10-Q

UNITED STATES

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    June 30, 2012

OR

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

For the transition period from _______________ to _______________

Commission file number              0-53713

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 o

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

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company  o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  Yes o    No x

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

July 31, 2012 – 36,164,448 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I.   Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – June 30, 2012 and December 31, 2011 (not audited)	2 & 3
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2012 and 2011 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2012 and 2011 (not audited)	5
	Consolidated Statements of Cash Flows - Three and Six Months Ended June 30, 2012 and 2011  (not audited)	6
	Notes to Consolidated Financial Statements (not audited)	7-30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31-50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50-51
Item 4.	Controls and Procedures	52
Part II.  Other Information
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53-54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	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)	June 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	--	$	14,652
Accounts Receivable:
Trade—Net		134,235		116,522
Other		16,602		18,807
Inventories		77,368		77,983
Deferred Income Taxes		12,320		12,307
Accrued Utility Revenues		11,325		13,719
Costs and Estimated Earnings in Excess of Billings		75,295		67,109
Regulatory Assets		25,334		27,391
Other		16,539		21,414
Assets of Discontinued Operations		521		29,692
Total Current Assets		369,539		399,596
Investments		9,056		11,093
Other Assets		27,309		26,997
Goodwill		39,119		39,406
Other Intangibles—Net		14,793		15,286
Deferred Debits
Unamortized Debt Expense		5,783		6,458
Regulatory Assets		118,672		124,137
Total Deferred Debits		124,455		130,595
Plant
Electric Plant in Service		1,380,680		1,372,534
Nonelectric Operations		217,391		310,320
Construction Work in Progress		82,523		54,439
Total Gross Plant		1,680,594		1,737,293
Less Accumulated Depreciation and Amortization		630,465		659,744
Net Plant		1,050,129		1,077,549
Total Assets	$	1,634,400	$	1,700,522
See accompanying notes to consolidated financial statements.

2

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands, except share data)	June 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt	$	11,274		$	--
Current Maturities of Long-Term Debt		50,170			3,033
Accounts Payable		118,954			115,514
Accrued Salaries and Wages		18,490			19,043
Accrued Taxes		8,664			11,841
Derivative Liabilities		20,339			18,770
Other Accrued Liabilities		5,540			5,540
Liabilities of Discontinued Operations		4			13,763
Total Current Liabilities		233,435			187,504
Pensions Benefit Liability		98,620			106,818
Other Postretirement Benefits Liability		49,356			48,263
Other Noncurrent Liabilities		22,150			19,002
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		152,598			177,264
Deferred Tax Credits		32,345			33,182
Regulatory Liabilities		68,071			69,106
Other		538			520
Total Deferred Credits		253,552			280,072
Capitalization
Long-Term Debt, Net of Current Maturities		421,829			471,915
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value;  Outstanding 2012 and 2011 – 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, 2012—36,164,448 Shares; 2011—36,101,695 Shares		180,822			180,509
Premium on Common Shares		253,113			253,123
Retained Earnings		109,267			141,248
Accumulated Other Comprehensive Loss		(3,244	)		(3,432	)
Total Common Equity		539,958			571,448
Total Capitalization		977,287			1,058,863
Total Liabilities and Equity	$	1,634,400		$	1,700,522
See accompanying notes to consolidated financial statements.

3

Otter Tail Corporation
Consolidated Statements of Income
(not audited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except share and per-share amounts)	2012			2011			2012			2011
Operating Revenues
Electric	$	78,909		$	77,978		$	168,847		$	169,504
Nonelectric		204,800			205,320			392,451			362,942
Total Operating Revenues		283,709			283,298			561,298			532,446
Operating Expenses
Production Fuel - Electric		12,455			17,080			27,879			36,657
Purchased Power - Electric System Use		12,328			7,894			26,486			20,271
Electric Operation and Maintenance Expenses		32,407			28,687			62,420			57,395
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)		167,612			179,241			330,602			319,580
Other Nonelectric Expenses		17,189			17,014			34,680			30,090
Asset Impairment Charge		45,573			--			46,005			--
Depreciation and Amortization		17,118			17,552			34,171			34,658
Property Taxes - Electric		2,670			2,417			5,287			4,826
Total Operating Expenses		307,352			269,885			567,530			503,477
Operating (Loss) Income		(23,643	)		13,413			(6,232	)		28,969
Interest Charges		8,477			9,138			17,093			18,614
Other Income		741			765			1,734			1,136
(Loss) Income from Continuing Operations Before Income Taxes		(31,379	)		5,040			(21,591	)		11,491
Income Tax (Benefit) Expense – Continuing Operations		(14,493	)		(85	)		(14,196	)		1,153
Net (Loss) Income from Continuing Operations		(16,886	)		5,125			(7,395	)		10,338
Discontinued Operations
(Loss) Income - net of Income Tax (Benefit) Expense of  ($11), $280, $573, and $568 for the respective periods		(15	)		451			826			934
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of  ($35), $3,515, ($169), and $3,515 for the respective periods		(455	)		13,252			(3,544	)		13,252
Net (Loss) Income from Discontinued Operations		(470	)		13,703			(2,718	)		14,186
Net (Loss) Income		(17,356	)		18,828			(10,113	)		24,524
Preferred Dividend Requirements and Other Adjustments		184			506			368			690
Earnings Available for Common Shares	$	(17,540	)	$	18,322		$	(10,481	)	$	23,834
Average Number of Common Shares Outstanding—Basic		36,031,447			35,926,124			36,013,313			35,901,489
Average Number of Common Shares Outstanding—Diluted		36,031,447			36,163,805			36,013,313			36,139,170
Basic Earnings Per Common Share:
Continuing Operations	$	(0.48	)	$	0.14		$	(0.22	)	$	0.28
Discontinued Operations		(0.01	)		0.37			(0.07	)		0.38
	$	(0.49	)	$	0.51		$	(0.29	)	$	0.66
Diluted Earnings Per Common Share:
Continuing Operations	$	(0.48	)	$	0.14		$	(0.22	)	$	0.28
Discontinued Operations		(0.01	)		0.37			(0.07	)		0.38
	$	(0.49	)	$	0.51		$	(0.29	)	$	0.66
Dividends Declared Per Common Share	$	0.2975		$	0.2975		$	0.5950		$	0.5950
See accompanying notes to consolidated financial statements.

4

Otter Tail Corporation
Consolidated Statements of Comprehensive Income
(not audited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Net (Loss) Income	$	(17,356	)	$	18,828		$	(10,113	)	$	24,524
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities:
Gain Arising During Period		4			31			108			14
Income Tax Expense		(2	)		(13	)		(43	)		(6	)
Unrealized Gain on Available-for-Sale Securities – net-of-tax		2			18			65			8
Foreign Currency Translation Adjustment:
Unrealized Net Change During Period		--			(342	)		--			303
Reversal of Previously Recognized Gains Realized on the Sale of Idaho Pacific Holdings, Inc. (IPH)		--			(6,068	)		--			(6,068	)
Income Tax Benefit		--			1,988			--			1,788
Foreign Currency Translation Adjustment – net-of-tax		--			(4,422	)		--			(3,977	)
Pension and Postretirement Benefit Plans:
Actuarial Loss -- Regulatory Allocation Adjustment (ESSRP)		--			--			--			(1,621	)
Amortization of Unrecognized Postretirement Benefit Losses and Costs		102			713			204			884
Income Tax (Expense) Benefit		(40	)		(285	)		(81	)		295
Pension and Postretirement Benefit Plans – net-of-tax		62			428			123			(442	)
Total Other Comprehensive Income (Loss)		64			(3,976	)		188			(4,411	)
Total Comprehensive (Loss) Income	$	(17,292	)	$	14,852		$	(9,925	)	$	20,113
See accompanying notes to consolidated financial statements.

5

Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)
	Six Months Ended June 30,
(in thousands)	2012			2011
Cash Flows from Operating Activities
Net (Loss) Income	$	(10,113	)	$	24,524
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Loss (Gain) from Sale of Discontinued Operations		3,544			(13,252	)
Income from Discontinued Operations		(826	)		(934	)
Depreciation and Amortization		34,171			34,658
Asset Impairment Charge		46,005			--
Deferred Tax Credits		(1,045	)		(1,281	)
Deferred Income Taxes		(9,632	)		5,650
Change in Deferred Debits and Other Assets		9,960			7,648
Discretionary Contribution to Pension Plan		(10,000	)		--
Change in Noncurrent Liabilities and Deferred Credits		6,095			1,212
Allowance for Equity (Other) Funds Used During Construction		(378	)		(292	)
Change in Derivatives Net of Regulatory Deferral		748			45
Stock Compensation Expense – Equity Awards		612			921
Other—Net		453			654
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(15,508	)		(30,298	)
Change in Inventories		615			(6,235	)
Change in Other Current Assets		(10,917	)		(2,743	)
Change in Payables and Other Current Liabilities		6,905			8,967
Change in Interest and Income Taxes Receivable/Payable		(6,549	)		(162	)
Net Cash Provided by Continuing Operations		44,140			29,082
Net Cash Provided by Discontinued Operations		1,377			11,655
Net Cash Provided by Operating Activities		45,517			40,737
Cash Flows from Investing Activities
Capital Expenditures		(69,443	)		(39,777	)
Proceeds from Disposal of Noncurrent Assets		5,560			1,233
Net (Increase) Decrease in Other Investments		(268	)		937
Net Cash Used in Investing Activities - Continuing Operations		(64,151	)		(37,607	)
Net Proceeds from Sale of Discontinued Operations		24,278			84,363
Net Cash Used in Investing Activities - Discontinued Operations		(11,705	)		(13,503	)
Net Cash (Used in) Provided by Investing Activities		(51,578	)		33,253
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		7,352			(5,627	)
Net Short-Term Borrowings (Repayments)		11,274			(46,777	)
Payments for Retirement of Common Stock and Common Stock Issuance Expenses		(196	)		(152	)
Proceeds from Issuance of Long-Term Debt		--			2,007
Short-Term and Long-Term Debt Issuance Expenses		(10	)		(688	)
Payments for Retirement of Long-Term Debt		(2,949	)		(167	)
Dividends Paid and Other Distributions		(21,980	)		(21,952	)
Net Cash Used in Financing Activities - Continuing Operations		(6,509	)		(73,356	)
Net Cash Used in Financing Activities - Discontinued Operations		(1,409	)		(310	)
Net Cash Used in Financing Activities		(7,918	)		(73,666	)
Net Change in Cash and Cash Equivalents - Discontinued Operations		(673	)		--
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations		--			(324	)
Net Change in Cash and Cash Equivalents		(14,652	)		--
Cash and Cash Equivalents at Beginning of Period		14,652			--
Cash and Cash Equivalents at End of Period	$	--		$	--
See accompanying notes to consolidated financial statements.

6

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments 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, 2011, 2010 and 2009 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Because of seasonal and other factors, the earnings for the three and six month periods ended June 30, 2012 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, 2011.

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 (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) 815, Derivatives and Hedging. 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Percentage-of-Completion Revenues		36.2	%		38.0	%		34.2	%		36.8	%

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs Incurred on Uncompleted Contracts	$	533,627		$	583,346
Less Billings to Date		(500,959	)		(550,070	)
Plus Estimated Earnings Recognized		27,299			24,478
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

7

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs and Estimated Earnings in Excess of Billings	$	75,295		$	67,109
Billings in Excess of Costs and Estimated Earnings		(15,328	)		(9,355	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

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:

	June 30,		December 31,
(in thousands)	2012		2011
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	61,834	$	54,541

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, 2011	$	3,170
Provision for Warranties Issued During the Year		426
Settlements Made During the Year		(552	)
Adjustments to Warranty Estimates for Prior Years		(38	)
Warranty Reserve Balance, June 30, 2012	$	3,006

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:

	June 30,		December 31,
(in thousands)	2012		2011
Accounts Receivable Retained by Customers	$	14,390	$	13,526

8

Sales of Receivables

DMI was a party to a $40 million receivables sales agreement whereby designated customer accounts receivable were sold to General Electric Capital Corporation (GECC) on a revolving basis. This agreement was terminated effective April 26, 2012. 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 under DMI’s receivables sales agreement with GECC:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Accounts Receivable Sold	$	11,087	$	9,092	$	32,115	$	28,140

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 tables present, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	2,402
Forward Gasoline Purchase Contracts				27
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,114
U.S. Government Debt Securities – Held by Captive Insurance Company				1,303
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		734
Equity Securities - Nonqualified Retirement Savings Plan		127
Total Assets	$	2,471	$	10,846
Liabilities:
Derivative Liabilities:
Forward Energy Contracts	$	--	$	20,337
Forward Gasoline Purchase Contracts				2
Total Liabilities	$	--	$	20,339
In 2012, the Company’s investments in forward gasoline contracts and U.S. government debt securities were moved to level 2 of the fair value hierarchy and the regulatory assets and liabilities are no longer included in the fair value table.

9

December 31, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	3,803
Forward Gasoline Purchase Contracts		9
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Regulatory Assets – Current:
Deferred Mark-to-Market Losses on Forward Energy Contracts				5,208
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				8,083
U.S. Government Debt Securities – Held by Captive Insurance Company		707
Money Market Fund - Escrow Account IPH Sale		1,501
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		254
Regulatory Assets – Deferred:
Deferred Mark-to-Market Losses on Forward Energy Contracts				10,749
Total Assets	$	4,081	$	27,843
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	18,770
Regulatory Liabilities – Current:
Deferred Mark-to-Market Gains on Forward Energy Contracts				96
Total Liabilities	$	--	$	18,866

Inventories

Inventories consist of the following:

	June 30,		December 31,
(in thousands)	2012		2011
Finished Goods	$	24,333	$	21,373
Work in Process		11,365		11,951
Raw Material, Fuel and Supplies		41,670		44,659
Total Inventories	$	77,368	$	77,983

Asset Impairment Charge

The Company entered into a nonbinding letter of interest in June 2012 to sell the property, plant and equipment of DMI for $20 million, with the Company retaining DMI’s net working capital—approximately $66 million on June 30, 2012. The transaction is expected to close no later than January 3, 2013. The market value for DMI’s assets has been significantly impacted by reduced demand for wind towers due to adverse market conditions affecting the industry, including uncertainty regarding renewal or extension of the Federal Production Tax Credit (PTC) for investments in renewable energy resources, which is set to expire at the end of 2012. Based on the Company’s second quarter 2012 decision to divest DMI’s assets and the price for the fixed assets agreed to in the nonbinding letter of interest, DMI recorded a noncash asset impairment charge of $45.6 million ($27.5 million net-of-tax), or $0.76 per share, in the second quarter of 2012 broken down as follows:

(in thousands)
Long-Lived Assets	$	90,846
Accumulated Depreciation – Long-Lived Assets		(45,561	)
Goodwill		288
Total Asset Impairment Charges	$	45,573

Under the terms of the nonbinding letter of interest, DMI must complete its current backlog of towers ordered for delivery in 2012 before closing can occur. Under these circumstances, accounting rules require that DMI’s assets and results of operations continue to be reported as continuing operations. However, on completion of all remaining tower orders, DMI’s assets will be considered available for immediate sale and the Company expects DMI’s results and any remaining assets will be reported as discontinued operations at the end of 2012. Should the transaction not be completed, the Company plans to close DMI’s plants in West Fargo, North Dakota and Tulsa, Oklahoma and sell DMI’s fixed assets, after DMI finishes its backlog of orders for 2012.

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Goodwill and Other Intangible Assets

The following table summarizes changes to goodwill by business segment during 2012:

(in thousands)	Gross Balance December 31, 2011		Accumulated Impairments			Balance (net of impairments) December 31, 2011		Adjustments to Goodwill in 2012			Balance (net of impairments) June 30, 2012
Electric	$	240	$	(240	)	$	--	$	--		$	--
Wind Energy		288		--			288		(288	)		--
Manufacturing		24,445		(12,259	)		12,186		--			12,186
Construction		7,630		--			7,630		1			7,631
Plastics		19,302		--			19,302		--			19,302
Total	$	51,905	$	(12,499	)	$	39,406	$	(287	)	$	39,119

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,661	$	13,150	15 – 25 years
Other Intangible Assets Including Contracts		1,092		549		543	5 – 30 years
Total	$	17,903	$	4,210	$	13,693
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2011(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,236	$	13,575	15 – 25 years
Covenants Not to Compete		713		709		4	3 – 5 years
Other Intangible Assets Including Contracts		1,092		485		607	5 – 30 years
Total	$	18,616	$	4,430	$	14,186
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Amortization Expense – Intangible Assets	$	246	$	218	$	493	$	442

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)	2012		2013		2014		2015		2016
Estimated Amortization Expense – Intangible Assets	$	981	$	977	$	977	$	977	$	945

Supplemental Disclosures of Cash Flow Information

	As of June 30,
(in thousands)	2012		2011
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$	6,558	$	1,326

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Reclassifications and Changes to Presentation

The Company’s consolidated statements of income for the three and six month periods ended June 30, 2011 and consolidated statement of cash flows for the six months ended June 30, 2011 reflect the reclassifications of the operating results and cash flows of E.W. Wylie Corporation (Wylie), DMS Health Technologies, Inc. (DMS), and Aviva Sports, Inc. (Aviva), a wholly owned subsidiary of ShoreMaster, Inc. (ShoreMaster), to discontinued operations as a result of the December 2011 sale of Wylie, the January 2012 sale of Aviva and the February 2012 sale of DMS. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or six month periods ended June 30, 2011.

2. Segment Information

The Company’s businesses have been classified into five reportable 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 sell products and provide services to customers primarily in the United States. The five segments are: Electric, Wind Energy, Manufacturing, Construction and Plastics.

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 Energy consists of DMI, 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. The facility in Ontario, Canada was idled in the fourth quarter of 2011 due to a lack of orders for wind towers.

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 and Minnesota 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.

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

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).

The Company’s corporate operating costs include 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 one customer within the Wind Energy segment that accounted for 10.8% of the Company’s consolidated revenues in 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
United States of America		97.5	%		97.9	%		97.7	%		98.3	%
Canada		1.6	%		1.9	%		1.5	%		1.5	%
All Other Countries		0.9	%		0.2	%		0.8	%		0.2	%

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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 the three and six month periods ended June 30, 2012 and total assets by business segment as of June 30, 2012 and December 31, 2011 are presented in the following tables:

Operating Revenue

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	78,963		$	78,031		$	168,966		$	169,627
Wind Energy		62,618			55,025			114,720			102,013
Manufacturing		63,581			57,320			129,575			112,681
Construction		37,934			49,133			73,551			86,648
Plastics		41,490			44,373			76,365			62,851
Corporate Revenues and Intersegment Eliminations		(877	)		(584	)		(1,879	)		(1,374	)
Total	$	283,709		$	283,298		$	561,298		$	532,446

Interest Expense

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Electric	$	4,762	$	4,990	$	9,613	$	10,078
Wind Energy		1,614		1,858		3,314		3,559
Manufacturing		1,353		1,255		2,689		2,466
Construction		310		227		563		447
Plastics		346		402		692		765
Corporate and Intersegment Eliminations		92		406		222		1,299
Total	$	8,477	$	9,138	$	17,093	$	18,614

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	(800	)	$	8		$	822		$	2,608
Wind Energy		(15,811	)		(2,174	)		(15,967	)		(3,723	)
Manufacturing		1,658			1,562			3,127			3,352
Construction		(1,164	)		130			(3,940	)		(80	)
Plastics		2,722			2,144			4,897			1,903
Corporate		(1,098	)		(1,755	)		(3,135	)		(2,907	)
Total	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153

Earnings Available for Common Shares

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	5,191		$	7,386		$	16,207		$	18,528
Wind Energy		(24,933	)		(6,566	)		(25,623	)		(12,798	)
Manufacturing		2,420			2,769			4,631			5,427
Construction		(1,756	)		184			(5,927	)		(141	)
Plastics		4,067			3,312			7,320			2,938
Corporate		(2,059	)		(2,144	)		(4,371	)		(3,984	)
Discontinued Operations		(470	)		13,381			(2,718	)		13,864
Total	$	(17,540	)	$	18,322		$	(10,481	)	$	23,834

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Identifiable Assets

	June 30,		December 31,
(in thousands)	2012		2011
Electric	$	1,168,902	$	1,170,449
Wind Energy		113,736		149,234
Manufacturing		155,865		154,908
Construction		68,407		69,453
Plastics		87,747		72,200
Corporate		39,222		54,586
Discontinued Operations		521		29,692
Total	$	1,634,400	$	1,700,522

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, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (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. Final rates went into effect October 1, 2011. The overall increase to customers was approximately 1.6% compared to the authorized interim rate increase of 3.8%, which resulted in an interim rate refund to Minnesota retail electric customers of approximately $3.9 million in the fourth quarter of 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%. OTP’s authorized rates of return are based on a capital structure of 48.28% long term debt and 51.72% common equity.

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

Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.

The MPUC issued an order on January 12, 2010 finding OTP’s Luverne Wind Farm project eligible for cost recovery through the Minnesota Renewable Resource Adjustment (MNRRA). The 2010 annual MNRRA cost recovery filing was made on December 31, 2009 with a requested effective date of April 1, 2010. The MPUC approved OTP’s petition for a 2010 MNRRA in the third quarter of 2010 with implementation effective September 1, 2010. The 2010 MNRRA was in place from September 1, 2010 through September 30, 2011 with a recovery of $17.0 million.

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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 the MNRRA regulatory asset. OTP has a regulatory asset of $2.0 million for revenues that are eligible for recovery through the MNRRA rider that have not been billed to Minnesota customers as of June 30, 2012. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by revised filing on July 25, 2012. The filing included a request to extend the period of the new rate for 18 months, which would reduce the current balance of unrecovered costs to zero.

Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or otherwise deemed eligible by the MPUC. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

OTP requested recovery of its transmission investments being recovered through its Minnesota TCR rider rate as part of its general rate case filed on April 2, 2010. In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs currently being recovered through OTP’s Minnesota 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 has a regulatory asset of $0.2 million for revenues that are eligible for recovery through the Minnesota TCR rider that have not been billed to Minnesota customers as of June 30, 2012. OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. The update to OTP’s Minnesota TCR rider, approved by the MPUC on March 26, 2012, went into effect April 1, 2012.

In this TCR rider update, the MNPUC addressed how to handle utility investments in transmission facilities that qualify for regional cost allocation under the MISO tariff. MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from the other MISO utilities. The MPUC considered two possible approaches to recovery of OTP’s transmission investments in excess of amounts allocated back to its retail load-serving obligations: (1) a split method in which OTP’s Minnesota retail customers would be responsible only for the investment allocated back to OTP through the MISO tariff, or (2) an all-in method in which OTP’s retail customers would be responsible for the entire investment OTP made with an offsetting credit for revenues received from other MISO utilities under the MISO tariff. The MPUC approved using the all-in method on March 26, 2012.

On May 24, 2012, OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. If approval is obtained to include projects in the rider, investment in the approved projects will be included in the annual Minnesota TCR rider update filings and recovery of the investment will begin through the TCR rider rates if subsequently approved by the MPUC.

Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal. On July 1, 2010 OTP filed its plan for 2011-2013. The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.

A written order was issued by the MPUC on January 11, 2012 approving the recovery of $3.5 million for the 2010 MNCIP financial incentives. Beginning in January 2012, OTP’s MNCIP Conservation Cost Recovery Adjustment (CCRA) increased from 3.0% to 3.8% for all Minnesota retail electric customers. On March 30, 2012 OTP submitted its annual 2011 financial incentive filing request for $2.6 million.

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OTP has a regulatory asset of $6.2 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 June 30, 2012. OTP recognized revenue for Minnesota conservation costs earned totaling $0.9 million and $1.7 million, respectively, in the three and six month periods ended June 30, 2012, compared with $1.2 million and $3.0 million, respectively, in the three and six month periods ended June 30, 2011.

North Dakota

Renewable Resource Cost Recovery Rider—The 2010 North Dakota Renewable Resource Adjustment (NDRRA) was in place for the period of September 1, 2010 through March 31, 2012 with a recovery of $15.6 million. On December 29, 2011 OTP submitted its annual update to the renewable rider with an April 1, 2012 effective date. OTP’s request for an updated NDRRA was approved by the North Dakota Public Service Commission (NDPSC) on March 21, 2012 and went into effect April 1, 2012. The 2011 NDRRA has an expected recovery of $10.1 million over the period April 1, 2012 through March 31, 2013. OTP has a regulatory asset of $1.3 million for revenues that are eligible for recovery through the NDRRA rider that have not been billed to North Dakota customers as of June 30, 2012.

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 filed a request for an initial North Dakota TCR rider with the NDPSC on April 29, 2011. On April 25, 2012 the NDPSC approved the use of the split method of cost recovery for the North Dakota TCR rider and the rider rate to be effective May 1, 2012. OTP has a regulatory asset of $1.1 million for revenues that are eligible for recovery through the North Dakota TCR rider that have not been billed to North Dakota customers as of June 30, 2012.

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% 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 was approved by the SDPUC and implemented on December 1, 2011.

Federal

Wholesale power sales and transmission rates are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Federal Power Act of 1935, as amended. The FERC is an independent agency, with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

Effective January 1, 2010, the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). OTP was also authorized by the FERC to recover: (1) in its formula rate 100% of prudently incurred Construction Work in Progress (CWIP) in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects that OTP is investing in, including the Fargo project, Bemidji project and Brookings project.

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On December 16, 2010, FERC approved the cost allocation for a new classification of projects in MISO called Multi-Value Projects (MVP). MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011, FERC reaffirmed the MVP cost allocation on Rehearing. The MVP cost allocation is currently being challenged at the United States Court of Appeals, Seventh Circuit.

Effective January 1, 2012, the FERC authorized OTP to recover 100% CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVP’s in MISO’s 2011 Transmission Expansion Plan: the Big Stone South – Brookings MVP and the Ellendale – Big Stone South MVP.

The Big Stone South – Brookings Project—OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. A portion of this line is anticipated to use previously obtained Big Stone II transmission route permits and easements and is expected to be in service in 2017. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. OTP expects, in the third quarter of 2012, to file a request with the SDPUC for recertification of a portion of the line route that was approved as part of the Big Stone II transmission development. OTP and Xcel Energy expect to make a joint route permit filing in the first quarter of 2013 for the remaining portion of the project.

The Ellendale – Big Stone South Project—OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU).  MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. This project will require regulatory approval from both the SDPUC and the NDPSC. Route permits are expected to be filed with the respective commissions in the third quarter of 2013.

Capacity Expansion 2020 (CapX2020)

CapX2020 is a joint initiative of eleven 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 230 kV 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. Recovery of OTP’s CapX2020 transmission investments will be through the MISO Tariff (the Brookings Project as an MVP) and Minnesota, North Dakota and South Dakota TCR Riders.

The Fargo Project—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011.

The MPUC approved a route permit for the St. Cloud to Fargo portion of the Fargo Project 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. Construction on Phase 2 began in November 2011 and is expected to be completed in the fourth quarter of 2013.

A combined North Dakota Certificate of Corridor Compatibility and route permit application was submitted to the NDPSC on October 3, 2011. The NDPSC conducted a hearing on January 30, 2012. The project expects to receive final permit approval from the NDPSC during the third quarter of 2012. Once all final permits have been received from the NDPSC, project agreements for Phase 3, which consists of the line section between Alexandria, Minnesota and Fargo, North Dakota, would be executed with the project partners.

The Brookings Project—The MPUC approved the final line segment route permit for the Brookings Project on February 3, 2011. OTP executed project agreements with co-owners on January 13, 2012. The NDPSC approved the request for an Advanced Determination of Prudence (ADP) on November 10, 2011. The South Dakota route permit was approved by the SDPUC in June 2011. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011.This project will be placed in service in segments with the earliest segment being placed in service in the summer of 2013 and the last segment placed in service during the first quarter of 2015.

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The Bemidji Project—OTP serves as the lead utility for the Bemidji Project. This line is expected to be in service before the end of 2012. The MPUC approved the CON for this project on July 9, 2009. A route permit application was approved by the MPUC on October 28, 2010. The joint state and federal Environmental Impact Statement 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 a judgment 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 August 6, 2012 a Consent Order Approving Stipulation for Entry of Consent Decree was issued in federal court, which enjoins the LLBO from interfering with the construction, operation, maintenance or repair of the transmission line. The federal litigation is now concluded. In conjunction with the stipulated agreement, the tribal court dismissed the LLBO’s action and the LLBO has withdrawn its petition to the MPUC.

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. On March 29, 2012 the EPA took final action to approve South Dakota’s Regional Haze State Implementation Plan (SIP), finding that South Dakota’s SIP submittal met all applicable regional haze regulations. The EPA’s final approval of the SIP was published in the Federal Register on April 26, 2012, with an effective date of May 29, 2012.

On January 14, 2011 OTP filed a petition asking the MPUC for 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 December 20, 2011 the MPUC granted OTP’s petition for ADP for the Big Stone Plant Air Quality Control System (AQCS). The MPUC written order was issued on January 23, 2012.

OTP filed an application for an ADP with the NDPSC on May 20, 2011, and the NDPSC approved OTP’s request for an ADP on May 9, 2012.

On March 30, 2012 OTP requested approval from the SDPUC for an Environmental Cost Recovery Rider to recover costs associated with the Big Stone Plant AQCS, with a proposed effective date of October 1, 2012. This rider is designed to recover the revenue requirements plus carrying charges of the Big Stone AQCS project while under construction as well as after completion of the project until placed into base rates through the filing of a rate case. For the initial period of October 1, 2012 through September 30, 2013, OTP is requesting revenue requirement recovery on expenditures incurred for the Big Stone Plant AQCS. Information requests for this filing were received on July 13, 2012.

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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:

	June 30, 2012						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	7,047	$	91,808	$	98,855	see notes
Deferred Marked-to-Market Losses		6,952		11,175		18,127	38 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		2,456		3,724		6,180	24 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,895		3,895	asset lives
Big Stone II Unrecovered Project Costs – Minnesota		510		1,885		2,395	51 months
Debt Reacquisition Premiums		273		2,113		2,386	243 months
Accrued Cost-of-Energy Revenues		2,065		--		2,065	12 months
Deferred Income Taxes		--		2,018		2,018	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,007		960		1,967	21 months
Big Stone II Unrecovered Project Costs – North Dakota		1,388		157		1,545	13 months
North Dakota Renewable Resource Rider Accrued Revenues		1,264		79		1,343	21 months
North Dakota Transmission Rider Accrued Revenues		1,103		--		1,103	12 months
Big Stone II Unrecovered Project Costs – South Dakota		100		761		861	103 months
General Rate Case Recoverable Expenses		596		42		638	19 months
Minnesota Transmission Rider Accrued Revenue		208		--		208	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		156		--		156	5 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		126		--		126	6 months
Deferred Holding Company Formation Costs		55		55		110	24 months
South Dakota Transmission Rider Accrued Revenues		28		--		28	6 months
Total Regulatory Assets	$	25,334	$	118,672	$	144,006
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	64,996	$	64,996	asset lives
Deferred Income Taxes		--		2,961		2,961	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		114		120	258 months
South Dakota – Nonasset-Based Margin Sharing Excess		72		--		72	6 months
Deferred Marked-to-Market Gains		61		--		61	8 months
Total Regulatory Liabilities	$	139	$	68,071	$	68,210
Net Regulatory Asset Position	$	25,195	$	50,601	$	75,796

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	December 31, 2011						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	6,304	$	96,074	$	102,378	see notes
Deferred Marked-to-Market Losses		5,208		10,749		15,957	44 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		5,234		2,208		7,442	18 months
Accrued Cost-of-Energy Revenue		4,043		--		4,043	12 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,662		3,662	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,461		1,306		2,767	33 months
Big Stone II Unrecovered Project Costs – Minnesota		495		2,144		2,639	57 months
Debt Reacquisition Premiums		280		2,246		2,526	249 months
Deferred Income Taxes		--		2,382		2,382	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		1,340		862		2,202	19 months
North Dakota Renewable Resource Rider Accrued Revenues		785		1,325		2,110	24 months
General Rate Case Recoverable Expenses		721		285		1,006	25 months
Big Stone II Unrecovered Project Costs – South Dakota		100		811		911	109 months
North Dakota Transmission Rider Accrued Revenue		518		--		518	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		343		--		343	11 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		252		--		252	12 months
Deferred Holding Company Formation Costs		55		83		138	30 months
South Dakota – Asset-Based Margin Sharing Shortfall		138		--		138	2 months
South Dakota Transmission Rider Accrued Revenues		114		--		114	12 months
Total Regulatory Assets	$	27,391	$	124,137	$	151,528
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,610	$	65,610	asset lives
Deferred Income Taxes		--		3,379		3,379	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		117		123	264 months
Deferred Marked-to-Market Gains		96		--		96	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		54		--		54	12 months
Minnesota Transmission Rider Accrued Refund		28		--		28	see notes
Total Regulatory Liabilities	$	184	$	69,106	$	69,290
Net Regulatory Asset Position	$	27,207	$	55,031	$	82,238

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 June 30, 2012 are related to forward purchases of energy scheduled for delivery through August 2015.

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

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

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Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 243 months.

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

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 through June 30, 2012 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of June 30, 2012.

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.

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 June 30, 2012.

North Dakota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facility and net operating costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of June 30, 2012.

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. 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.

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

Minnesota Transmission Rider Accrued Revenue relates to revenues earned on qualifying transmission system facilities and net operating costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of June 30, 2012.

MISO Schedule 26 Transmission Cost Recovery Rider True-up relates to the Minnesota jurisdictional portion of MISO Schedule 26 for regional transmission cost recovery that was included in the calculation of the Minnesota Transmission Rider and subsequently adjusted to reflect actual billing amounts in the schedule.

South Dakota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facility and net operating costs incurred to serve South Dakota customers that have not been billed to South Dakota customers as of June 30, 2012.

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

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, Fair Value Measurement.

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 June 30, 2012 and December 31, 2011, and the change in the Company’s consolidated balance sheet position from December 31, 2011 to June 30, 2012 and December 31, 2010 to June 30, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Other Current Asset – Derivative Asset	$	2,402		$	3,803
Regulatory Asset – Current Deferred Marked-to-Market Loss		6,952			5,208
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		11,175			10,749
Total Assets		20,529			19,760
Derivative Liability		(20,337	)		(18,770	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(61	)		(96	)
Total Liabilities		(20,398	)		(18,866	)
Fair Value Adjustments Included in Earnings	$	131		$	894

(in thousands)	Year-to-Date June 30, 2012			Year-to-Date June 30, 2011
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	894		$	763
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(700	)		(151	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33	)		(86	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		161			526
Changes in Fair Value of Contracts Entered into in Current Period		(30	)		120
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	131		$	646

The recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on June 30, 2012 are expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	3rd Qtr 2012		4th Qtr 2012		1st Qtr 2013		Total
Net Gain	$	5	$	123	$	3	$	131

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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					Six Months Ended
	June 30,					June 30,
(in thousands)	2012			2011		2012		2011
Net Gains (Losses) on Forward Electric Energy Contracts	$	(50	)	$	139	$	144	$	131

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. The Company has 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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	860		8	$	1,677		10
Net Credit Risk to Single Largest Counterparty	$	348			$	737

OTP had a net credit risk exposure to eight counterparties with investment grade credit ratings. OTP had no exposure at June 30, 2012 or December 31, 2011 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The 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 June 30, 2012 and December 31, 2011:

Current Liability – Marked-to-Market Loss  (in thousands)	June 30, 2012			December 31, 2011
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	2,000		$	3,423
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		18,337			15,347
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	20,337		$	18,770
1Certain 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	$	18,337		$	15,347
Offsetting Gains with Counterparties under Master Netting Agreements		(2,355	)		(3,471	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	15,982		$	11,876

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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, 2011 through June 30, 2012:

Common Shares Outstanding, December 31, 2011	36,101,695
Issuances:
Restricted Stock Issued to Employees	24,500
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	21,150
Retirements:
Shares Withheld for Individual Income Tax Requirements	(5,072	)
Forfeiture of Unvested Restricted Stock	(1,825	)
Common Shares Outstanding, June 30, 2012	36,164,448

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 June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$24.93 – $31.34

Six Months Ended June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$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 16, 2012 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	$21.32	25% per year through April 8, 2016
Restricted Stock Granted to Executive Officers	24,500	$21.32	25% per year through April 8, 2016
Stock Performance Awards Granted to Executive Officers	80,800	$21.75	December 31, 2014
Restricted Stock Units Granted to Employees	12,800	$17.14	100% on April 8, 2016

The restricted shares granted to the Company’s nonemployee directors and executive officers 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 161,600 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, 2012 through December 31, 2014. The aggregate target share award is 80,800 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, 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 June 30, 2012 the remaining unrecognized compensation expense related to stock-based compensation was approximately $4.1 million (before income taxes) which will be amortized over a weighted-average period of 2.7 years.

Compensation expense recognized under the Company’s stock-based payment programs are presented in the table below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Employee Stock Purchase Plan (15% discount)	$	49	$	72	$	88	$	134
Restricted Stock Granted to Directors		138		195		274		387
Restricted Stock Granted to Employees		87		133		145		248
Restricted Stock Units Granted to Employees		51		70		105		153
Stock Performance Awards Granted to Executive Officers		293		--		293		--
Totals	$	618	$	470	$	905	$	922

8. Retained Earnings Restriction

The Company’s Restated Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders by the amount of any declared but unpaid dividends to holders of the Company’s cumulative preferred shares. Under these provisions none of the Company’s retained earnings were restricted at June 30, 2012.

25

9. Commitments and Contingencies

Construction Commitments

At December 31, 2011 OTP had commitments under contracts in connection with construction programs aggregating approximately $41.0 million for 2012. OTP’s share of additional commitments under contracts entered into in 2012 related to CapX2020 transmission projects, the Big Stone AQCS project, and a water handling project at Coyote Station increased its total construction commitments as of June 30, 2012 by $18.7 million for the remainder of 2012, $21.9 million for 2013, $4.2 million for 2014 and $19.5 million for 2015.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for capacity and energy requirements under agreements extending through 2032. OTP did not enter into any agreements for the purchase of additional capacity or energy to meet future capacity and energy requirements in the first six months of 2012.

OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP did not commit to any additional coal purchases in the first six months of 2012.

Commitment for Development of New Coal Source for Coyote Station

Coyote Station owners, including OTP, entered into an agreement on May 1, 2012 with the North American Coal Corporation for pre-commencement development work at Coyote Creek Mine near Coyote Station. OTP’s current share of the Coyote Station owners’ commitment to develop Coyote Creek Mine is for up to $0.9 million plus any interest or capital charges. All applicable development work is to be completed in 2012. If the lignite sales agreement (LSA) currently under negotiation is signed, the pre-contract development costs will be paid over a 52-month period starting in May 2016 when the first coal would be delivered under the LSA. If the LSA is not signed, the Coyote Station owners can terminate development activities and would be billed for all pre-contract costs incurred with payment due within 30 days of receipt of the invoice.

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 June 30, 2012 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 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 all of these items result in a liabilities being incurred, the loss could be as high as $7.0 million. Additionally, the Company may become subject to significant claims of which its management is unaware, or the claims of which its management is aware may result in the Company incurring a significantly greater liability than it anticipates.

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of June 30, 2012 and December 31, 2011:

(in thousands)	Line Limit		In Use on June 30, 2012		Restricted due to Outstanding Letters of Credit		Available on June 30, 2012		Available on December 31, 2011
Otter Tail Corporation Credit Agreement1	$	200,000	$	2,289	$	850	$	196,861	$	198,776
OTP Credit Agreement		170,000		8,985		3,050		157,965		165,950
Total	$	370,000	$	11,274	$	3,900	$	354,826	$	364,726
1   On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

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Long-Term Debt Retirement

In April 2012, ShoreMaster, Inc. (ShoreMaster), a wholly owned subsidiary of Varistar Corporation, exercised a purchase option on a building it had been leasing under a capital lease and paid off the remaining $2.8 million balance of its lease obligation.

The following tables provide a breakdown of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	8,985	$	--	$	2,289	$	11,274
Long-Term Debt:
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, 20171						50,000		50,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at June 30, 2012						1,808		1,808
Total	$	320,195	$	--	$	151,808	$	472,003
Less: Current Maturities1		--		--		50,170		50,170
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	101,634	$	421,829
Total Short-Term and Long-Term Debt (with current maturities)	$	329,180	$	--	$	154,093	$	483,273
1On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

December 31, 2011 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	--	$	--	$	--
Long-Term Debt:
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 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at December 31, 2011			$	2,868		1,889		4,757
Total	$	320,195	$	2,868	$	151,889	$	474,952
Less: Current Maturities		--		2,868		165		3,033
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	151,720	$	471,915
Total Short-Term and Long-Term Debt (with current maturities)	$	320,195	$	2,868	$	151,885	$	474,948

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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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	1,248		$	1,175		$	2,542		$	2,350
Interest Cost on Projected Benefit Obligation		3,125			3,175			6,233			6,350
Expected Return on Assets		(3,607	)		(3,538	)		(7,215	)		(7,075	)
Amortization of Prior-Service Cost		102			100			204			200
Amortization of Net Actuarial Loss		1,289			650			2,520			1,300
Net Periodic Pension Cost	$	2,157		$	1,562		$	4,284		$	3,125

Cash flows—The Company had a minimum pension plan funding requirement of $3,015,000 as of December 31, 2011, and made a discretionary plan contribution of $10,000,000 in January 2012. The Company is not required to make, and has not made, any additional contributions in 2012. The Company did not make a contribution to its pension plan in the six months ended June 30, 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 June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Service Cost—Benefit Earned During the Period	$	12	$	21	$	23	$	41
Interest Cost on Projected Benefit Obligation		369		408		739		816
Amortization of Prior-Service Cost		19		18		37		37
Amortization of Net Actuarial Loss		81		61		163		122
Net Periodic Pension Cost	$	481	$	508	$	962	$	1,016

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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	439		$	425		$	900		$	850
Interest Cost on Projected Benefit Obligation		869			850			1,750			1,700
Amortization of Transition Obligation		187			187			374			374
Amortization of Prior-Service Cost		53			50			105			100
Amortization of Net Actuarial Loss		368			213			759			426
Effect of Medicare Part D Expected Subsidy		(533	)		(525	)		(1,020	)		(1,050	)
Net Periodic Postretirement Benefit Cost	$	1,383		$	1,200		$	2,868		$	2,400

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 Cash Equivalents—The carrying amount approximates fair value because of the short-term maturity of those instruments.

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Long-Term Debt—The fair value of the Company’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820, Fair Value Measurement.

