Otter Tail Power Company Big Stone II Project	Apr. 25, 2011 Minnesota Public Utilities Commission Otter Tail Power Company Big Stone II Project	Apr. 02, 2011 Minnesota Public Utilities Commission Otter Tail Power Company Big Stone II Project	Sep. 30, 2011 Minnesota Public Utilities Commission Otter Tail Power Company Resource Recovery Adjustment	Sep. 30, 2011 Minnesota Public Utilities Commission Otter Tail Power Company Conservation Improvement Program	Dec. 31, 2010 Minnesota Public Utilities Commission Otter Tail Power Company Conservation Improvement Program	Aug. 20, 2010 Maximum South Dakota Public Utilities Commission Otter Tail Power Company	Apr. 21, 2011 South Dakota Public Utilities Commission Otter Tail Power Company	Sep. 28, 2010 South Dakota Public Utilities Commission Otter Tail Power Company	Sep. 30, 2011 South Dakota Public Utilities Commission Otter Tail Power Company Big Stone Air Quality Control System	Feb. 17, 2011 South Dakota Public Utilities Commission Otter Tail Power Company Big Stone II Project	Sep. 30, 2011 South Dakota Public Utilities Commission Big Stone Air Quality Control System
Regulatory Matters [Line Items]
General rate increase request					8.01%							10.00%
General rate revenue increase approved													$ 643,000
Interim rate increase request					3.80%
General rate revenue increase request	5,000,000											2,800,000
General rate increase request, base rate revenues	3.76%
Overall increase rate to customers		1.60%
Interim rate increase approved				3.80%
Interim rate refund, approximate		3,900,000
Accrued refund Liability		3,900,000
Allowed rate of return on rate base		8.61%	8.33%										8.50%
Allowed rate of return on equity		10.74%	10.43%
Percentage of general rate revenue increase approved													2.32%
Capital structure, long term debt percentage		48.28%
Capital structure, common equity percentage		51.72%
Regulatory Asset									3,500,000	7,200,000
Financial incentive income										1,300,000	3,700,000
Number of days the propossed rates are suspended for review														180 days
BART compliant air quality control system implementation period																	5 years
Estimated project cost															264,000,000		490,000,000
Investment cost incurred							3,199,000									1,000,000
Investment cost incurred, project transmission-related cost							3,246,000
Investment cost incurred, at present value						2,758,000
Investment cost incurred, recovery period						60 months		5 years								10 years
Investment cost incurred, transferred to construction work in progress						$ 3,246,000

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Costs and Estimated Earnings in Excess of Billings (Detail) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Uncompleted Contracts [Line Items]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$ 54,309	$ 67,352
DMI Industries, Inc
Uncompleted Contracts [Line Items]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$ 38,843	$ 58,990