	June 30, 2012						December 31, 2011
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	--		$	--		$	14,652		$	14,652
Long-Term Debt (including current maturities)	$	(471,999	)	$	(532,927	)	$	(474,948	)	$	(528,074	)

15. Income Tax Expense – Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three and six month periods ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
(Loss) Income Before Income Taxes – Continuing Operations	$	(31,379	)	$	5,040		$	(21,591	)	$	11,491
Add Back Canadian Losses not Subject to Income Tax Benefits		917			3,283			1,368			6,780
(Loss) Income Before Income Taxes – Continuing Operations, Subject to Taxes		(30,462	)		8,323			(20,223	)		18,271
Income Tax (Benefit) Expense Computed at the Company’s Net Composite Federal and State Statutory Rate (39%)		(11,880	)		3,246			(7,887	)		7,126
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,831	)		(1,929	)		(3,818	)		(3,905	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			(676	)		--
Corporate Owned Life Insurance		(13	)		(178	)		(385	)		(266	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(149	)		(265	)		(371	)		(555	)
Medicare Part D Subsidy		(194	)		(169	)		(391	)		(361	)
Employee Stock Ownership Plan Dividend Deduction		(191	)		(190	)		(381	)		(384	)
Canadian Revenue Authority Audit Settlement		--			--			--			156
Investment Tax Credit		(180	)		(214	)		(360	)		(427	)
Other Items – Net		(55	)		(386	)		73			(231	)
Income Tax (Benefit) Expense – Continuing Operations	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153
Effective Income Tax Rate – Continuing Operations		46.2	%		(1.7	)%		65.7	%		10.0	%

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2012
Balance on January 1	$	12,138
Increases Related to Tax Positions for Prior Years		--
Uncertain Positions Resolved During Year		(8,354	)
Balance on June 30	$	3,784

The balance of unrecognized tax benefits as of June 30, 2012 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 30, 2012 is not expected to change significantly within the next six months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. No interest is accrued on tax uncertainties as of June 30, 2012.

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17. Discontinued Operations

On May 6, 2011, the Company completed the sale of IPH for approximately $87.0 million in cash, including $3.0 million deposited in an escrow account, of which $1.5 million was released to the Company in May 2012. In the second half of 2011, the IPH sales proceeds were reduced by $1.2 million related to a purchase price adjustment. On December 29, 2011 the Company completed the sale of Wylie, its trucking business, for approximately $25.0 million in cash. On January 18, 2012 the Company sold the assets of Aviva for $0.3 million in cash. On February 29, 2012 the Company sold DMS for $28.3 million in cash. Following are summary presentations of the results of discontinued operations for three and six month periods ended June 30, 2012 and 2011:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Operating Revenues	$	--		$	41,282		$	16,352		$	99,460
Operating Expenses		26			41,799			14,928			99,343
Operating (Loss) Income		(26	)		(517	)		1,424			117
Interest Charges		--			11			147			31
Other Income		--			1,259			122			1,416
Income Tax (Benefit) Expense		(11	)		280			573			568
Net (Loss) Income from Operations		(15	)		451			826			934
(Loss) Gain on Disposition Before Taxes		(490	)		16,767			(3,713	)		16,767
Income Tax (Benefit) Expense on Disposition		(35	)		3,515			(169	)		3,515
Net (Loss) Gain on Disposition		(455	)		13,252			(3,544	)		13,252
Net (Loss) Income	$	(470	)	$	13,703		$	(2,718	)	$	14,186

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Current Assets	$	521		$	29,320
Net Plant		--			372
Assets of Discontinued Operations	$	521		$	29,692
Current Liabilities	$	236		$	14,740
Deferred Income Taxes		(232	)		(1,811	)
Deferred Credits - Other		--			119
Long-Term Debt		--			715
Liabilities of Discontinued Operations	$	4		$	13,763

18. Subsequent Events

Early Repayment of Debt

On July 13, 2012 the Company prepaid in full its outstanding $50 million, 8.89% Senior Unsecured Note due November 30, 2017 (the Cascade Note) issued pursuant to the Note Purchase Agreement dated as of February 23, 2007, as amended, between the Company and Cascade Investment, L.L.C. (Cascade). Immediately before the prepayment, the Cascade Note bore interest at 8.89% annually. The price paid by the Company to prepay the Cascade Note was $63,031,000, which included the principal amount of the Cascade Note plus accrued interest of $531,000 and a negotiated prepayment premium of $12,500,000. The Company used funds available under the Otter Tail Corporation Credit Agreement for the prepayment. This early retirement reflects the Company’s desire to lower its long-term debt outstanding given its recent divestitures and its anticipated divestiture of DMI. On repayment, $606,000 in unamortized debt expense related to this note was immediately recognized as expense along with the $12,500,000 negotiated prepayment premium, which will reduce diluted earnings per share by $0.22 in 2012. The $50,000,000 of debt retired on July 13, 2012 was included in current maturities of long-term debt on the Company’s June 30, 2012 consolidated balance sheet. Cascade owned approximately 9.6% of the Company’s outstanding common stock as of December 31, 2011.

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

RESULTS OF OPERATIONS

Following is an analysis of our operating results by business segment for the three and six month periods ended June 30, 2012 and 2011, followed by a discussion of changes in our consolidated financial position during the six months ended June 30, 2012 and our business outlook for the remainder of 2012.

Comparison of the Three Months Ended June 30, 2012 and 2011

Consolidated operating revenues were $283.7 million for the three months ended June 30, 2012 compared with $283.3 million for the three months ended June 30, 2011. Operating loss was $23.6 million for the three months ended June 30, 2012 compared with operating income of $13.4 million for the three months ended June 30, 2011. The Company recorded diluted earnings per share from continuing operations of ($0.48) for the three months ended June 30, 2012 compared to $0.14 for the three months ended June 30, 2011 and total diluted earnings per share of ($0.49) for the three months ended June 30, 2012 compared to $0.51 for the three months ended June 30, 2011.

Asset Impairment Charge—We entered into a nonbinding letter of interest in June 2012 to sell the property, plant and equipment of DMI Industries, Inc. (DMI) for $20 million, while retaining DMI’s net working capital—approximately $66 million on June 30, 2012. The transaction is expected to close no later than January 3, 2013. The market value for DMI’s assets has been significantly impacted by reduced demand for wind towers due to adverse market conditions affecting the industry, including uncertainty regarding renewal or extension of the Federal Production Tax Credit (PTC) for investments in renewable energy resources, which is set to expire at the end of 2012. Based on our second quarter 2012 decision to divest DMI’s assets and the price for the fixed assets agreed to in the nonbinding letter of interest, DMI recorded a noncash asset impairment charge of $45.6 million ($27.5 million net-of-tax), or $0.76 per share, in the second quarter of 2012 broken down as follows:

(in thousands)
Long-Lived Assets	$	90,846
Accumulated Depreciation – Long-lived Assets		(45,561	)
Goodwill		288
Total Asset Impairment Charge	$	45,573

Under the terms of the nonbinding letter of interest, DMI must complete its current backlog of towers ordered for delivery in 2012 before closing can occur. Under these circumstances, accounting rules require that DMI’s assets and results of operations continue to be reported as continuing operations. However, on completion of all remaining tower orders, DMI’s assets will be considered available for immediate sale and we expect DMI’s results and any remaining assets will be reported as discontinued operations at the end of 2012. Should the transaction not be completed, we plan to close DMI’s plants in West Fargo, North Dakota and Tulsa, Oklahoma and sell DMI’s fixed assets, after DMI finishes its backlog of orders for 2012.

Intersegment Eliminations—Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended June 30, 2012 and 2011 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)	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011
Operating Revenues:
Electric	$	54	$	53
Nonelectric		823		531
Cost of Goods Sold		830		557
Other Nonelectric Expenses		47		27

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Electric

	Three Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Retail Sales Revenue	$	68,719	$	67,702	$	1,017			1.5
Wholesale Revenue – Company Generation		2,028		3,563		(1,535	)		(43.1	)
Net Revenue – Energy Trading Activity		561		750		(189	)		(25.2	)
Other Revenue		7,655		6,016		1,639			27.2
Total Operating Revenues	$	78,963	$	78,031	$	932			1.2
Production Fuel		12,455		17,080		(4,625	)		(27.1	)
Purchased Power – System Use		12,328		7,894		4,434			56.2
Other Operation and Maintenance Expenses		32,407		28,687		3,720			13.0
Depreciation and Amortization		10,447		10,020		427			4.3
Property Taxes		2,670		2,417		253			10.5
Operating Income	$	8,656	$	11,933	$	(3,277	)		(27.5	)

	Three Months Ended
	June 30,							%
Electric kwh Sales (in thousands)	2012		2011		Change			Change
Retail kilowatt-hour (kwh) Sales		907,529		951,527		(43,998	)		(4.6	)
Wholesale kwh Sales – Company Generation		71,364		147,799		(76,435	)		(51.7	)
Wholesale kwh Sales – Purchased Power Resold		58,632		29,481		29,151			98.9

The $1.0 million increase in retail sales revenue reflects the following:

● a $1.8 million increase in revenue mainly related to rate design changes implemented in Minnesota in October 2011 on finalization of Otter Tail Power Company’s (OTP) 2010 general rate case,

● a $1.0 million increase in revenue related to the recovery of an increase in the average cost of fuel and purchased power per kwh incurred to serve retail customers, and

● a $0.7 million increase in transmission costs recovery rider revenue as a result of increased investment in transmission assets,

offset by:

● a $2.5 million decrease in revenue, mainly due to a 4.6% reduction in retail kwh sales primarily resulting from significantly milder weather in the second quarter of 2012 as heating degree days were down 28.0% compared with the second quarter of 2011.

Wholesale electric revenue from company-owned generation decreased $1.5 million as a result of a 51.7% decrease in wholesale kwh sales. Lower wholesale demand due to milder weather drove wholesale prices down, reducing opportunities to sell competitively in wholesale markets. Additionally, OTP’s plant availability was reduced in the second quarter of 2012 as Coyote Station, OTP’s lowest fuel-cost plant, was shut down for seven weeks of scheduled maintenance and Big Stone Plant had a 10-day spring maintenance outage, resulting in a 34.9% reduction in kwhs generated from OTP’s steam-powered and combustion turbine generators.

Other electric operating revenue increased $1.6 million mainly as a result of an increase in transmission tariff revenues, due, in part, to revenues from CapX2020 transmission project investments.

Fuel costs decreased $4.6 million as a result of the 34.9% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators, partially offset by a 12.0% increase in the cost of fuel per kwh generated. Generation levels decreased in response to lower demand due to mild weather and because of scheduled plant maintenance outages. The cost of purchased power for retail sales increased $4.4 million as a result of a 121% increase in kwhs purchased, partially offset by a 29.2% decrease in the cost per kwh purchased. The increase in kwhs purchased was mainly due to the reduced availability of OTP’s steam-powered generators.

32

Electric operating and maintenance expenses increased $3.7 million due to the following:

● a $1.8 million increase in generation plant maintenance costs mainly related to the seven-week scheduled maintenance shutdown of Coyote Station in the second quarter of 2012,

● a $1.2 million increase in employee benefit expenses mainly due to increases in postretirement benefit costs resulting from a reduction in the discount rate related to projected benefit obligations, and

● a $0.7 million increase in Midwest Independent Transmission System Operator (MISO) Schedule 26 transmission service charges.

The $0.4 million increase in Electric segment depreciation expense is related to 2011 property additions. The $0.3 million increase in property taxes is due to higher taxes on electric distribution property along with increased investments in transmission property.

Wind Energy

	Three Months Ended
	June 30,									%
(in thousands)	2012			2011			Change			Change
Revenues	$	62,618		$	55,025		$	7,593			13.8
Cost of Goods Sold		51,990			56,012			(4,022	)		(7.2	)
Operating Expenses		2,209			3,116			(907	)		(29.1	)
Asset Impairment Charge		45,573			--			45,573			--
Depreciation and Amortization		2,073			2,798			(725	)		(25.9	)
Operating Loss	$	(39,227	)	$	(6,901	)	$	(32,326	)		(468.4	)

Revenues at DMI’s U.S. plants increased $16.7 million due to an 8.8% increase in towers produced at those facilities, while cost of goods sold increased by only $6.8 million at those locations as a result of productivity improvements, cost controls and the implementation of quality control measures that eliminated the need for outsourced quality assurance staffing. Revenues and cost of goods sold at DMI’s Canadian plant were down $9.1 million and $10.8 million, respectively, as a result of the idling of plant in the fourth quarter of 2011 due to a reduction in tower orders. DMI’s operating expenses decreased $0.6 million at its idled Canadian plant. At DMI’s other locations, operating expenses decreased $0.3 million as a result of lower salary and benefit expenses, due to staff reductions, and reduced maintenance expenses. As described above, DMI recorded a noncash asset impairment charge of $45.6 million in the second quarter of 2012 as a result of writing down its fixed assets to an indicated market value of $20.0 million.Depreciation expense decreased mainly as a result of the impairment of assets in Canada in 2011.

Manufacturing

	Three Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Revenues	$	63,581	$	57,320	$	6,261			10.9
Cost of Goods Sold		48,203		42,458		5,745			13.5
Operating Expenses		6,805		6,051		754			12.5
Depreciation and Amortization		3,219		3,232		(13	)		(0.4	)
Operating Income	$	5,354	$	5,579	$	(225	)		(4.0	)

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 $7.1 million as a result of higher sales volume due to improved customer demand.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased by $0.8 million due to increased sales of industrial and medical packaging products.

33

● Revenues at ShoreMaster, Inc. (ShoreMaster), our waterfront equipment business, decreased $1.6 million, reflecting a $1.3 million decrease in commercial sales and a $0.3 million decrease in residential sales.

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

● Cost of goods sold at BTD increased $6.3 million mainly as a result of increased sales volume.

● Cost of goods sold at T.O. Plastics increased $0.6 million as a result of costs associated with the increase in sales of industrial and medical packaging products, offset by a $0.3 million decrease in costs related to improved productivity and efficiencies and more selective bidding practices.

● Cost of goods sold at ShoreMaster decreased $0.8 million as a result of a $0.4 million decrease in costs related to the reduction in product sales combined with $0.4 million in productivity losses mainly related to costs incurred to relocate ShoreMaster’s commercial production operations in Camdenton, Missouri to its Fergus Falls, Minnesota and St. Augustine, Florida locations.

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

● Operating expenses at BTD increased $0.7 million mainly due to increased benefit expenses related to employee incentives.

● Operating expenses at T.O. Plastics were unchanged between the quarters.

● Operating expenses at ShoreMaster increased $0.1 million between the quarters.

Construction

	Three Months Ended
	June 30,								%
(in thousands)	2012			2011		Change			Change
Operating Revenues	$	37,934		$	49,133	$	(11,199	)		(22.8	)
Cost of Goods Sold		36,992			45,108		(8,116	)		(18.0	)
Operating Expenses		3,030			3,015		15			0.5
Depreciation and Amortization		470			495		(25	)		(5.1	)
Operating (Loss) Income	$	(2,558	)	$	515	$	(3,073	)		(596.7	)

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

● Revenues at Foley Company, a mechanical and prime contractor on industrial projects, decreased $15.4 milliondue to a decrease in work volume and the effect of cost overruns on estimated revenues recognized under percentage-of-completion accounting.

● Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, increased $4.2 million as a result of an increase in electrical transmission, distribution and substation work facilitated by better weather and improved access to construction sites in the second quarter of 2012 compared with the second quarter of 2011.

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

● Cost of goods sold at Foley Company decreased $11.0 million, mainly in material and subcontractor costs due to a decrease in work volume.

● Cost of goods sold at Aevenia increased $2.9 million between the quarters as a result of the increase in electrical transmission, distribution and substation work completed in the second quarter of 2012.

34

Plastics

	Three Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Revenues	$	41,490	$	44,373	$	(2,883	)		(6.5	)
Cost of Goods Sold		31,257		36,220		(4,963	)		(13.7	)
Operating Expenses		2,328		1,436		892			62.1
Depreciation and Amortization		785		864		(79	)		(9.1	)
Operating Income	$	7,120	$	5,853	$	1,267			21.6

Operating revenues for the Plastics segment decreased as result of a 12.3% decrease in pounds of polyvinyl chloride (PVC) pipe sold, partially offset by a 6.6% increase in the price per pound of pipe sold. The decrease in costs of goods sold was related to the decrease in pounds of pipe sold in combination with a 1.6% decrease in the cost per pound of PVC pipe sold between the quarters. The increase in operating expenses in the Plastics segment is mainly due to increased benefit expenses for employee incentives related to improved operating results.

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
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Expenses	$	2,864	$	3,423	$	(559	)		(16.3	)
Depreciation and Amortization		124		143		(19	)		(13.2	)

The decrease in corporate operating expenses reflects reductions in salary and benefit costs and expenditure for external services, insurance and public relations between the quarters.

Interest Charges

Interest charges decreased $0.7 million in the second quarter of 2012 compared with the second quarter of 2011, mainly as a result of a $65.9 million decrease in the average daily balance of short-term debt outstanding between the quarters.

35

Income Taxes – Continuing Operations

Income tax benefit - continuing operations increased $14.4 million in the three months ended June 30, 2012 compared with the three months ended June 30, 2011. The following table provides a reconciliation of income tax expense calculated at the Company’s net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three month periods ended June 30, 2012 and 2011:

	Three Months Ended June 30,
(in thousands)	2012			2011
(Loss) Income Before Income Taxes – Continuing Operations	$	(31,379	)	$	5,040
Add Back Canadian Losses not Subject to Income Tax Benefits		917			3,283
(Loss) Income Before Income Taxes – Continuing Operations, Subject to Taxes		(30,462	)		8,323
Income Tax (Benefit) Expense Computed at the Company’s Net Composite Federal and State Statutory Rate (39%)		(11,880	)		3,246
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,831	)		(1,929	)
Corporate Owned Life Insurance		(13	)		(178	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(149	)		(265	)
Medicare Part D Subsidy		(194	)		(169	)
Employee Stock Ownership Plan Dividend Deduction		(191	)		(190	)
Investment Tax Credit		(180	)		(214	)
Other Items - Net		(55	)		(386	)
Income Tax (Benefit) – Continuing Operations	$	(14,493	)	$	(85	)
Effective Income Tax Rate – Continuing Operations		46.2	%		(1.7	)%

Due to cumulative losses in the Canadian operations of DMI, we have no tax liability from taxable income in Canada to offset with income tax benefits on losses, therefore, we record no tax benefit related to the losses of our Canadian operations. Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Discontinued Operations

In the second quarter of 2011, we sold Idaho Pacific Holdings, Inc. (IPH), our food ingredient processing company, and in the fourth quarter of 2011 we sold E.W. Wylie Corporation (Wylie), our trucking business. On January 18, 2012 ShoreMaster completed the sale of the assets of its wholly owned subsidiary, Aviva Sports, Inc. (Aviva), and on February 29, 2012 we completed the sale of DMS Health Technologies Inc. (DMS), our health services business. The financial position, results of operations and cash flows of IPH, Wylie, Aviva and DMS are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the three months ended June 30, 2012 and 2011:

	For the Three Months Ended June 30,
(in thousands)	2012			2011
Operating Revenues	$	--		$	41,282
Operating Expenses		26			41,799
Operating Loss		(26	)		(517	)
Interest Charges		--			11
Other Income		--			1,259
Income Tax (Benefit) Expense		(11	)		280
Net (Loss) Income from Operations		(15	)		451
(Loss) Gain on Disposition Before Taxes		(490	)		16,767
Income Tax (Benefit) Expense on Disposition		(35	)		3,515
Net (Loss) Gain on Disposition		(455	)		13,252
Net (Loss) Income	$	(470	)	$	13,703

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Comparison of the Six Months Ended June 30, 2012 and 2011

Consolidated operating revenues were $561.3 million for the six months ended June 30, 2012 compared with $532.4 million for the six months ended June 30, 2011. Operating loss was $6.2 million for the six months ended June 30, 2012 compared with operating income of $29.0 million for the six months ended June 30, 2011. The Company recorded diluted earnings per share from continuing operations of ($0.22) for the six months ended June 30, 2012 compared to $0.28 for the six months ended June 30, 2011 and total diluted earnings per share of ($0.29) for the six months ended June 30, 2012 compared to $0.66 for the six months ended June 30, 2011.

Asset Impairment Charge—The DMI second quarter 2011 asset impairment described above resulted in a $45.6 million noncash asset impairment charge ($27.5 million, net-of-tax benefits), or $0.76 per share, in the six month period ended June 30, 2012.

Intersegment Eliminations—Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the six month periods ended June 30, 2012 and 2011 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)	Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Operating Revenues:
Electric	$	119	$	123
Nonelectric		1,760		1,251
Cost of Goods Sold		1,775		1,100
Other Nonelectric Expenses		104		274

Electric

	Six Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Retail Sales Revenue	$	150,141	$	150,605	$	(464	)		(0.3	)
Wholesale Revenue – Company Generation		4,107		6,299		(2,192	)		(34.8	)
Net Revenue – Energy Trading Activity		973		978		(5	)		(0.5	)
Other Revenue		13,745		11,745		2,000			17.0
Total Operating Revenues	$	168,966	$	169,627	$	(661	)		(0.4	)
Production Fuel		27,879		36,657		(8,778	)		(23.9	)
Purchased Power – System Use		26,486		20,271		6,215			30.7
Other Operation and Maintenance Expenses		62,420		57,395		5,025			8.8
Asset Impairment Charge		432		--		432			--
Depreciation and Amortization		20,847		20,059		788			3.9
Property Taxes		5,287		4,826		461			9.6
Operating Income	$	25,615	$	30,419	$	(4,804	)		(15.8	)

	Six Months Ended
	June 30,							%
Electric kwh Sales (in thousands)	2012		2011		Change			Change
Retail kwh Sales		2,112,134		2,257,650		(145,516	)		(6.4	)
Wholesale kwh Sales – Company Generation		166,755		246,056		(79,301	)		(32.2	)
Wholesale kwh Sales – Purchased Power Resold		65,032		92,733		(27,701	)		(29.9	)

The $0.5 million decrease in retail sales revenue reflects the following:

● a $5.7 million decrease in revenue, mainly due to a 6.4% reduction in retail kwh sales resulting from significantly milder weather in the first half of 2012 as heating degree days were down 27.8% compared with the first half of 2011,

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● a $2.1 million decrease in revenue related to the recovery of fuel and purchased power costs, and

● a $1.5 million reduction in accrued conservation program cost recovery revenue related to the timing of the recognition of conservation costs and incentives recovered through the Minnesota Conservation Improvement Program surcharge,

offset by:

● a $4.9 million increase in revenue related to rate design changes implemented in Minnesota in October 2011 on finalization of OTP’s 2010 general rate case,

● a $2.1 million increase in transmission costs recovery rider revenue as a result of increased investment in transmission assets, and

● a $1.8 million revenue reduction in the first half of 2011 related to accruing a refund for a portion of revenues collected under interim rates in 2010 during OTP’s most recent Minnesota rate case.

Wholesale electric revenue from company-owned generation decreased $2.2 million as a result of a 32.2% decrease in wholesale kwh sales. Lower wholesale demand due to milder weather drove wholesale prices down, reducing opportunities to sell competitively in wholesale markets. Additionally, OTP’s plant availability was reduced in the second quarter of 2012 as Coyote Station, OTP’s lowest fuel-cost plant, was shut down for seven weeks of scheduled maintenance and Big Stone Plant had a 10-day spring maintenance outage, resulting in a 28.9% reduction in kwhs generated from OTP’s steam-powered and combustion turbine generators between the periods.

Other electric operating revenue increased $2.0 million as a result of:

● a $3.9 million increase in transmission tariff revenues due, in part, to revenues from CapX2020 transmission project investments, and

● a 0.3 million increase in other miscellaneous services revenue,

offset by:

● a reduction in revenue related to the sale of access rights through an Otter Tail Energy Services Company (OTESCO) wind farm development site in the first quarter of 2011 for $1.1 million, and

● a $1.1 million reduction in revenues from steam sales at Big Stone Plant to a nearby ethanol plant as a result of the customer generating more of its own steam from its natural gas fired boiler in response to low natural gas prices.

Fuel costs decreased $8.8 million as a result of the 28.9% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators, partially offset by a 6.9% increase in the cost of fuel per kwh generated. Generation levels decreased in response to lower demand due to mild weather and because of scheduled plant maintenance outages. The cost of purchased power for retail sales increased $6.2 million as a result of a 57.4% increase in kwhs purchased, partially offset by a 17.0% decrease in the cost per kwh purchased. The increase in kwhs purchased was mainly due to the reduced availability of OTP’s steam-powered generators.

Electric operating and maintenance expenses increased $5.0 million due to the following:

● a $2.0 million increase in employee benefit expenses mainly due to increases in pension and retirement health benefit costs resulting from a reduction in the discount rate related to projected benefit obligations,

● a $1.6 million increase in MISO transmission service charges, mainly Schedule 26 charges,

● a $1.1 million increase in maintenance expenses at Coyote Station related to its second quarter 2012 seven-week scheduled major maintenance shutdown,

● a $0.8 million increase in maintenance costs at Big Stone Plant,

● a $0.4 million increase in vegetation management expenses, and

● a $0.3 million increase in bad debt expense related to a reduction in the allowance for uncollectible accounts in the first quarter of 2011, resulting in a decrease in bad debt expense in that period,

offset by:

● a $1.2 million reduction in incurred conservation program costs, commensurate with a reduction in accrued revenues related to the future recovery of those costs.

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OTESCO recorded an additional $0.4 million asset impairment charge related to its wind farm development rights at its Sheridan Ridge and Stutsman County sites in North Dakota as a potential sale of the rights did not occur as expected in the first quarter of 2012. The $0.8 million increase in Electric segment depreciation expense is related to 2011 property additions. The $0.5 million increase in property taxes is due to higher taxes on electric distribution property along with increased investments in transmission and distribution property.

Wind Energy

	Six Months Ended
	June 30,									%
(in thousands)	2012			2011			Change			Change
Revenues	$	114,720		$	102,013		$	12,707			12.5
Cost of Goods Sold		99,574			103,896			(4,322	)		(4.2	)
Operating Expenses		3,787			5,594			(1,807	)		(32.3	)
Asset Impairment Charge		45,573			--			45,573			--
Depreciation and Amortization		4,155			5,310			(1,155	)		(21.8	)
Operating Loss	$	(38,369	)	$	(12,787	)	$	(25,582	)		(200.1	)

Revenues at DMI’s U.S. plants increased $33.1 million due to a 13.9% increase in towers produced at those facilities, while cost of goods sold increased by only $19.7 million at those locations as a result of productivity improvements, cost controls and the implementation of quality control measures that eliminated the need for outsourced quality assurance staffing. Revenues and cost of goods sold at DMI’s Canadian plant were down $20.4 million and $24.0 million, respectively, as a result of the idling of plant in the fourth quarter of 2011 due to a reduction in tower orders. DMI’s operating expenses decreased $1.2 million at its idled Canadian plant. At DMI’s other locations, operating expenses decreased $0.6 million as a result of lower salary and benefit expenses, due to staff reductions, and reduced maintenance and travel expenses. As described above, DMI recorded a noncash asset impairment charge of $45.6 million in the second quarter of 2012 as a result of writing down its fixed assets to an indicated market value of $20.0 million.Depreciation expense decreased mainly as a result of the impairment of assets in Canada in 2011.

Manufacturing

	Six Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Revenues	$	129,575	$	112,681	$	16,894			15.0
Cost of Goods Sold		98,914		84,447		14,467			17.1
Operating Expenses		13,891		10,599		3,292			31.1
Depreciation and Amortization		6,415		6,402		13			0.2
Operating Income	$	10,355	$	11,233	$	(878	)		(7.8	)

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

● Revenues at BTD increased $19.0 million as a result of higher sales volume due to improved customer demand.

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

● Revenues at ShoreMaster decreased $3.4 million, reflecting a $3.8 million decrease in commercial sales, partially offset by a $0.4 million increase in residential sales.

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

● Cost of goods sold at BTD increased $15.4 million as a result of increased sales volume.

● Cost of goods sold at T.O. Plastics increased $0.9 million as a result of costs associated with the increase in sales of industrial and medical packaging products, offset by a $0.5 million decrease in costs related to improved productivity and efficiencies.

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● Cost of goods sold at ShoreMaster decreased $1.4 million as a result of a $2.2 million decrease in costs related to the reduction in product sales, offset by $0.8 million in severance and relocation costs incurred in 2012 related to shutting down ShoreMaster’s commercial production operations in Camdenton, Missouri and moving parts and equipment to its Fergus Falls, Minnesota and St. Augustine, Florida locations.

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

● Operating expenses at BTD increased $2.0 million mainly due to increased benefit expenses related to employee incentives, but also due to increased salary and benefit expenses related to workforce expansion and increases in expenditures for contracted services, insurance and advertising.

● Operating expenses at T.O. Plastics decreased $0.1 million between the periods.

● Operating expenses at ShoreMaster increased $1.4 million, reflecting a $0.5 million increase in expenses for outside professional services, a first quarter 2011 expense reduction of $0.7 million from the collection of a receivable written off as uncollectible prior to 2011, and a $0.2 million gain on a first quarter 2011 asset sale.

Construction

	Six Months Ended
	June 30,								%
(in thousands)	2012			2011		Change			Change
Operating Revenues	$	73,551		$	86,648	$	(13,097	)		(15.1	)
Cost of Goods Sold		75,685			79,397		(3,712	)		(4.7	)
Operating Expenses		6,310			6,121		189			3.1
Depreciation and Amortization		904			940		(36	)		(3.8	)
Operating (Loss) Income	$	(9,348	)	$	190	$	(9,538	)		--

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

● Revenues at Foley Company decreased $22.5 million, due to a decrease in work volume and the effect of cost overruns on estimated revenues recognized under percentage-of-completion accounting.

● Revenues at Aevenia increased $9.4 million between the periods as a result an increase in electrical transmission, distribution and substation work facilitated by better weather and improved access to construction sites in the first half of 2012 compared with the first half of 2011.

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

● Cost of goods sold at Foley Company decreased $11.3 million, mainly in material and subcontractor costs due to a decrease in work volume between periods.

● Cost of goods sold at Aevenia increased $7.6 million between the periods as a result of the increase in electrical transmission, distribution and substation work performed in the first half of 2012.

The increase in operating expenses in our Construction segment mainly reflects increases in outside service expenses at Foley.

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Plastics

	Six Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Revenues	$	76,365	$	62,851	$	13,514			21.5
Cost of Goods Sold		58,204		52,940		5,264			9.9
Operating Expenses		3,691		2,657		1,034			38.9
Depreciation and Amortization		1,598		1,667		(69	)		(4.1	)
Operating Income	$	12,872	$	5,587	$	7,285			130.4

Operating revenues for the Plastics segment increased as result of a 10.9% increase in pounds of PVC pipe sold combined with a 9.6% increase in the price per pound of pipe sold. The increase in costs of goods sold was related to the increase in pounds of pipe sold slightly offset by a 0.9% decrease in the cost per pound of PVC pipe sold. The increase in operating expenses in the Plastics segment is mainly due to increased benefit expenses for employee incentives related to improved operating results, but also reflects increases in salaries and commissions related to the increase in sales volume.

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.

	Six Months Ended
	June 30,							%
(in thousands)	2012		2011		Change			Change
Operating Expenses	$	7,105	$	5,393	$	1,712			31.7
Depreciation and Amortization		252		280		(28	)		(10.0	)

The increase in corporate operating expenses mainly is due to higher employee benefit costs and increased costs for insurance programs and outside services.

Interest Charges

Interest charges decreased $1.5 million in the first six months of 2012 compared with the first six months of 2011, mainly as a result of an $80.6 million decrease in the average daily balance of short-term debt outstanding between the periods.

Other Income

The increase in other income of $0.6 million in the six months ended June 30, 2012 compared with the six months ended June 30, 2011 includes a $0.2 million decrease in foreign currency transaction losses in the Canadian operations of DMI, an increase of $0.2 million in allowance for equity funds used during construction and other miscellaneous revenues at OTP and a $0.1 million increase in the cash surrender value of corporate-owned life insurance policies.

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Income Taxes – Continuing Operations

Income taxes - continuing operations decreased $15.3 million in the six months ended June 30, 2012 compared with the six months ended June 30, 2011. The following table provides a reconciliation of income tax expense calculated at the Company’s net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the six months ended June 30, 2012 and 2011:

	Six Months Ended June 30,
(in thousands)	2012			2011
(Loss) Income Before Income Taxes – Continuing Operations	$	(21,591	)	$	11,491
Add Back Canadian Losses not Subject to Income Tax Benefits		1,368			6,780
(Loss) Income Before Income Taxes – Continuing Operations, Subject to Taxes		(20,223	)		18,271
Income Tax (Benefit) Expense Computed at the Company’s Net Composite Federal and State Statutory Rate (39%)		(7,887	)		7,126
Increases (Decreases) in Tax from:
Federal PTCs		(3,818	)		(3,905	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		(676	)		--
Corporate Owned Life Insurance		(385	)		(266	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(371	)		(555	)
Medicare Part D Subsidy		(391	)		(361	)
Employee Stock Ownership Plan Dividend Deduction		(381	)		(384	)
Canadian Revenue Authority Audit Settlement		--			156
Investment Tax Credit		(360	)		(427	)
Other Items - Net		73			(231	)
Income Tax (Benefit) Expense – Continuing Operations	$	(14,196	)	$	1,153
Effective Income Tax Rate – Continuing Operations		65.7	%		10.0	%

Due to cumulative losses in the Canadian operations of DMI, we have no tax liability from taxable income in Canada to offset with income tax benefits on losses, therefore, we record no tax benefit related to the losses of our Canadian operations. Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Discontinued Operations

In the second quarter of 2011, we sold IPH, our food ingredient processing company, and in the fourth quarter of 2011 we sold Wylie, our trucking business. On January 18, 2012 ShoreMaster completed the sale of the assets of its wholly owned subsidiary, Aviva, and on February 29, 2012 we completed the sale of DMS, our health services business. The financial position, results of operations, and cash flows of IPH, Wylie, Aviva and DMS are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the six months ended June 30, 2012 and 2011:

	For the Six Months Ended June 30,
(in thousands)	2012			2011
Operating Revenues	$	16,352		$	99,460
Operating Expenses		14,928			99,343
Operating Income		1,424			117
Interest Charges		147			31
Other Income		122			1,416
Income Tax Expense		573			568
Net Income from Operations		826			934
(Loss) Gain on Disposition Before Taxes		(3,713	)		16,767
Income Tax (Benefit) Expense on Disposition		(169	)		3,515
Net (Loss) Gain on Disposition		(3,544	)		13,252
Net (Loss) Income	$	(2,718	)	$	14,186

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FINANCIAL POSITION

The following table presents the status of our lines of credit as of June 30, 2012 and December 31, 2011:

(in thousands)	Line Limit		In Use on June 30, 2012		Restricted due to Outstanding Letters of Credit		Available on June 30, 2012		Available on December 31, 2011
Otter Tail Corporation Credit Agreement	$	200,000	$	2,289	$	850	$	196,861	$	198,776
OTP Credit Agreement		170,000		8,985		3,050		157,965		165,950
Total	$	370,000	$	11,274	$	3,900	$	354,826	$	364,726

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

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 11, 2012 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 May 14, 2012 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 2012 through 2016 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. 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 common stock dividend payments have exceeded our net (losses) income in each of the last four 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 was a party to a $40 million receivables sales agreement whereby designated customer accounts receivable were sold to General Electric Capital Corporation on a revolving basis. Accounts receivable totaling $32.1 million were sold in the first four months of 2012. 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. This agreement was terminated effective April 26, 2012.

Cash provided by operating activities from continuing operations was $44.1 million for the six months ended June 30, 2012 compared with $29.1 million for the six months ended June 30, 2011. The $15.0 million increase in cash provided by operating activities from continuing operations reflects a decrease in net income of $34.6 million, offset by $46.0 million in noncash asset impairment charges and a $5.0 million reduction in cash used for working capital items between the periods.

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Net cash used in investing activities of continuing operations was $64.2 million for the six months ended June 30, 2012 compared to $37.6 million for the six months ended June 30, 2011. An increase in cash used for capital expenditures at the electric utility of $32.5 million, mainly related to expenditures for CapX2020 transmission line construction projects, was partially offset by decreases in cash used for capital expenditures at all of our nonelectric operating companies totaling $2.9 million. Net proceeds from the sale of discontinued operations of $24.3 million in the first half of 2012, which were used to pay down short-term borrowings and for other corporate purposes, reflect proceeds, net of selling costs, of $24.0 million from the sale of DMS and $0.3 million from the sale of Aviva’s assets. Net cash used in investing activities of discontinued operations of $11.7 million in the first half of 2012 reflects cash used by DMS to purchase assets held under operating leases. Net cash used in investing activities of discontinued operations of $13.5 million in the first half of 2011 mainly reflects cash used by DMS to purchase assets held under operating leases.

Net cash used in financing activities from continuing operations decreased $66.8 million in the six months ended June 30, 2012 compared with the six months ended June 30, 2011 mainly due to a $70.0 million net increase in short-term borrowings and checks issued in excess of cash between the periods. We also issued $2.0 million in long-term debt and paid $0.7 million in short-term and long-term debt issuance expenses in the first six months of 2011. ShoreMaster paid $2.8 million to buy out a capital lease in the second quarter of 2012.

Our contractual obligations under other purchase obligations reported in the table on page 54 of our Annual Report on Form 10-K for the year ended December 31, 2011 have increased by $18.7 million for 2012, $26.1 million for 2013 and 2014, and $19.5 million for 2015 and 2016, for contracts related to the construction of CapX2020 transmission projects, a new air quality control system at Big Stone Plant in South Dakota, and a water handling project at Coyote Station in North Dakota.

Under its amended and restated credit agreement (the OTP Credit Agreement) OTP has available a $170 million line of credit with an accordion feature whereby the line can 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 this line of credit bear interest at LIBOR plus 1.5%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. 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 contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 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 the borrower’s credit ratings. The OTP Credit Agreement expires on March 3, 2016.

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

In April 2012, ShoreMaster exercised a purchase option on a building it had been leasing under a capital lease and paid off the remaining $2.8 million balance of its lease obligation.

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On July 13, 2012 we prepaid in full our outstanding $50 million, 8.89% Senior Unsecured Note due November 30, 2017 (the Cascade Note) issued pursuant to the Note Purchase Agreement dated as of February 23, 2007, as amended, between us and Cascade Investment, L.L.C. (Cascade).  Immediately before the prepayment, the Cascade Note bore interest at 8.89% annually. The price paid by us to prepay the Cascade Note was $63,031,000, which included the principal amount of the Cascade Note plus accrued interest of $531,000 and a negotiated prepayment premium of $12,500,000. We used funds available under the Credit Agreement for the prepayment. This early retirement reflects our desire to lower our long-term debt outstanding given our recent recent divestitures and our anticipated divestiture of DMI. This retirement of debt strengthens our consolidated capital structure and will positively affect future years’ earnings by lowering interest costs. On repayment, $606,000 in unamortized debt expense related to this note was immediately recognized as expense along with the $12,500,000 prepayment premium, which will reduce diluted earnings per share by $0.22 in 2012. The $50,000,000 of debt retired on July 13, 2012 was included in current maturities of long-term debt on our June 30, 2012 consolidated balance sheet. Cascade owned approximately 9.6% of our outstanding common stock as of December 31, 2011.

The following table presents the status of the corporation’s lines of credit as of July 31, 2012 and June 30, 2012:

(in thousands)	Line Limit		In Use  On July 31, 2012		Restricted due to Outstanding Letters of Credit		Available on July 31, 2012		Available on June 30, 2012
Otter Tail Corporation Credit Agreement	$	200,000	$	60,000	$	733	$	139,267	$	196,861
OTP Credit Agreement		170,000		9,124		3,050		157,826		157,965
Total	$	370,000	$	69,124	$	3,783	$	297,093	$	354,826

On December 1, 2011 OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes) pursuant to a note purchase agreement dated July 29, 2011 (2011 Note Purchase Agreement) between OTP and the purchasers named therein. OTP used a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of its 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 were used to repay short-term debt of OTP which was issued to fund capital expenditures, to pay fees and expenses related to the debt issuance and to fund a $10 million contribution to our pension plan in January 2012.

On December 4, 2009 we issued $100 million of our 9.000% notes due 2016 under the indenture (for unsecured debt securities) dated as of November 1, 1997, as amended by a first supplemental indenture dated as of July 1, 2009, between us and U.S. Bank National Association (formerly First Trust National Association), as trustee. The notes are senior unsecured indebtedness and bear interest at 9.000% per year, payable semi-annually in arrears on June 15 and December 15 of each year. The entire principal amount of the notes, unless previously redeemed or otherwise repaid, will mature and become due and payable on December 15, 2016.

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. 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 2007 Note Purchase Agreement and the 2011 Note Purchase Agreement each contain a number of restrictions on the applicable obligor and its subsidiaries. These include restrictions on the obligor’s ability and the ability of the obligor’s subsidiaries to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties.

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Financial Covenants

As of June 30, 2012 we were in compliance with the financial statement covenants that existed in our 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 debt agreements are subject to certain financial covenants. Specifically:

● Under the 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 June 30, 2012 our Interest and Dividend Coverage Ratio calculated under the requirements of the Credit Agreement was 2.06 to 1.00.

● Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, as provided in the OTP Credit Agreement. As of June 30, 2012 OTP’s Interest and Dividend Coverage Ratio calculated under the requirements of the OTP Credit Agreement was 3.22 to 1.00.

● Under the 2007 Note Purchase Agreement, the 2011 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 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 2007 Note Purchase Agreement and 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 June 30, 2012 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.22 to 1.00.

As of June 30, 2012 our interest-bearing debt to total capitalization was 0.47 to 1.00 on a fully consolidated basis and 0.50 to 1.00 for OTP.

OFF-BALANCE-SHEET ARRANGEMENTS

As of June 30, 2012, we and our subsidiary companies have outstanding letters of credit totaling $10.8 million, but our line of credit borrowing limits are only restricted by $3.9 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.

2012 BUSINESS OUTLOOK

Based on year-to-date segment performance and the anticipated classification of DMI under discontinued operations, we are updating our 2012 expectations for diluted earnings per share from continuing operations to a range of $0.84 to $1.09 (inclusive of an after tax charge of $0.22 per share for early retirement of long term debt in the third quarter of 2012) from our previously announced range of $1.05 to $1.40. This guidance considers the cyclical nature of some of our businesses and reflects challenges presented by current economic conditions, as well as our plans and strategies for improving future operating results. Our current consolidated capital expenditures expectation for 2012 is in the range of $125 million to $135 million. This compares with $74 million of capital expenditures in 2011. We plan to invest in generation and transmission projects for the Electric segment that have the potential to positively impact our earnings and returns on capital. Future Electric segment investments include the construction of a new air quality control system at Big Stone Plant to meet requirements of the Clean Air Act and regional haze regulations, investment in two MISO-determined ‘multi-value’ transmission projects that will serve the MISO region, and continuing investment, with other utilities, in three CapX2020 transmission projects already underway.

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Segment components of our updated 2012 earnings per share guidance range are as follows:

Previous 2012 Earnings Per Share Guidance Range			Updated 2012 Earnings Per Share  Guidance Range
	Low	High		Low	High
Electric	$1.00	$1.05	Electric	$1.00	$1.05
Wind Energy	($0.10)	$0.00	Wind Energy	$0.00	$0.00
Manufacturing	$0.36	$0.41	Manufacturing	$0.25	$0.30
Construction	($0.13)	($0.08)	Construction	($0.18)	($0.13)
Plastics	$0.18	$0.23	Plastics	$0.24	$0.29
Corporate	($0.26)	($0.21)	Corporate –Recurring Costs	($0.25)	($0.20)
			Subtotal	$1.06	$1.31
			Corporate – Debt Extinguishment	($0.22)	($0.22)
Total – Continuing Operations	$1.05	$1.40	Total – Continuing Operations	$0.84	$1.09
Discontinued Operations:			Discontinued Operations:
Net Earnings	$0.00	$0.03	Net Loss	($0.09)	($0.04)
			DMI Asset Impairment Charge	($0.81)	($0.76)
Loss on Sale of Disc. Ops.	($0.10)	($0.08)	Loss on Sale of Discontinued Operations	($0.10)	($0.08)
Total	$0.95	$1.35	Total	($0.16)	$0.21

Contributing to the earnings guidance for 2012 are the following items:

● We expect net income in our Electric segment to be in the same range as previous guidance.

● We expect to complete a sale of our Wind Energy segment assets by early 2013 and, therefore, we expect DMI’s 2012 results to be included in discontinued operations. DMI has been able to stabilize production, improve productivity, align headcount with current production demands and eliminate the need for outsourced quality assurance staffing. Order backlog is expected to continue to generate revenues, earnings and cash flows for the remainder of 2012 but DMI’s second quarter 2012 noncash asset impairment charge will have a negative impact on consolidated results in 2012. Backlog in the Wind Energy segment is $70 million for the remainder of 2012.

● We now expect 2012 earnings from our Manufacturing segment to be lower than previous guidance primarily due to lower earnings at ShoreMaster and BTD. Continued reductions in commercial revenues at ShoreMaster along with higher than expected commercial operating expenses are the primary reason for the revised outlook. BTD expects lower earnings compared to previous guidance due to reduction in sales volume at its Illinois plant and lower scrap prices for steel in the second half of 2012 compared with the first half of 2012. Backlog in place for the manufacturing companies is $76 million for 2012 compared with $62 million one year ago.

● We now expect a larger net loss from our Construction segment in 2012 as Foley continued to experience cost overruns on certain major projects in the first half of 2012. Backlog in place for the construction businesses is $73 million for 2012 compared with $84 million one year ago.

● We are increasing the earning guidance for our Plastics segment net income in 2012, compared with previous guidance, based on the strength of its performance in the first half of 2012 and current market conditions.

● We expect corporate general and administrative costs to remain relatively flat between the years.

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.

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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, percentage-of-completion, warranty 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 60 through 63 of our Annual Report on Form 10-K for the year ended December 31, 2011. There were no material changes in critical accounting policies or estimates during the quarter ended June 30, 2012.

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 our borrowing costs and pension plan and postretirement health care expenses.

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

● We may, 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. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

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

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

● We made a $10.0 million discretionary contribution to our defined benefit pension plan in January 2012. We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, 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.

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

● We are subject to risks associated with energy markets.

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

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

● Competition is a factor in all of our businesses.

● We rely on our information systems to conduct our business, and failure to protect these systems against security breaches could adversely affect our business and results of operations.  Additionally, if these systems fail or become unavailable for any significant period of time, our business could be harmed.

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

● 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.

● 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 the value of DMI’s fixed assets and result in an additional impairment of these assets if we are unable to agree to terms related to the June 2012 nonbinding letter of interest to sell these assets. The Federal Production Tax Credit is currently scheduled to expire on December 31, 2012.

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

● Competition from foreign and domestic manufacturers, cost management in a fixed price contract project environment, the price and availability of raw materials, 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 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.

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● 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.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

At June 30, 2012 we had exposure to market risk associated with interest rates because we had $2.3 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 $9.0 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 June 30, 2012 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.

All of our consolidated long-term debt has fixed interest rates. 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.

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

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

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

OTP has market, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of June 30, 2012 OTP had recognized, on a pretax basis, $131,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity and electricity generating capacity. 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 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 the 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 contracts that are marked to market as of June 30, 2012, are 100% offset by forward energy sales contracts in terms of volumes and delivery periods but not in terms of delivery points. The differential in forward prices at the different delivery locations currently results in a net mark-to-market unrealized gain on OTP’s forward energy contracts of $131,000.

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 June 30, 2012 because the open purchases were not at the same delivery points as the open sales.

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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 June 30, 2012 and December 31, 2011, and the change in our consolidated balance sheet position from December 31, 2011 to June 30, 2012 and December 31, 2010 to June 30, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Other Current Asset – Derivative Asset	$	2,402		$	3,803
Regulatory Asset – Current Deferred Marked-to-Market Loss		6,952			5,208
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		11,175			10,749
Total Assets		20,529			19,760
Derivative Liability		(20,337	)		(18,770	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(61	)		(96	)
Total Liabilities		(20,398	)		(18,866	)
Fair Value Adjustments Included in Earnings	$	131		$	894

(in thousands)	Year-to-Date June 30, 2012			Year-to-Date June 30, 2011
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	894		$	763
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(700	)		(151	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33	)		(86	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		161			526
Changes in Fair Value of Contracts Entered into in Current Period		(30	)		120
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	131		$	646

The recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on June 30, 2012 are expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	3rd Qtr 2012		4th Qtr 2012		1st Qtr 2013		Total
Net Gain	$	5	$	123	$	3	$	131

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					Six Months Ended
	June 30,					June 30,
(in thousands)	2012			2011		2012		2011
Net Gains (Losses) on Forward Electric Energy Contracts	$	(50	)	$	139	$	144	$	131

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 June 30, 2012 was $348,000. As of June 30, 2012 OTP had a net credit risk exposure of $860,000 from eight counterparties with investment grade credit ratings. OTP had no exposure at June 30, 2012 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 $860,000 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 June 30, 2012. 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 June 30, 2012, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2012.

During the fiscal quarter ended June 30, 2012, 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.

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

Other

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

Item 1A.  Risk Factors

We are updating the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 30 through 37 of our Annual Report on Form 10-K for the year ended December 31, 2011, related to divestitures and in light of the nonbinding letter of interest we entered into in June of 2012 to sell the assets of DMI Industries, Inc.

The following general risk factor from our 2011 Annual Report on Form 10-K has been revised.

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.

Revised 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. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

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.

The following Wind Energy segment risk factor from the Company’s 2011 Annual Report on Form 10-K has been revised.

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 focused on supplying towers to wind turbine manufacturers and owners and operators of wind energy generation facilities. The wind industry is dependent on federal tax incentives and state renewable portfolio standards and may not be economically viable absent such incentives.

The federal government provides economic incentives to the owners of wind energy facilities, including a federal production tax credit, an investment tax credit and a cash grant equal in value to the investment tax credit. These programs provide material incentives to develop wind energy generation facilities and thereby impact the demand for our manufactured products and services. The failure of Congress to extend or renew these incentives beyond their current expiration dates could significantly delay the development of wind energy generation facilities and the demand for wind turbines, towers, gearing and related components. We cannot assure that any extension or renewal of the production tax credit, investment tax credit or cash grant program will be enacted prior to its expiration or, if allowed to expire, that any extension or renewal enacted thereafter would be enacted with retroactive effect. Any delay or failure to extend or renew the federal production tax credit, investment tax credit or cash grant program in the future could have a material adverse impact on our business, results of operations and future financial performance.

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State renewable energy portfolio standards generally require or encourage state-regulated electric utilities to supply a certain proportion of electricity from renewable energy sources or devote a certain portion of their plant capacity to renewable energy generation. Currently, the majority of states and the District of Columbia have renewable energy portfolio standards in place and certain other states have voluntary utility commitments to supply a specific percentage of their electricity from renewable sources. Any changes to existing renewable energy portfolio standards, the enactment of renewable energy portfolio standards in additional states, or the enactment of a federal renewable energy portfolio may impact the demand for our products. We cannot assure you that government support for renewable energy will continue. The elimination of, or reduction in, state or federal government policies that support renewable energy could have a material adverse impact on our business, results of operations and future financial performance.

Revised Risk Factor:

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 the value of DMI’s fixed assets and result in an additional impairment of these assets if we are unable to agree to terms related to the June 2012 nonbinding letter of interest to sell these assets. The Federal Production Tax Credit is currently scheduled to expire on December 31, 2012.

The following Wind Energy segment risk factor from the Company’s 2011 Annual Report on Form 10-K has been eliminated.

Competition from foreign and domestic manufacturers, cost management in a fixed price contract project environment, fluctuations in foreign currency exchange rates and general economic conditions could affect the revenues and earnings of our Wind Energy segment.

Our Wind Energy segment is subject to risks associated with competition from foreign and domestic manufacturers, some of whom have greater distribution capabilities, greater capital resources and other capabilities that may place downward pressure on margins and profitability. Our wind tower manufacturer operates in a fixed price project environment where balancing workload to costs can create variation in margins that may not be recoverable from customers. If DMI is not able to recover cost increases from its customers, it could have a negative effect on profit margins and income from our Wind Energy segment.

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. In the fourth quarter 2011, we idled our wind tower production plant in Fort Erie, Ontario. 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.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The Company does not have a publicly announced stock repurchase program. The following table shows common shares that were surrendered to the Company by employees to pay taxes in connection with shares issued for incentive awards under the Company’s 1999 Stock Incentive Plan: 

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
April 2012		5,072	$	21.79
May 2012		--		--
June 2012		--		--
Total		5,072

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Item 6.     Exhibits

10.1	1999 Employee Stock Purchase Plan, As Amended (2012) (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
10.2	Form of 2012 Restricted Stock Award Agreement for Executive Officers (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
10.3	Form of 2012 Performance Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
10.4	Form of 2012 Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
10.5	Distribution Agreement Dated May 14, 2012 between Otter Tail Corporation and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.1 to the Form 8-K filed by Otter Tail Corporation on May 14, 2012).
10.6	Otter Tail Corporation Executive Restoration Plus Plan.
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:  August 9, 2012

55

EXHIBIT INDEX

Exhibit Number		Description
	10.1	1999 Employee Stock Purchase Plan, As Amended (2012) (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
	10.2	Form of 2012 Restricted Stock Award Agreement for Executive Officers (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
	10.3	Form of 2012 Performance Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
	10.4	Form of 2012 Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by Otter Tail Corporation on April 19, 2012).
	10.5	Distribution Agreement Dated May 14, 2012 between Otter Tail Corporation and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.1 to the Form 8-K filed by Otter Tail Corporation on May 14, 2012).
	10.6	Otter Tail Corporation Executive Restoration Plus Plan.
	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-10.6

Exhibit 10.6

OTTER TAIL CORPORATION

EXECUTIVE RESTORATION PLUS PLAN

07.01.2012

1

TABLE OF CONTENTS

SECTION 1		Purpose and Administration		1
	1.1.	Name of Plan	1
	1.2.	Effective Date	1
	1.3.	Purpose	1
	1.4.	Administration	1
SECTION 2		Definitions		2
	2.1.	Account	2
	2.2.	Bonus	2
	2.3.	Change in Control	2
	2.4.	Code	3
	2.5.	Committee	3
	2.6.	Company	3
	2.7.	Compensation	3
	2.8.	Deferral Election	3
	2.9.	Disabled	3
	2.10.	Elective Deferred Subaccount	4
	2.11.	Employee	4
	2.12.	Employer	4
	2.13.	Employer Contributions	4
	2.14.	Employer Contributions Subaccount	4
	2.15.	ERISA	4
	2.16.	Investment Options	4
	2.17.	Otter Tail Corporation Retirement Savings Plan	5
	2.18.	Participant	5
	2.19.	Plan	5
	2.20.	Plan Administrator	5
	2.21.	Plan Year	5
	2.22.	Salary	5
	2.23.	Separation from Service	5
	2.24.	Unforeseeable Emergency	5
	2.25.	Valuation Date	5
	2.26.	Other Definitions	6
SECTION 3		Eligibility, Participation, Deferral Elections, and Employer Contributions		6
	3.1.	Eligibility and Participation	6
	3.2.	Rules for Deferral Elections	6

i

	3.3.	Amounts Deferred	6
	3.4.	Cancellation of Deferral Elections	7
	3.5.	Employer Contributions	7
SECTION 4		Accounts		7
	4.1.	Participant Accounts	7
	4.2.	Deferral Account Adjustments and Hypothetical Investment Options	7
	4.3.	Vesting	8
	4.4.	Investment Options	8
SECTION 5		Payment of Benefits		9
	5.1.	Payment upon Separation from Service	9
	5.2.	Payment Upon Disability	9
	5.3.	Payment Upon Death of a Participant	9
	5.4.	Beneficiary	9
	5.5.	Accelerated Distribution Alternatives	9
	5.6.	Effect of Early Taxation	10
	5.7.	Permitted Delays	10
	5.8.	Withholding of Taxes	10
SECTION 6		Miscellaneous		11
	6.1.	Rights Unsecured	11
	6.2.	No Enlargement of Rights	11
	6.3.	Interests Not Transferable	11
	6.4.	Forfeitures and Unclaimed Amounts	12
	6.5.	Controlling Law	12
	6.6.	Words and Headings	12
	6.7.	Action by the Company	12
	6.8.	No Fiduciary Relationship	12
	6.9.	Claims Procedures	12
	6.10.	Notice	14
	6.11.	No Guarantee of Benefits	15
	6.12.	Incapacity of Recipient	15
	6.13.	Corporate Successors	15
	6.14.	Severability	15
	6.15.	Indemnification	15
SECTION 7		Amendment and Termination		16
	7.1.	Amendment or Termination	16
	7.2.	Effect of Amendment or Termination	16

ii

SECTION 1

Purpose and Administration

1.1. Name of Plan. Otter Tail Corporation, a Minnesota corporation, (“Company”), hereby adopts the Executive Restoration Plus Plan (“Plan”), as set forth herein.

1.2. Effective Date.  The effective date of this Plan is July 1, 2012.

1.3. Purpose.  The Company has established the Plan primarily for the purpose of providing deferred compensation to a select group of management or highly compensated employees of the Employer.  The Plan is intended: (1) to comply with Code section 409A and official guidance issued thereunder for all amounts earned under the Plan, and (2) to be “a plan which is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of sections 201(2), 301(a)(3) and 401(a)(1) of ERISA.

Notwithstanding any other provision of this Plan, this Plan shall be interpreted, operated and administered in a manner consistent with these intentions.

The Company intends that the Plan (and any trust under the Plan as described in Section 6.1) shall be treated as unfunded for tax purposes and for purposes of Title I of ERISA.  The Plan is not intended to qualify under Code section 401(a).  The Company’s obligations hereunder, if any, to a Participant (or to a Participant’s beneficiary) shall be unsecured and shall be a mere promise by the Company to make payments hereunder in the future.  A Participant (and any Participant’s beneficiary) shall be treated as a general unsecured creditor of the Company.

1.4. Administration.  The Plan shall be administered by the Committee, which shall act as the Plan Administrator.  The Plan Administrator shall have the powers, rights and duties set forth in the Plan and shall have the power, in the Plan Administrator’s sole and absolute discretion, to determine all questions arising under the Plan, including the determination of the rights of all persons with respect to the Plan and to interpret the provisions of the Plan and remedy any ambiguities, inconsistencies, or omissions.  Any decisions of the Plan Administrator shall be final and binding on all persons with respect to the Plan and the benefits provided under the Plan.  The Committee  may delegate some or all of the Plan Administrator’s authority under the Plan to one or more persons or providers, provided, however, that (i) such delegation must be in writing, and (ii) the delegate must accept such delegation in writing.  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.

3

If a Participant is serving as the Plan Administrator (either individually or as a member of a committee), the Participant may not decide or determine any matter or question concerning such Participant’s benefits under the Plan that the Participant would not have the right to decide or determine if the Participant were not serving as the Plan Administrator.

SECTION 2

Definitions

For purposes of the Plan, the following words and phrases shall have the meanings set forth below, unless their context clearly requires a different meaning:

2.1. Account.  “Account” means the bookkeeping account maintained under the Plan in the Participant’s name to reflect amounts deferred by the Participant under the Plan pursuant to Section 3 (as adjusted under Section 4) and any Employer Contributions made on behalf of the Participant pursuant to Section 3 (as adjusted under Section 4).  The Account shall be hypothetical in nature and shall be maintained for bookkeeping purposes only.  Neither the Plan nor the Account shall hold any actual funds or assets.  The Account shall consist of a Participant’s entire account balance, including his Elective Deferred Subaccount and Employer Contributions Subaccount.

2.2. Bonus.  “Bonus” means an amount payable to an eligible Employee under an annual bonus or incentive compensation plan of the Company.

2.3. Change in Control.  “Change in Control” means, for purposes of determining a Participant’s vested interest in his Employer Contributions Subaccount:

(a) Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) becomes or has become 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 members of the Company’s Board of Directors at the beginning of that period cease to constitute a majority of the Company’s Board of Directors and the new members of the Board have not been endorsed by a majority of the Board members before the date of that change; 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.

2.4. Code.  “Code” means the Internal Revenue Code of 1986, as amended from time to time. Any reference to a section of the Code includes any comparable section or sections of any future legislation that amends, supplements or supersedes that section.

2.5. Committee.  “Committee” means the Benefits Advisory Committee of the Company.

2.6. Company.  “Company” means Otter Tail Corporation, a Minnesota corporation.

2.7. Compensation.  “Compensation” means the total remuneration paid to the Participant by the Employer for services as an employee reportable on Treasury Form W-2 (or any comparable successor form) for the applicable period; subject, however, to the following:

(a) Included Items. In determining a Participant’s Compensation there shall be included (i) elective contributions made by the Employer on behalf of the Participant that are not includible in gross income under Code sections 125, 132(f), 402(e)(3), 402(h), 403(b), 414(h)(2) and 457 including elective contributions authorized by the Participant under a retirement savings election under the Otter Tail Corporation Retirement Savings Plan, a cafeteria plan or any other qualified cash or deferred arrangement under Code section 401(k) and (ii) all elective deferrals under this or any other nonqualified plan of the Company.

(b) Excluded Items. In determining a Participant’s Compensation there shall be excluded: (i) all expense reimbursements (including moving expenses and tuition reimbursements), and other similar payments, and (ii) all noncash remuneration, and (iii) welfare benefits (both cash and noncash) including third party sick pay (including short and long term disability insurance benefits), and (iv) income imputed from insurance coverages and premiums or employee discounts and other similar accounts, and (v) the value of stock options and stock appreciation rights (whether or not exercised) and other similar amounts, and (vi) all foreign service allowances, station allowances, foreign tax equalization payments and other similar payments, and (vii) taxable and nontaxable fringe benefits, prizes, gifts (both cash and noncash included) or awards provided by Employer (including any gross up) (viii) final payments on account of termination of employment (i.e., severance payments) and settlement for accrued but unused PTO plans, and (ix) the value of long term incentives under the Company’s  1999 Stock Incentive Plan or any successor Plan, and (x) Achievement Awards and other similar incentive payments, and (xi) similar emoluments consistent with the foregoing.

2.8. Deferral Election.  “Deferral Election” means a written irrevocable election filed by the Participant with the Employer, as provided in Section 3.2, specifying the amount of Compensation to be deferred by the Participant for a Plan Year.

2.9. Disabled.  “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 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.

2.10. Elective Deferred Subaccount.  “Elective Deferred Subaccount” means the bookkeeping account maintained to reflect the portion of a Participant’s Salary and Bonus deferred under the Plan pursuant to Section 3 (as adjusted under Section 4).  The Elective Deferred Subaccount shall be hypothetical in nature and shall be maintained for bookkeeping purposes only.  Neither the Plan nor the Elective Deferred Subaccount shall hold any actual funds or assets.

2.11. Employee.  “Employee” means an employee of the Employer who meets the eligibility criteria set forth in Section 3.1 of the Plan and who is a member of a select group of management or highly compensated employees as defined under ERISA or the regulations thereunder.

2.12. Employer.  “Employer” means the Company.

2.13. Employer Contributions.  “Employer Contributions” means any Employer Contributions credited to a Participant’s Employer Contributions Subaccount pursuant to Section 3.5.

2.14. Employer Contributions Subaccount.  “Employer Contributions Subaccount” means the bookkeeping account maintained to reflect Employer Contributions made on behalf of the Participant under the Plan pursuant to Section 3.5 (as adjusted under Section 4).  The Employer Contributions Subaccount shall be hypothetical in nature and shall be maintained for bookkeeping purposes only.  Neither the Plan nor the Employer Contributions Subaccount shall hold any actual funds or assets.

2.15. ERISA.  “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.  Any reference to a section of ERISA includes any comparable section or sections of any future legislation that amends, supplements or supersedes that section.

2.16. Investment Options.  The Plan Administrator will designate the hypothetical “Investment Options”, if any, available for participant selection from time to time.

2.17. Otter Tail Corporation Retirement Savings Plan.  The “Otter Tail Corporation Retirement Savings Plan” means the Company’s retirement plan qualified under sections 401(a) and 401(k) of the Code as amended from time to time.

2.18. Participant.  “Participant” means an Employee who meets the eligibility criteria set forth in Section 3.1 and who has made a Deferral Election in accordance with the terms of the Plan or otherwise had amounts credited to his Account.

2.19. Plan.  “Plan” means the nonqualified deferred compensation plan named in Section 1.1.

2.20. Plan Administrator.  The “Plan Administrator” means the Benefits Advisory Committee or its delegate appointed as described in Section 1.4.

2.21. Plan Year.  “Plan Year” means the calendar year, however, the initial Plan Year shall be a short Plan Year, beginning on the Effective Date and ending on the following December 31.

2.22. Salary.  “Salary” means the regular base salary paid to an eligible Employee by the Company.  Such pay shall be determined before any elections to defer or otherwise reduce compensation under this or any other nonqualified deferred compensation plan, and also before any salary reductions used for contributions or to purchase benefits under any other Company sponsored plans such as the Otter Tail Corporation Retirement Savings Plan.

2.23. Separation from Service.  “Separation from Service” or “Separates from Service” means a “separation from service” within the meaning of Code section 409A.

2.24. Unforeseeable Emergency.  “Unforeseeable Emergency” means a severe financial hardship of the Participant as described in Code section 409A resulting from:

(a) A sudden and unexpected illness or accident of the Participant, the Participant’s beneficiary, the Participant’s spouse, or the Participant’s dependent (as defined in Code section 152(a));

(b) Loss of Participant’s property due to casualty; or

(c) Such other similar extraordinary and unforeseeable circumstances resulting from events beyond the control of the Participant.

Whether a Participant has an Unforeseeable Emergency shall be determined in the sole discretion of the Plan Administrator.

2.25. Valuation Date.  “Valuation Date” means each business day the financial markets are open, unless the underlying investment requires a less frequent valuation.

2.26. Other Definitions.  In addition to the terms defined in this Section 2, other terms are defined when first used in Sections of this Plan.

SECTION 3

Eligibility, Participation, Deferral Elections, and Employer Contributions

3.1. Eligibility and Participation.  Any executive officer or employee of Otter Tail Corporation who is named by its Chief Executive Officer (“CEO”) is eligible to participate in the Plan. An Employee shall become a Participant as of a date specified by the CEO and shall remain a Participant until the entire balance of the Participant’s vested Account has been distributed.

3.2. Rules for Deferral Elections.  Any Employee identified in Section 3.1 may make a separate Deferral Election to defer receipt of Salary and Bonus in accordance with the rules set forth below:

(a) All Deferral Elections must be made in writing on the form prescribed by the Plan Administrator.  Each Deferral Election will be effective only when filed with the Plan Administrator no later than the date specified by the Plan Administrator.  In no event may a Deferral Election be made later than the last day of the Plan Year preceding the Plan Year in which the Compensation being deferred is earned.  Additionally, no election under this Plan will be allowed if the Employee has a deferral election in place under another account balance nonqualified deferred compensation plan sponsored by the Company that would be aggregated with this Plan under Code section 409A.

(b) With respect to Plan Years following the Participant’s initial Plan Year of participation in the Plan, failure to complete timely another Deferral Election shall constitute a waiver of the Participant’s right to elect a different amount of Compensation to be deferred for each such Plan Year and shall be considered an affirmation and ratification to continue the Participant’s existing Deferral Election (i.e., an “evergreen election”).  However, a Participant may, prior to the beginning of any Plan Year, elect to increase or decrease the amount of Compensation to be deferred for the next following Plan Year by filing another Deferral Election with the Plan Administrator in accordance with paragraph (a) above.

3.3. Amounts Deferred. Commencing on the effective date, a Participant may elect to:

Defer up to 50% of Salary, in 1% increments.

Defer up to 100% of Bonus, in 1% increments.

The amount of Compensation deferred by a Participant shall be credited to the Participant’s Elective Deferred Subaccount as soon as administratively practicable after the date the Compensation would be paid to the Participant absent such deferral.

3.4. Cancellation of Deferral Elections.If a Participant becomes Disabled or obtains a distribution under Section 5.5(a) on account of an Unforeseeable Emergency during a Plan Year, his Deferral Election for such Plan Year shall be cancelled.

3.5. Employer Contributions.  The Employer may, in its sole discretion, credit to the Employer Contributions Subaccount of any Employee an amount determined by the Employer in its sole discretion (an “Employer Contribution”) for a Plan Year.

(a) Annual Employer Contributions.  Unless and until changed by the Employer, as of the Effective Date, the Employer Contribution for each Participant for each Plan Year shall be an amount equal to the sum of six and one-half percent (6.5%) of his Compensation for that Plan Year in excess of Code Section 401(a)(17) compensation limit in effect for that year plus three percent (3%) of the Participant’s Compensation for that year.  To be eligible for such contribution, the Participant must be actively employed as of the last day of the Plan Year for which the contribution is being made.

(b) One-Time Opening Balance Contribution.  The Employer Contributions Subaccount for Shane Waslaski shall be credited with an Employer Contribution for 2011 and 2010 (each calendar year before January 1, 2012 in which he was an executive officer of the Employer) in an amount equal to the sum of six and one-half percent (6.5%) of his Compensation for each such year in excess of Code Section 401(a)(17)  compensation limit in effect for that year plus three percent (3%) of his total Compensation for that year.

SECTION 4

Accounts

4.1. Participant Accounts.  All amounts deferred pursuant to one or more Deferral Elections under the Plan and any Employer Contributions shall be credited to a Participant’s Account and shall be adjusted under Section 4.2.

4.2. Deferral Account Adjustments and Hypothetical Investment Options.  As of each Valuation Date, the Plan Administrator shall adjust amounts in a Participant’s Account to reflect earnings (or losses) in the Investment Options attributable to the Participant’s Account.  Earnings (or losses) on amounts in a Participant’s Account shall accrue commencing on the date the Account first has a positive balance and shall continue to accrue until the entire balance in the Participant’s Account has been distributed.  Earnings (or losses) shall be credited to a Participant’s Account based on the results that would have been achieved had amounts credited to the Account been invested as soon as practicable after crediting into the Investment Options selected by the Participant.  Nothing in this Section 4.2 or otherwise in the Plan, however, will require the Company to actually invest any amounts in such Investment Options or otherwise.

4.3. Vesting.  A Participant shall be vested in his Account as follows:

(a) A Participant’s Elective Deferred Subaccount shall be fully vested at all times.

(b) A Participant’s Employer Contributions Subaccount shall be vested to the same extent he is vested in any employer contributions under the Otter Tail Corporation Retirement Savings Plan from time to time, provided, however, that a Participant shall become fully vested in their Employer Contributions Subaccount upon his death, his becoming Disabled or upon a Change in Control; provided the date on which the Participant becomes fully vested in the Employer Contributions as a result of any of those events must occur while the Participant is actively employed by or associated with the Employer.

To the extent that any amounts credited to a Participant’s Employer Contribution Subaccount are not vested at the time such amounts are otherwise payable under Section 5, such amounts shall be forfeited.

4.4. Investment Options.  If applicable, the Plan Administrator shall from time to time specify procedures to allow Participants to make elections as to the deemed investment of amounts newly credited to their Account, as well as the deemed investment of amounts previously credited to their Account.  Participant fund selections must be made to the Plan Administrator or designated agent.  Fund selections will be effective within a reasonable period of time as determined by the means used to communicate such selections and generally accepted business practices.

The Plan Administrator or its designated agent may take investment instructions from a Participant as of any business day regarding Investment Options.  Investment elections and/or transfer instructions may be accepted in a manner determined by the Plan Administrator.

Investment Options are selected solely for purposes of determining hypothetical gains and/or losses to a Participant’s bookkeeping Account.  Neither the Plan nor any Account shall hold any actual funds or assets.  The Plan Administrator may change Investment Options at its discretion.

SECTION 5

Payment of Benefits

5.1. Payment upon Separation from Service.  The vested portion of a Participant’s Account shall be paid in a lump sum within 90 days following the first business day of the seventh month following the Participant’s Separation from Service.

5.2. Payment Upon Disability.  Notwithstanding anything in the Plan to the contrary, in the event a Participant becomes Disabled while the Participant is employed by or associated with the Employer, payment of the Participant’s vested Account shall be made in a lump sum payment within 90 days following the date on which the Participant becomes Disabled.  Whether a Participant is Disabled for purposes of the Plan shall be determined by the Plan Administrator in accordance with the provisions of Section 2.9.

5.3. Payment Upon Death of a Participant.  Notwithstanding anything in the Plan to the contrary, a Participant’s vested Account shall be paid to the Participant’s beneficiary (designated in accordance with Section 5.4) in a lump sum payment within 90 days following the date of the Participant’s death.

5.4. Beneficiary.  The Participant may name a beneficiary or beneficiaries to receive the balance of the Participant’s vested Account in the event of the Participant’s death.  To be effective, any beneficiary designation must be filed in writing with the Plan Administrator in accordance with rules and procedures adopted by the Plan Administrator for that purpose.  A Participant may revoke an existing beneficiary designation by filing another written beneficiary designation with the Plan Administrator.  The latest beneficiary designation received by the Plan Administrator during the Participant’s lifetime shall be controlling.  If no beneficiary is named by a Participant, or if the Participant survives all of his named beneficiaries and does not designate another beneficiary, the Participant’s vested Account shall be paid in the following order of precedence:

(a)           The Participant’s spouse; or if none

(b)           The Participant’s children (including adopted children) per stirpes; or if none

(c)           The Participant’s estate.

5.5.          Accelerated Distribution Alternatives.

(a) Unforeseeable Emergency.  Notwithstanding anything in the Plan to the contrary, if the Plan Administrator determines that a Participant has incurred an Unforeseeable Emergency, the Participant shall, to the extent permitted by Code §409A and applicable regulations, receive in a lump sum payment of all or any portion of the Participant’s vested Account needed to satisfy the Unforeseeable Emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, but only if the Unforeseeable Emergency may not be relieved (i) through reimbursement or compensation by insurance or otherwise; (ii) by liquidation of the Participant’s assets to the extent the liquidation of such assets would not itself cause severe financial hardship; or (iii) by cessation of deferrals under the Plan.  A payment on account of an Unforeseeable Emergency shall not be in excess of the amount needed to relieve such Unforeseeable Emergency and shall be made within 90 daysfollowing the date of such Unforeseeable Emergency.

(b) Other Accelerated Distributions.  Notwithstanding anything in the Plan to the contrary, a Participant’s vested Account shall be paid to the Participant in a lump sum payment within ninety (90) days of the need for payment in connection with a conflict of interest as provided in Treasury Regulation §1.409A-3(j)(4)(iii); payment of employment taxes as provided in Treasury Regulation §1.409A-3(j)(4)(vi); plan termination and liquidation pursuant to Section 7.2 and as provided in Treasury Regulation §1.409A-3(j)(4)(ix); payment of state local or foreign taxes as provided in Treasury Regulation §1.409A-3(j)(4)(xi); certain offsets as provided in Treasury Regulation §1.409A-3(j)(4)(xiii); or settlement of bona fide disputes as provided in Treasury Regulation §1.409A-3(j)(4)(xiv).

5.6. Effect of Early Taxation.  Notwithstanding anything in the Plan to the contrary, if a Participant’s benefits under the Plan are includible in income pursuant to Code section 409A, such benefits shall be distributed immediately to the Participant.

5.7. Permitted Delays.  Notwithstanding anything in the Plan to the contrary, any payment to a Participant under the Plan shall be delayed upon the Plan Administrator’s reasonable anticipation of one or more of the following events:

(a) The Company’s deduction with respect to such payment would be eliminated by application of Code section 162(m);

(b) The making of the payment would violate Federal securities laws or other applicable law; or

(c) Any other event or condition prescribed under Treasury Regulation 1.409A-2(b)(7(iii);

provided, that any payment delayed pursuant to this Section 5.7 shall be paid in accordance with Code section 409A.

5.8. Withholding of Taxes.  In connection with the Plan, the Employer, or a properly designated agent, may withhold any applicable Federal, state or local income tax and employment taxes, including Social Security taxes, at such time and in such amounts from a benefit payment under the Plan or a Participant’s wages or reduce a Participant’s Account as is necessary to comply with applicable laws and regulations.  The Employer, or a properly designated agent, shall report Plan payments and other Plan-related information to the appropriate governmental agencies as required under applicable laws.

SECTION 6

Miscellaneous

6.1. Rights Unsecured.  Any payments by a trust of benefits provided to a Participant under the Plan shall be considered payment by the Company and shall discharge the Company from any further liability under the Plan for such payments.  Any funds set aside by the Company for the purpose of meeting its obligations under the Plan, including any amounts held by a trustee, if any, shall continue for all purposes to be part of the general assets of the Company and shall be available to its general creditors in the event of the Company’s bankruptcy or insolvency.  The Company’s obligation under this Plan shall be that of an unfunded and unsecured promise to pay money in the future.

The Company may, but is not required to, establish and maintain one or more grantor trust(s) to hold assets to be used for payment of benefits under the Plan.  Any trust established by the Company for purposes of paying benefits under this Plan, and the taxation of any assets held in such trust on behalf of Participants, shall be subject to the requirements of Code §409A, including (a) the rules pertaining to offshore funding set forth in Code §409A(b)(1), (b) the transfers of assets for the benefit of covered employees (as defined in Code §409A(b)(3)(d)(ii)) when any defined benefit plan of the Company is in a restricted period, and (c) the restriction of assets in connection with a change in the Company’s financial health under Code §409A(b)(2).  The Company’s obligations under the Plan may be satisfied with assets of the Trust, if any, distributed pursuant to the terms thereof, and any such distribution shall reduce the Company’s obligations under the Plan.

6.2. No Enlargement of Rights.  Establishment of the Plan shall not be construed to give any Employee the right to be retained by the Employer or to any benefits not specifically provided by the Plan.  Any liability of the Company to any Participant, former Participant, or Participant’s beneficiary with respect to a right to payment under the Plan shall be based solely upon contractual obligations created by the Plan.

6.3. Interests Not Transferable.  Except as to withholding of any tax under the laws of the United States or any state or locality and the provisions of Section 5.8, no benefit payable at any time under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, or any other encumbrance of any kind or to any attachment, garnishment, or other legal process of any kind.  Any attempt by a person (including a Participant or a Participant’s beneficiary) to anticipate, alienate, sell, transfer, assign, pledge, or otherwise encumber any benefits under the Plan, whether currently or thereafter payable, shall be void.  If any person shall attempt to, or shall alienate, sell, transfer, assign, pledge or otherwise encumber such person’s benefits under the Plan, or if by any reasons of such person’s bankruptcy or other event happening at any time, such benefits would devolve upon any other person or would not be enjoyed by the person entitled thereto under the Plan, then the Plan Administrator, in the Plan Administrator’s sole discretion, may terminate the interest in any such benefits of the person otherwise entitled thereto under the Plan and may hold or apply such benefits in such manner as the Plan Administrator may deem proper.

6.4. Forfeitures and Unclaimed Amounts.  Unclaimed amounts shall consist of the amounts in the Account of a Participant that cannot be distributed because of the Plan Administrator’s inability, after a reasonable search, to locate a Participant or the Participant’s beneficiary, as applicable, within a period of two (2) years after the distribution date upon which the payment of benefits became due.  Unclaimed amounts shall be forfeited at the end of such two-year period.  These forfeitures will reduce the obligations of the Company, if any, under the Plan.  After an unclaimed amount has been forfeited, the Participant or beneficiary, as applicable, shall have no further right to amounts in the Participant’s Account.

6.5. Controlling Law.  The law of the state of Minnesota shall be controlling in all matters relating to the Plan to the extent not preempted by Federal Law.

6.6. Words and Headings.  Words in the masculine gender shall include the feminine and the singular shall include the plural, and vice versa, unless qualified by the context.  Any headings used herein are included for ease of reference only, and are not to be construed so as to alter the terms hereof.

6.7. Action by the Company.  Except as otherwise specifically provided herein, any action required of or permitted to be taken by the Company under the Plan shall be by resolution of the Committee, unless reserved to the Company’s Board of Directors.

6.8. No Fiduciary Relationship.  Nothing contained in this Plan, and no action taken pursuant to its provisions by either the Company or the Participants shall create, or be construed to create a fiduciary relationship between the Company and the Participant, a designated beneficiary, other beneficiaries of the Participant, or any other person.

6.9. Claims Procedures.

(a) Initial Review.  Any person (hereinafter referred to as a “Claimant”) who believes that he or she is being denied a benefit to which he or she may be entitled under the Plan may file a written request for such benefit with the Plan Administrator.  Such written request must set forth the Claimant’s claim and must be addressed to the Plan Administrator, at the Company’s principal place of business.  Upon receipt of a claim, the Plan Administrator shall advise the Claimant that a reply will be forthcoming within ninety (90) days and shall deliver a reply within ninety (90) days.  If special circumstances (such as for a hearing) require a longer period, the Plan Administrator may extend the reply period for an additional ninety (90) days so long as the Plan Administrator notifies the Claimant in writing, prior to the expiration of the ninety-day period, of the reasons for an extension of time.  If the claim is denied in whole or in part, the Plan Administrator shall issue a written determination, using language calculated to be understood by the Claimant, setting forth:

(1) The specific reason or reasons for such denial;

(2) The specific reference to pertinent provisions of the Plan upon which such denial is based;

(3) A description of any additional material or information necessary for the Claimant to perfect the Claimant’s claim and an explanation why such material or such information is necessary; and

(4) Appropriate information as to the steps to be taken if the Claimant wishes to submit the claim for review, including the time limits for requesting such a review and the Claimant’s right to bring a civil action under ERISA section 502(a) following an adverse benefit determination on review.

(b) Review of Denial.  Within sixty (60) days after the receipt by the Claimant of the written determination described above, the Claimant may request in writing, that the Plan Administrator review the initial claim determination.  The request must be addressed to the Plan Administrator, at the Company’s principal place of business.  The Claimant or the Claimant’s duly authorized representative will have, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claims for benefits and may submit issues and comments in writing for consideration by the Plan Administrator.  The review will take into account all comments, documents, records, and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.

If the claimant does not request a review of the Plan Administrator’s determination within such sixty-day period, the Claimant shall be barred and estopped from challenging the Plan Administrator’s determination.  If the Claimant does file a request for review, his request must include a description of the issues and evidence he deems relevant.  Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.

Within sixty (60) days after the Plan Administrator’s receipt of a request for review, the Plan Administrator will render a decision.  After considering all materials presented by the Claimant, the Plan Administrator will render a written determination, written in a manner calculated to be understood by the Claimant setting forth:

(1) The specific reasons for the adverse determination;

(2) The specific references to the pertinent provisions of the Plan on which the decision is based;

(3) A statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits; and

(4) A statement describing any voluntary appeal procedures offered by the Plan and the Claimant’s right to obtain the information about such procedures, as well as a statement of the Claimant’s right to bring an action under ERISA section 502(a).

If special circumstances require that the sixty-day time period be extended, the Plan Administrator will so notify the Claimant in writing before the end of the sixty-day period and will render the decision as soon as practicable, but no later than one hundred twenty days after receipt of the request for review.

(c) Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in this Section 6.9 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the Claimant has exhausted his remedies under this Section 6.9.  In any such legal action, the Claimant may only present evidence and theories which the Claimant presented during the claims procedure. Any claims which the Claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived.  Judicial review of a Claimant’s denied claim shall be limited to a determination of whether the denial was an abuse of discretion based on the evidence and theories the Claimant presented during the claims procedure.

(d) Limitations Period.  Any suit or legal action initiated by a Claimant under the Plan must be brought by the Claimant no later than one year following a final decision on the claim for benefits by the Plan Administrator.  The one-year limitation on suits for benefits will apply in any forum where a Claimant initiates such suit or legal action.

(e) Disability Claims.  Claims for disability benefits shall be determined under DOL Regulation section 2560.503-1 which is hereby incorporated by reference.

6.10. Notice.  Any notice required or permitted to be given under the provisions of the Plan shall be in writing, and shall be signed by the party giving or making the same.  If such notice, consent or demand is mailed to a party hereto, it shall be sent by United States certified mail, postage prepaid, addressed to such party’s last known address as shown on the records of the Company.  Notices to the Plan Administrator should be sent in care of the Company at the Company’s principal place of business.  The date of such mailing shall be deemed the date of notice.  Either party may change the address to which notice is to be sent by giving notice of the change of address in the manner set forth above.

6.11. No Guarantee of Benefits.  Nothing contained in the Plan shall constitute a guarantee by the Company or any other person or entity that the assets of the Company will be sufficient to pay any benefits hereunder.

6.12. Incapacity of Recipient.  If any person entitled to a distribution under the Plan is deemed by the Plan Administrator to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until a claim for such payment shall have been made by a duly appointed guardian or other legal representative of such person, the Plan Administrator may provide for such payment or any part thereof to be made to any other person or institution then contributing toward or providing for the care and maintenance of such person.  Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Company and the Plan with respect to the payment.

6.13. Corporate Successors.  The Plan and the obligations of the Company under the Plan shall become the responsibility of any successor to the Company by reason of a transfer or sale of substantially all of the assets of the Company or by the merger or consolidation of the Company into or with any other corporation or other entity.

6.14. Severability.  In the event any provision of the Plan shall be held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining parts of the Plan, but the Plan shall be construed and enforced as if the illegal or invalid provision had never been inserted.

6.15. Indemnification.  To the extent not covered by insurance, the Company shall indemnify the Plan Administrator, each employee, officer, director, and agent of the Company, and all persons formerly serving in such capacities, against any and all liabilities or expenses, including all legal fees relating thereto, arising in connection with the exercise of their duties and responsibilities with respect to the Plan, provided however that the Company shall not indemnify any person for liabilities or expenses due to that person’s own gross negligence or willful misconduct.

SECTION 7

Amendment and Termination

7.1 Amendment or Termination.  The Company reserves the right to modify, amend or terminate the Plan when, in the sole discretion of the Company, such amendment or termination is advisable.

7.2 Effect of Amendment or Termination.  No amendment or termination of the Plan shall reduce or eliminate any vested balance in a Participant’s Account accrued through the date of such amendment or termination.  However, an amendment may freeze or limit future deferrals or credits of benefits under the Plan on and after the date of such amendment.  Upon termination of the Plan, distribution of Plan benefits shall be made to Participants and beneficiaries in the manner and at the time described in Section 5, unless the Company determines in its sole discretion that all such amounts shall be distributed upon termination in accordance with the requirements under Code section 409A.  Upon termination of the Plan, no further deferrals of Compensation or crediting of Employer Contributions shall be permitted; provided, however, earnings, gains and losses shall continue to be credited to each Participant’s Account balance in accordance with Section 4 until the vested Account balances are fully distributed.

IN WITNESS WHEREOF, Otter Tail Corporation has caused this Plan to be executed by its duly authorized officers this 29th day of June, 2012.

OTTER TAIL CORPORATION
By	George Koeck
Its	Sr. Vice President

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: August 9, 2012

/s/  Edward J. McIntyre

Edward J. McIntyre

President and Chief Executive Officer

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: August 9, 2012

/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 June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward J. McIntyre, President and Chief Executive 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/  Edward J. McIntyre

Edward J. McIntyre

President and Chief Executive Officer

August 9, 2012

EX-32.1

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 June 30, 2012 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

August 9, 2012

XML

Warranty Reserves (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Summary Of Significant Accounting Policies [Abstract]
Warranty Reserve Balance, December 31, 2011	$ 3,170
Provision for Warranties Issued During the Year	426
Settlements Made During the Year	(552)
Adjustments to Warranty Estimates for Prior Years	(38)
Warranty Reserve Balance, June 30, 2012	$ 3,006

XML

Rate and Regulatory Matters (Details) (USD $)			6 Months Ended												3 Months Ended		6 Months Ended					6 Months Ended	1 Months Ended	3 Months Ended								1 Months Ended			1 Months Ended	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Otter Tail Power Company Conservation Improvement Program Minimum	Jun. 30, 2012 Otter Tail Power Company Renewable Resource Cost Recovery Rider Fiscal Year 2012	Jun. 30, 2012 Otter Tail Power Company Renewable Resource Cost Recovery Rider Fiscal Year 2016	Jun. 30, 2012 Otter Tail Power Company Renewable Resource Cost Recovery Rider Fiscal Year 2020	Jun. 30, 2012 Otter Tail Power Company Renewable Resource Cost Recovery Rider Fiscal Year 2025	Jun. 30, 2012 Otter Tail Power Company Capacity Expansion 2020 Entity Project	Jun. 30, 2012 Otter Tail Power Company Fargo Project Capacity Expansion 2020 kV	Jun. 30, 2012 Otter Tail Power Company Big Stone Project Air Quality Control	Jun. 30, 2012 Otter Tail Power Company Brookings Project Capacity Expansion 2020 kV	Jun. 30, 2012 Otter Tail Power Company Bemidji Project Capacity Expansion 2020 kV	Jun. 30, 2012 Otter Tail Power Company Twin Cities La Crosse Capacity Expansion 2020 kV	Jun. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider	Jun. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jun. 30, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jun. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jun. 30, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Mar. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jan. 11, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Dec. 31, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jun. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate [Member]	Apr. 25, 2011 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case Properties	Dec. 31, 2011 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case	Apr. 02, 2010 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case	Jun. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Luverne Wind Farm Project Renewable Resource Cost Recovery Rider	Jan. 12, 2010 Otter Tail Power Company Minnesota Public Utilities Commission Luverne Wind Farm Project Renewable Resource Cost Recovery Rider	Jun. 30, 2012 Otter Tail Power Company North Dakota Public Service Commission Transmission Cost Recovery Rider	Jun. 30, 2012 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Dec. 29, 2011 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Sep. 30, 2010 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Apr. 21, 2011 Otter Tail Power Company South Dakota Public Utilities Commission General Rate Case	Sep. 28, 2010 Otter Tail Power Company South Dakota Public Utilities Commission General Rate Case	Aug. 20, 2010 Otter Tail Power Company South Dakota Public Utilities Commission General Rate Case	Aug. 20, 2010 Otter Tail Power Company South Dakota Public Utilities Commission General Rate Case Maximum	Jun. 30, 2012 Otter Tail Power Company Federal Energy Regulatory Commission Project	Dec. 31, 2010 Otter Tail Power Company Federal Energy Regulatory Commission Project
Regulatory Matters [Line Items]
General rate increase request																									8.01%
General rate revenue increase percentage description																																			Under 10.0%
Number of days the proposed rates are suspended for review																																	180 days			1 day
Interim rate increase request																									3.80%
General rate revenue increase approved																							$ 5,000,000									$ 643,000
Percentage of general rate revenue increase approved																							3.76%									2.32%
Big Stone II Investment cost incurred, recovery period																							5 years
Number of transmission lines approved for transfer of investments from rider recovery to base rate recovery																							2
Public utilities overall approximate rate increase to customers																								1.60%
Public utilities interim rate increase approved																								3.80%
Refundable interim rate difference to customers																								3,900,000
Public utilities allowed rate of return prior to approval of increase in base rate																								8.33%
Public utilities allowed rate of return subsequent to approval of increase in base rate																								8.61%								8.50%
Public utilities allowed rate of return on equity prior to approval of increase in base rate																								10.43%
Public utilities allowed rate of return on equity subsequent to approval of increase in base rate																								10.74%
Long term debt as percentage of aggregate capital used for computation of entitys rate of return																								48.28%
Common equity as percentage of aggregate capital used for computation of entitys rate of return																								51.72%
Percentage of qualifying renewable energy to be supplied in proportion to aggregate energy supplies				12.00%	17.00%	20.00%	25.00%
Regulatory asset	144,006,000	151,528,000												200,000	6,200,000		6,200,000									2,000,000		1,100,000	1,300,000
Extended period of new effective rate																						18 months
Current balance of unrecovered costs due to extended period for new rate																						0
Expected cost recovery from customers																											17,000,000			10,100,000	15,600,000
Surcharge revenues and financial incentives recognized during period															900,000	1,200,000	1,700,000	3,000,000
Percentage of operating revenue from service to be invested in energy conservation			1.50%
Financial incentive filing request																			2,600,000
Financial incentives approved																				3,500,000
Conservation improvement programs surcharge																				3.80%	3.00%
General rate revenue increase request																																		$ 2,800,000
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate																																				100.00%	100.00%
Percentage of prudently incurred costs of cancelled or abandoned transmission facilities, authorized for recovery by formula transmission rate																																					100.00%
Number of projects authorized for recovery of costs if abandoned																																				2	3
Number of investor								11
Number of major transmission projects								4
Expanded capacity of projects									345		345	230	345
BART compliant air quality control system implementation period										5 years

XML

Estimated Amortization Expense for Intangible Assets (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012
Summary Of Significant Accounting Policies [Abstract]
2012	$ 981
2013	977
2014	977
2015	977
2016	$ 945

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified		1 Months Ended		6 Months Ended			1 Months Ended
	Jun. 30, 2012	Dec. 31, 2011 Otter Tail Power Company Commitments Under Contracts In Connection With Construction Programs	Jun. 30, 2012 Otter Tail Power Company Commitments Under Contracts In Connection With Construction Programs	Jun. 30, 2012 Otter Tail Power Company Capacity and Energy Requirements	Jun. 30, 2012 Otter Tail Power Company Coal and Freight Purchase Commitments Minimum	Jun. 30, 2012 Otter Tail Power Company Coal and Freight Purchase Commitments Maximum	May 31, 2012 Otter Tail Power Company Commitment to develop Coyote Creek Mine
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Amount		$ 41.0					$ 0.9
Additional construction commitment, due in remainder of 2012			18.7
Construction commitment, due in 2013			21.9
Construction commitment, due in 2014			4.2
Construction commitment, due in 2015			19.5
Development Period Costs Payment Term							52 months
Contractual Commitment Term For Payment Of Pre Contract Costs							30 days
Contracts expiration year				2032	2012	2016
Loss Contingency, range of possible loss, maximum	$ 7.0

XML

Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	$ 25,334	$ 27,391
Regulatory Liabilities - Current	139	184
Net Regulatory Assets - Current	25,195	27,207
Regulatory Assets - Long-Term	118,672	124,137
Regulatory Liabilities - Long-Term	68,071	69,106
Net Regulatory Assets - Long-Term	50,601	55,031
Regulatory Assets - Total	144,006	151,528
Regulatory Liabilities - Total	68,210	69,290
Net Regulatory Asset Position	75,796	82,238
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	7,047	6,304
Regulatory Assets - Long-Term	91,808	96,074
Regulatory Assets - Total	98,855	102,378
Regulatory Assets - Remaining Recovery/Refund Period	see notes	see notes
Deferred Marked-to-Market Losses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	6,952	5,208
Regulatory Assets - Long-Term	11,175	10,749
Regulatory Assets - Total	18,127	15,957
Regulatory Assets - Remaining Recovery/Refund Period	38 months	44 months
Deferred Conservation Improvement Program Costs & Accrued Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	2,456	5,234
Regulatory Assets - Long-Term	3,724	2,208
Regulatory Assets - Total	6,180	7,442
Regulatory Assets - Remaining Recovery/Refund Period	24 months	18 months
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	1,007	1,461
Regulatory Assets - Long-Term	960	1,306
Regulatory Assets - Total	1,967	2,767
Regulatory Assets - Remaining Recovery/Refund Period	21 months	33 months
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	510	495
Regulatory Assets - Long-Term	1,885	2,144
Regulatory Assets - Total	2,395	2,639
Regulatory Assets - Remaining Recovery/Refund Period	51 months	57 months
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	273	280
Regulatory Assets - Long-Term	2,113	2,246
Regulatory Assets - Total	2,386	2,526
Regulatory Assets - Remaining Recovery/Refund Period	243 months	249 months
Big Stone II Unrecovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	1,388	1,340
Regulatory Assets - Long-Term	157	862
Regulatory Assets - Total	1,545	2,202
Regulatory Assets - Remaining Recovery/Refund Period	13 months	19 months
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	1,264	785
Regulatory Assets - Long-Term	79	1,325
Regulatory Assets - Total	1,343	2,110
Regulatory Assets - Remaining Recovery/Refund Period	21 months	24 months
General Rate Case Recoverable Expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	596	721
Regulatory Assets - Long-Term	42	285
Regulatory Assets - Total	638	1,006
Regulatory Assets - Remaining Recovery/Refund Period	19 months	25 months
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	100	100
Regulatory Assets - Long-Term	761	811
Regulatory Assets - Total	861	911
Regulatory Assets - Remaining Recovery/Refund Period	103 months	109 months
North Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	1,103	518
Regulatory Assets - Long-Term
Regulatory Assets - Total	1,103	518
Regulatory Assets - Remaining Recovery/Refund Period	12 months	12 months
Minnesota Transmission Rider Accrued Revenue
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	208
Regulatory Assets - Long-Term
Regulatory Assets - Total	208
Regulatory Assets - Remaining Recovery/Refund Period	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	156	343
Regulatory Assets - Long-Term
Regulatory Assets - Total	156	343
Regulatory Assets - Remaining Recovery/Refund Period	5 months	11 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	126	252
Regulatory Assets - Long-Term
Regulatory Assets - Total	126	252
Regulatory Assets - Remaining Recovery/Refund Period	6 months	12 months
Deferred Holding Company Formation Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	55	55
Regulatory Assets - Long-Term	55	83
Regulatory Assets - Total	110	138
Regulatory Assets - Remaining Recovery/Refund Period	24 months	30 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	6	6
Regulatory Liabilities - Long-Term	114	117
Regulatory Liabilities - Total	120	123
Regulatory Liabilities - Remaining Recovery/Refund Period	258 months	264 months
Deferred Marked-to-Market Gains
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	61	96
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	61	96
Regulatory Liabilities - Remaining Recovery/Refund Period	8 months	12 months
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	72	54
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	72	54
Regulatory Liabilities - Remaining Recovery/Refund Period	6 months	12 months
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current
Regulatory Assets - Long-Term	3,895	3,662
Regulatory Assets - Total	3,895	3,662
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	asset lives
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current
Regulatory Liabilities - Current
Regulatory Assets - Long-Term	2,018	2,382
Regulatory Liabilities - Long-Term	2,961	3,379
Regulatory Assets - Total	2,018	2,382
Regulatory Liabilities - Total	2,961	3,379
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives	asset lives
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current
Regulatory Liabilities - Long-Term	64,996	65,610
Regulatory Liabilities - Total	64,996	65,610
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives	asset lives
Accrued Cost-of-Energy Revenue
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	2,065	4,043
Regulatory Assets - Long-Term
Regulatory Assets - Total	2,065	4,043
Regulatory Assets - Remaining Recovery/Refund Period	12 months	12 months
South Dakota - Asset-Based Margin Sharing Shortfall
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current		138
Regulatory Assets - Long-Term
Regulatory Assets - Total		138
Regulatory Assets - Remaining Recovery/Refund Period		2 months
South Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	28	114
Regulatory Assets - Long-Term
Regulatory Assets - Total	28	114
Regulatory Assets - Remaining Recovery/Refund Period	6 months	12 months
Minnesota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		28
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 28
Regulatory Liabilities - Remaining Recovery/Refund Period		see notes

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Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Tax Disclosure [Abstract]
(Loss) Income Before Income Taxes - Continuing Operations	$ (31,379)	$ 5,040	$ (21,591)	$ 11,491
Add Back Canadian Losses not Subject to Income Tax Benefits	917	3,283	1,368	6,780
(Loss) Income Before Income Taxes - Continuing Operations, Subject to Taxes	(30,462)	8,323	(20,223)	18,271
Income Tax (Benefit) Expense Computed at the Company's Net Composite Federal and State Statutory Rate (39%)	(11,880)	3,246	(7,887)	7,126
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(1,831)	(1,929)	(3,818)	(3,905)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue			(676)
Corporate Owned Life Insurance	(13)	(178)	(385)	(266)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(149)	(265)	(371)	(555)
Medicare Part D Subsidy	(194)	(169)	(391)	(361)
Employee Stock Ownership Plan Dividend Deduction	(191)	(190)	(381)	(384)
Canadian Revenue Authority Audit Settlement				156
Investment Tax Credit	(180)	(214)	(360)	(427)
Other Items - Net	(55)	(386)	73	(231)
Income Tax (Benefit) Expense - Continuing Operations	$ (14,493)	$ (85)	$ (14,196)	$ 1,153
Effective Income Tax Rate - Continuing Operations	46.20%	(1.70%)	65.70%	10.00%

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Components of Intangible Assets (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Amortizable Intangible Assets:
Gross Carrying Amount	17,903	18,616
Accumulated Amortization	4,210	4,430
Net Carrying Amount	13,693	14,186
Trade Name
Indefinite-lived Intangible Assets:
Indefinite-lived Intangible Assets, Carrying Amount	1,100	1,100
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	3,661	3,236
Net Carrying Amount	13,150	13,575
Customer Relationships | Maximum
Amortizable Intangible Assets:
Amortization Periods	25 years	25 years
Customer Relationships | Minimum
Amortizable Intangible Assets:
Amortization Periods	15 years	15 years
Covenants Not to Compete
Amortizable Intangible Assets:
Gross Carrying Amount		713
Accumulated Amortization		709
Net Carrying Amount		4
Covenants Not to Compete | Maximum
Amortizable Intangible Assets:
Amortization Periods		5 years
Covenants Not to Compete | Minimum
Amortizable Intangible Assets:
Amortization Periods		3 years
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Gross Carrying Amount	1,092	1,092
Accumulated Amortization	549	485
Net Carrying Amount	543	607
Other Intangible Assets Including Contracts | Maximum
Amortizable Intangible Assets:
Amortization Periods	30 years	30 years
Other Intangible Assets Including Contracts | Minimum
Amortizable Intangible Assets:
Amortization Periods	5 years	5 years

XML

Income Tax Expense - Continuing Operations (Tables)

6 Months Ended

Jun. 30, 2012

Income Tax Disclosure [Abstract]

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

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three and six month periods ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
(Loss) Income Before Income Taxes – Continuing Operations	$	(31,379	)	$	5,040		$	(21,591	)	$	11,491
Add Back Canadian Losses not Subject to Income Tax Benefits		917			3,283			1,368			6,780
(Loss) Income Before Income Taxes – Continuing Operations, Subject to Taxes		(30,462	)		8,323			(20,223	)		18,271
Income Tax (Benefit) Expense Computed at the Company’s Net Composite Federal and State Statutory Rate (39%)		(11,880	)		3,246			(7,887	)		7,126
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,831	)		(1,929	)		(3,818	)		(3,905	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			(676	)		--
Corporate Owned Life Insurance		(13	)		(178	)		(385	)		(266	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(149	)		(265	)		(371	)		(555	)
Medicare Part D Subsidy		(194	)		(169	)		(391	)		(361	)
Employee Stock Ownership Plan Dividend Deduction		(191	)		(190	)		(381	)		(384	)
Canadian Revenue Authority Audit Settlement		--			--			--			156
Investment Tax Credit		(180	)		(214	)		(360	)		(427	)
Other Items – Net		(55	)		(386	)		73			(231	)
Income Tax (Benefit) Expense – Continuing Operations	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153
Effective Income Tax Rate – Continuing Operations		46.2	%		(1.7	)%		65.7	%		10.0	%

Summarized activity related to unrecognized tax benefits

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2012
Balance on January 1	$	12,138
Increases Related to Tax Positions for Prior Years		--
Uncertain Positions Resolved During Year		(8,354	)
Balance on June 30	$	3,784

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Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate (Parenthetical) (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%	39.00%	39.00%

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Breakdown of Assignment of Consolidated Short-Term and Long-Term Debt Outstanding (Parenthetical) (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%
Long-Term Debt, Due Date	Dec. 15, 2016	Dec. 15, 2016
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.65%	4.65%
Long-Term Debt, Due Date	Sep. 01, 2017	Sep. 01, 2017
Senior Unsecured Note 8.89%, due November 30, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	8.89%	8.89%
Long-Term Debt, Due Date	Nov. 30, 2017	Nov. 30, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.85%	4.85%
Long-Term Debt, Due Date	Sep. 01, 2022	Sep. 01, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%

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Effect of Marking to Market Forward Contracts for Purchase and Sale of Electricity and Location and Fair Value Amounts of Related Derivatives (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current Deferred Marked-to-Market Loss	$ 25,334	$ 27,391
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	118,672	124,137
Derivative Liability	20,339	18,770
Regulatory Liability - Current Deferred Marked-to-Market Gain	139	184
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Other Current Asset - Derivative Asset	2,402	3,803
Total Assets	20,529	19,760
Derivative Liability	(20,337)	(18,770)
Total Liabilities	(20,398)	(18,866)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period	131	894	646	763
Forward Electricity Contracts | Deferred Marked-to-Market Losses
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current Deferred Marked-to-Market Loss	6,952	5,208
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	11,175	10,749
Regulatory Liability - Current Deferred Marked-to-Market Gain	$ (61)	$ (96)

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Pension Plan and Other Postretirement Benefits - Additional Information (Detail) (USD $)	1 Months Ended
	Jan. 31, 2012	Dec. 31, 2011
Compensation and Retirement Disclosure [Abstract]
Funding requirement, minimum		$ 3,015,000
Plan contribution	$ 10,000,000

XML

Income Tax Expense - Additional Information (Details)	6 Months Ended
	Jun. 30, 2012
Income Tax Disclosure [Abstract]
Period For Unrecognized Tax Benefits Not Expected Change	6 months

XML

Fair Value of Financial Instruments (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents		$ 14,652
Long-Term Debt (including current maturities)	(471,999)	(474,948)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents		14,652
Long-Term Debt (including current maturities)	$ (532,927)	$ (528,074)

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Status of Lines of Credit (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Line of Credit Facility [Line Items]
Line Limit	$ 370,000
In Use	11,274
Restricted due to Outstanding Letters of Credit	3,900
Available	354,826		364,726
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	200,000	[1]
In Use	2,289	[1]
Restricted due to Outstanding Letters of Credit	850	[1]
Available	196,861	[1]	198,776	[1]
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	8,985
Restricted due to Outstanding Letters of Credit	3,050
Available	$ 157,965		$ 165,950

[1] On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 - Subsequent Events.

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Percent of Sales Revenue by Country

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
United States of America		97.5	%		97.9	%		97.7	%		98.3	%
Canada		1.6	%		1.9	%		1.5	%		1.5	%
All Other Countries		0.9	%		0.2	%		0.8	%		0.2	%

Information on Continuing Operations for Business Segments

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 the three and six month periods ended June 30, 2012 and total assets by business segment as of June 30, 2012 and December 31, 2011 are presented in the following tables:

Operating Revenue

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	78,963		$	78,031		$	168,966		$	169,627
Wind Energy		62,618			55,025			114,720			102,013
Manufacturing		63,581			57,320			129,575			112,681
Construction		37,934			49,133			73,551			86,648
Plastics		41,490			44,373			76,365			62,851
Corporate Revenues and Intersegment Eliminations		(877	)		(584	)		(1,879	)		(1,374	)
Total	$	283,709		$	283,298		$	561,298		$	532,446

Interest Expense

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Electric	$	4,762	$	4,990	$	9,613	$	10,078
Wind Energy		1,614		1,858		3,314		3,559
Manufacturing		1,353		1,255		2,689		2,466
Construction		310		227		563		447
Plastics		346		402		692		765
Corporate and Intersegment Eliminations		92		406		222		1,299
Total	$	8,477	$	9,138	$	17,093	$	18,614

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	(800	)	$	8		$	822		$	2,608
Wind Energy		(15,811	)		(2,174	)		(15,967	)		(3,723	)
Manufacturing		1,658			1,562			3,127			3,352
Construction		(1,164	)		130			(3,940	)		(80	)
Plastics		2,722			2,144			4,897			1,903
Corporate		(1,098	)		(1,755	)		(3,135	)		(2,907	)
Total	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153

Earnings Available for Common Shares

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	5,191		$	7,386		$	16,207		$	18,528
Wind Energy		(24,933	)		(6,566	)		(25,623	)		(12,798	)
Manufacturing		2,420			2,769			4,631			5,427
Construction		(1,756	)		184			(5,927	)		(141	)
Plastics		4,067			3,312			7,320			2,938
Corporate		(2,059	)		(2,144	)		(4,371	)		(3,984	)
Discontinued Operations		(470	)		13,381			(2,718	)		13,864
Total	$	(17,540	)	$	18,322		$	(10,481	)	$	23,834

Identifiable Assets

	June 30,		December 31,
(in thousands)	2012		2011
Electric	$	1,168,902	$	1,170,449
Wind Energy		113,736		149,234
Manufacturing		155,865		154,908
Construction		68,407		69,453
Plastics		87,747		72,200
Corporate		39,222		54,586
Discontinued Operations		521		29,692
Total	$	1,634,400	$	1,700,522

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Significant Accounting Policies [Line Items]
Total Asset Impairment Charges	$ 45,573,000	$ 46,005,000
DMI Industries, Inc
Significant Accounting Policies [Line Items]
Receivable Sales Agreement	40,000,000	40,000,000
Receivables sales agreement effective termination date		Apr. 26, 2012
Nonbinding selling price DMI fixed assets		20,000,000
Working capital net of DMI Industries Inc	66,000,000	66,000,000
Total Asset Impairment Charges		45,600,000
Noncash asset impairment charge (Net of tax benefit)		$ 27,500,000
Noncash asset impairment charges (in dollars per share)		$ 0.76
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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Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Level 1
Assets:
Total Assets	$ 2,471	$ 4,081
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Liabilities:
Derivative Liabilities
Level 1 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets		9
Level 1 | Money Market and Mutual Funds
Assets:
Cash and Cash Equivalents Fair Value Disclosure	110	110
Other Assets	734	254
Level 1 | Money Market Fund
Assets:
Investments - Held by Captive Insurance Company		1,501
Restricted Investments, at Fair Value	1,500	1,500
Level 1 | U.S. Government Debt Securities
Assets:
Investments - Held by Captive Insurance Company		707
Level 1 | Equity Securities
Assets:
Other Assets	127
Level 2
Assets:
Total Assets	10,846	27,843
Liabilities:
Total Liabilities	20,339	18,866
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets	2,402	3,803
Regulatory Assets - Current - Deferred Mark-to-Market Losses		5,208
Regulatory Assets - Deferred Mark-to-Market Losses		10,749
Liabilities:
Derivative Liabilities	20,337	18,770
Regulatory Liabilities - Current - Deferred Mark-to-Market Gains		96
Level 2 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets	27
Liabilities:
Derivative Liabilities	2
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	7,114	8,083
Level 2 | U.S. Government Debt Securities
Assets:
Investments - Held by Captive Insurance Company	$ 1,303

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Components of Net Periodic Benefit Cost (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	$ 1,248	$ 1,175	$ 2,542	$ 2,350
Interest Cost on Projected Benefit Obligation	3,125	3,175	6,233	6,350
Expected Return on Assets	(3,607)	(3,538)	(7,215)	(7,075)
Amortization of Prior-Service Cost	102	100	204	200
Amortization of Net Actuarial Loss	1,289	650	2,520	1,300
Net Periodic Cost	2,157	1,562	4,284	3,125
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	12	21	23	41
Interest Cost on Projected Benefit Obligation	369	408	739	816
Amortization of Prior-Service Cost	19	18	37	37
Amortization of Net Actuarial Loss	81	61	163	122
Net Periodic Cost	481	508	962	1,016
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period	439	425	900	850
Interest Cost on Projected Benefit Obligation	869	850	1,750	1,700
Amortization of Transition Obligation	187	187	374	374
Amortization of Prior-Service Cost	53	50	105	100
Amortization of Net Actuarial Loss	368	213	759	426
Effect of Medicare Part D Expected Subsidy	(533)	(525)	(1,020)	(1,050)
Net Periodic Cost	$ 1,383	$ 1,200	$ 2,868	$ 2,400

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Costs and Estimated Earnings in Excess of Billings that are Included in Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings	$ 75,295	$ 67,109
Billings in Excess of Costs and Estimated Earnings	(15,328)	(9,355)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$ 59,967	$ 57,754

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Information on Continuing Operations for Business Segments (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating Revenue	$ 283,709	$ 283,298	$ 561,298	$ 532,446
Interest Expense	8,477	9,138	17,093	18,614
Income Taxes	(14,493)	(85)	(14,196)	1,153
Earnings Available for Common Shares	(17,540)	18,322	(10,481)	23,834
Identifiable Assets	1,634,400		1,634,400		1,700,522
Electric
Segment Reporting Information [Line Items]
Operating Revenue	78,963	78,031	168,966	169,627
Interest Expense	4,762	4,990	9,613	10,078
Income Taxes	(800)	8	822	2,608
Earnings Available for Common Shares	5,191	7,386	16,207	18,528
Identifiable Assets	1,168,902		1,168,902		1,170,449
Wind Energy
Segment Reporting Information [Line Items]
Operating Revenue	62,618	55,025	114,720	102,013
Interest Expense	1,614	1,858	3,314	3,559
Income Taxes	(15,811)	(2,174)	(15,967)	(3,723)
Earnings Available for Common Shares	(24,933)	(6,566)	(25,623)	(12,798)
Identifiable Assets	113,736		113,736		149,234
Manufacturing
Segment Reporting Information [Line Items]
Operating Revenue	63,581	57,320	129,575	112,681
Interest Expense	1,353	1,255	2,689	2,466
Income Taxes	1,658	1,562	3,127	3,352
Earnings Available for Common Shares	2,420	2,769	4,631	5,427
Identifiable Assets	155,865		155,865		154,908
Construction
Segment Reporting Information [Line Items]
Operating Revenue	37,934	49,133	73,551	86,648
Interest Expense	310	227	563	447
Income Taxes	(1,164)	130	(3,940)	(80)
Earnings Available for Common Shares	(1,756)	184	(5,927)	(141)
Identifiable Assets	68,407		68,407		69,453
Plastics
Segment Reporting Information [Line Items]
Operating Revenue	41,490	44,373	76,365	62,851
Interest Expense	346	402	692	765
Income Taxes	2,722	2,144	4,897	1,903
Earnings Available for Common Shares	4,067	3,312	7,320	2,938
Identifiable Assets	87,747		87,747		72,200
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(877)	(584)	(1,879)	(1,374)
Interest Expense	92	406	222	1,299
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(1,098)	(1,755)	(3,135)	(2,907)
Earnings Available for Common Shares	(2,059)	(2,144)	(4,371)	(3,984)
Identifiable Assets	39,222		39,222		54,586
Discontinued Operations
Segment Reporting Information [Line Items]
Earnings Available for Common Shares	(470)	13,381	(2,718)	13,864
Identifiable Assets	$ 521		$ 521		$ 29,692

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Amounts of Compensation Expense Recognized under Stock-Based Payment Programs (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	$ 618	$ 470	$ 905	$ 922
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	49	72	88	134
Restricted Stock | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	138	195	274	387
Restricted Stock | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	87	133	145	248
Restricted Stock Units (RSUs) | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	51	70	105	153
Performance Shares | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Compensation expense	$ 293	$ 0	$ 293	$ 0

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Information on OTP's Credit Risk Exposure on Delivered and Marked-to-Market Forward Contracts (Detail) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Jun. 30, 2012 Counterparties	Dec. 31, 2011 Counterparties
Net Credit Risk on Forward Energy Contracts
Derivative [Line Items]
Exposure	$ 860	$ 1,677
Counterparties	8	10
Net Credit Risk to Single Largest Counterparty
Derivative [Line Items]
Exposure	$ 348	$ 737

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Amortization Expense for Intangible Assets (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Summary Of Significant Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 246	$ 218	$ 493	$ 442

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Segment Information

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Segment Information

2. Segment Information

The Company’s businesses have been classified into five reportable 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 sell products and provide services to customers primarily in the United States. The five segments are: Electric, Wind Energy, Manufacturing, Construction and Plastics.

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 Energy consists of DMI, 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. The facility in Ontario, Canada was idled in the fourth quarter of 2011 due to a lack of orders for wind towers.

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 and Minnesota 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.

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

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).

The Company’s corporate operating costs include 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 one customer within the Wind Energy segment that accounted for 10.8% of the Company’s consolidated revenues in 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
United States of America		97.5	%		97.9	%		97.7	%		98.3	%
Canada		1.6	%		1.9	%		1.5	%		1.5	%
All Other Countries		0.9	%		0.2	%		0.8	%		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 the three and six month periods ended June 30, 2012 and total assets by business segment as of June 30, 2012 and December 31, 2011 are presented in the following tables:

Operating Revenue

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	78,963		$	78,031		$	168,966		$	169,627
Wind Energy		62,618			55,025			114,720			102,013
Manufacturing		63,581			57,320			129,575			112,681
Construction		37,934			49,133			73,551			86,648
Plastics		41,490			44,373			76,365			62,851
Corporate Revenues and Intersegment Eliminations		(877	)		(584	)		(1,879	)		(1,374	)
Total	$	283,709		$	283,298		$	561,298		$	532,446

Interest Expense

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Electric	$	4,762	$	4,990	$	9,613	$	10,078
Wind Energy		1,614		1,858		3,314		3,559
Manufacturing		1,353		1,255		2,689		2,466
Construction		310		227		563		447
Plastics		346		402		692		765
Corporate and Intersegment Eliminations		92		406		222		1,299
Total	$	8,477	$	9,138	$	17,093	$	18,614

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	(800	)	$	8		$	822		$	2,608
Wind Energy		(15,811	)		(2,174	)		(15,967	)		(3,723	)
Manufacturing		1,658			1,562			3,127			3,352
Construction		(1,164	)		130			(3,940	)		(80	)
Plastics		2,722			2,144			4,897			1,903
Corporate		(1,098	)		(1,755	)		(3,135	)		(2,907	)
Total	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153

Earnings Available for Common Shares

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Electric	$	5,191		$	7,386		$	16,207		$	18,528
Wind Energy		(24,933	)		(6,566	)		(25,623	)		(12,798	)
Manufacturing		2,420			2,769			4,631			5,427
Construction		(1,756	)		184			(5,927	)		(141	)
Plastics		4,067			3,312			7,320			2,938
Corporate		(2,059	)		(2,144	)		(4,371	)		(3,984	)
Discontinued Operations		(470	)		13,381			(2,718	)		13,864
Total	$	(17,540	)	$	18,322		$	(10,481	)	$	23,834

Identifiable Assets

	June 30,		December 31,
(in thousands)	2012		2011
Electric	$	1,168,902	$	1,170,449
Wind Energy		113,736		149,234
Manufacturing		155,865		154,908
Construction		68,407		69,453
Plastics		87,747		72,200
Corporate		39,222		54,586
Discontinued Operations		521		29,692
Total	$	1,634,400	$	1,700,522

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Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions (Detail) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit	$ 2,000		$ 3,423
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	18,337	[1]	15,347	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements
Total Current Liability - Marked-to-Market Loss	$ 20,337		$ 18,770

[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 $ 18,337 $ 15,347 Offsetting Gains with Counterparties under Master Netting Agreements (2,355) (3,471) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,982 $ 11,876

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Inventories (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Finished Goods	$ 24,333	$ 21,373
Work in Process	11,365	11,951
Raw Material, Fuel and Supplies	41,670	44,659
Total Inventories	$ 77,368	$ 77,983

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Share-Based Payments (Tables)

6 Months Ended

Jun. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Compensation expense recognized under stock-based payment programs

On April 16, 2012 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	$21.32	25% per year through April 8, 2016
Restricted Stock Granted to Executive Officers	24,500	$21.32	25% per year through April 8, 2016
Stock Performance Awards Granted to Executive Officers	80,800	$21.75	December 31, 2014
Restricted Stock Units Granted to Employees	12,800	$17.14	100% on April 8, 2016

Amounts of Compensation Expense Recognized under Stock-Based Payment Programs

Compensation expense recognized under the Company’s stock-based payment programs are presented in the table below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Employee Stock Purchase Plan (15% discount)	$	49	$	72	$	88	$	134
Restricted Stock Granted to Directors		138		195		274		387
Restricted Stock Granted to Employees		87		133		145		248
Restricted Stock Units Granted to Employees		51		70		105		153
Stock Performance Awards Granted to Executive Officers		293		--		293		--
Totals	$	618	$	470	$	905	$	922

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Common Shares and Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2012

Stockholders Equity And Earnings Per Share [Abstract]

Reconciliation of Common Shares Outstanding

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2011 through June 30, 2012:

Common Shares Outstanding, December 31, 2011	36,101,695
Issuances:
Restricted Stock Issued to Employees	24,500
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	21,150
Retirements:
Shares Withheld for Individual Income Tax Requirements	(5,072	)
Forfeiture of Unvested Restricted Stock	(1,825	)
Common Shares Outstanding, June 30, 2012	36,164,448

Outstanding Stock Options with Exercise Prices Greater than Average Market Price Excluded from Calculation of 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 June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$24.93 – $31.34

Six Months Ended June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$24.93 – $31.34

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Regulatory Assets and Liabilities - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2012
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	243 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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Summary of Significant Accounting Policies - Asset Impairment Charges (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Summary Of Significant Accounting Policies [Abstract]
Long-Lived Assets	$ 90,846
Accumulated Depreciation - Long-Lived Assets	(45,561)
Goodwill	288
Total Asset Impairment Charges	$ 45,573	$ 46,005

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Short-Term and Long-Term Borrowings (Tables)

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Status of Lines of Credit

The following table presents the status of our lines of credit as of June 30, 2012 and December 31, 2011:

(in thousands)	Line Limit		In Use on June 30, 2012		Restricted due to Outstanding Letters of Credit		Available on June 30, 2012		Available on December 31, 2011
Otter Tail Corporation Credit Agreement1	$	200,000	$	2,289	$	850	$	196,861	$	198,776
OTP Credit Agreement		170,000		8,985		3,050		157,965		165,950
Total	$	370,000	$	11,274	$	3,900	$	354,826	$	364,726
1   On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding

The following tables provide a breakdown of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	8,985	$	--	$	2,289	$	11,274
Long-Term Debt:
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, 20171						50,000		50,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at June 30, 2012						1,808		1,808
Total	$	320,195	$	--	$	151,808	$	472,003
Less: Current Maturities1		--		--		50,170		50,170
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	101,634	$	421,829
Total Short-Term and Long-Term Debt (with current maturities)	$	329,180	$	--	$	154,093	$	483,273
1On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

December 31, 2011 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	--	$	--	$	--
Long-Term Debt:
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 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at December 31, 2011			$	2,868		1,889		4,757
Total	$	320,195	$	2,868	$	151,889	$	474,952
Less: Current Maturities		--		2,868		165		3,033
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	151,720	$	471,915
Total Short-Term and Long-Term Debt (with current maturities)	$	320,195	$	2,868	$	151,885	$	474,948

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Pension Plan and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Pension Plan

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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	1,248		$	1,175		$	2,542		$	2,350
Interest Cost on Projected Benefit Obligation		3,125			3,175			6,233			6,350
Expected Return on Assets		(3,607	)		(3,538	)		(7,215	)		(7,075	)
Amortization of Prior-Service Cost		102			100			204			200
Amortization of Net Actuarial Loss		1,289			650			2,520			1,300
Net Periodic Pension Cost	$	2,157		$	1,562		$	4,284		$	3,125

Executive Survivor and Supplemental Retirement Plan

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 June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Service Cost—Benefit Earned During the Period	$	12	$	21	$	23	$	41
Interest Cost on Projected Benefit Obligation		369		408		739		816
Amortization of Prior-Service Cost		19		18		37		37
Amortization of Net Actuarial Loss		81		61		163		122
Net Periodic Pension Cost	$	481	$	508	$	962	$	1,016

Postretirement Benefits

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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	439		$	425		$	900		$	850
Interest Cost on Projected Benefit Obligation		869			850			1,750			1,700
Amortization of Transition Obligation		187			187			374			374
Amortization of Prior-Service Cost		53			50			105			100
Amortization of Net Actuarial Loss		368			213			759			426
Effect of Medicare Part D Expected Subsidy		(533	)		(525	)		(1,020	)		(1,050	)
Net Periodic Postretirement Benefit Cost	$	1,383		$	1,200		$	2,868		$	2,400

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Summary Of Significant Accounting Policies [Abstract]

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 (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) 815, Derivatives and Hedging. 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Percentage-of-Completion Revenues		36.2	%		38.0	%		34.2	%		36.8	%

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs Incurred on Uncompleted Contracts	$	533,627		$	583,346
Less Billings to Date		(500,959	)		(550,070	)
Plus Estimated Earnings Recognized		27,299			24,478
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs and Estimated Earnings in Excess of Billings	$	75,295		$	67,109
Billings in Excess of Costs and Estimated Earnings		(15,328	)		(9,355	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

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:

	June 30,		December 31,
(in thousands)	2012		2011
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	61,834	$	54,541

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, 2011	$	3,170
Provision for Warranties Issued During the Year		426
Settlements Made During the Year		(552	)
Adjustments to Warranty Estimates for Prior Years		(38	)
Warranty Reserve Balance, June 30, 2012	$	3,006

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:

	June 30,		December 31,
(in thousands)	2012		2011
Accounts Receivable Retained by Customers	$	14,390	$	13,526

Sales of Receivables

DMI was a party to a $40 million receivables sales agreement whereby designated customer accounts receivable were sold to General Electric Capital Corporation (GECC) on a revolving basis. This agreement was terminated effective April 26, 2012. 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 under DMI’s receivables sales agreement with GECC:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Accounts Receivable Sold	$	11,087	$	9,092	$	32,115	$	28,140

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 tables present, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	2,402
Forward Gasoline Purchase Contracts				27
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,114
U.S. Government Debt Securities – Held by Captive Insurance Company				1,303
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		734
Equity Securities - Nonqualified Retirement Savings Plan		127
Total Assets	$	2,471	$	10,846
Liabilities:
Derivative Liabilities:
Forward Energy Contracts	$	--	$	20,337
Forward Gasoline Purchase Contracts				2
Total Liabilities	$	--	$	20,339
In 2012, the Company’s investments in forward gasoline contracts and U.S. government debt securities were moved to level 2 of the fair value hierarchy and the regulatory assets and liabilities are no longer included in the fair value table.

December 31, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	3,803
Forward Gasoline Purchase Contracts		9
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Regulatory Assets – Current:
Deferred Mark-to-Market Losses on Forward Energy Contracts				5,208
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				8,083
U.S. Government Debt Securities – Held by Captive Insurance Company		707
Money Market Fund - Escrow Account IPH Sale		1,501
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		254
Regulatory Assets – Deferred:
Deferred Mark-to-Market Losses on Forward Energy Contracts				10,749
Total Assets	$	4,081	$	27,843
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	18,770
Regulatory Liabilities – Current:
Deferred Mark-to-Market Gains on Forward Energy Contracts				96
Total Liabilities	$	--	$	18,866

Inventories

Inventories consist of the following:

	June 30,		December 31,
(in thousands)	2012		2011
Finished Goods	$	24,333	$	21,373
Work in Process		11,365		11,951
Raw Material, Fuel and Supplies		41,670		44,659
Total Inventories	$	77,368	$	77,983

Asset Impairment Charge

The Company entered into a nonbinding letter of interest in June 2012 to sell the property, plant and equipment of DMI for $20 million, with the Company retaining DMI’s net working capital—approximately $66 million on June 30, 2012. The transaction is expected to close no later than January 3, 2013. The market value for DMI’s assets has been significantly impacted by reduced demand for wind towers due to adverse market conditions affecting the industry, including uncertainty regarding renewal or extension of the Federal Production Tax Credit (PTC) for investments in renewable energy resources, which is set to expire at the end of 2012. Based on the Company’s second quarter 2012 decision to divest DMI’s assets and the price for the fixed assets agreed to in the nonbinding letter of interest, DMI recorded a noncash asset impairment charge of $45.6 million ($27.5 million net-of-tax), or $0.76 per share, in the second quarter of 2012 broken down as follows:

(in thousands)
Long-Lived Assets	$	90,846
Accumulated Depreciation – Long-Lived Assets		(45,561	)
Goodwill		288
Total Asset Impairment Charges	$	45,573

Under the terms of the nonbinding letter of interest, DMI must complete its current backlog of towers ordered for delivery in 2012 before closing can occur. Under these circumstances, accounting rules require that DMI’s assets and results of operations continue to be reported as continuing operations. However, on completion of all remaining tower orders, DMI’s assets will be considered available for immediate sale and the Company expects DMI’s results and any remaining assets will be reported as discontinued operations at the end of 2012. Should the transaction not be completed, the Company plans to close DMI’s plants in West Fargo, North Dakota and Tulsa, Oklahoma and sell DMI’s fixed assets, after DMI finishes its backlog of orders for 2012.

Goodwill and Other Intangible Assets

The following table summarizes changes to goodwill by business segment during 2012:

(in thousands)	Gross Balance December 31, 2011		Accumulated Impairments			Balance (net of impairments) December 31, 2011		Adjustments to Goodwill in 2012			Balance (net of impairments) June 30, 2012
Electric	$	240	$	(240	)	$	--	$	--		$	--
Wind Energy		288		--			288		(288	)		--
Manufacturing		24,445		(12,259	)		12,186		--			12,186
Construction		7,630		--			7,630		1			7,631
Plastics		19,302		--			19,302		--			19,302
Total	$	51,905	$	(12,499	)	$	39,406	$	(287	)	$	39,119

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,661	$	13,150	15 – 25 years
Other Intangible Assets Including Contracts		1,092		549		543	5 – 30 years
Total	$	17,903	$	4,210	$	13,693
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2011(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,236	$	13,575	15 – 25 years
Covenants Not to Compete		713		709		4	3 – 5 years
Other Intangible Assets Including Contracts		1,092		485		607	5 – 30 years
Total	$	18,616	$	4,430	$	14,186
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Amortization Expense – Intangible Assets	$	246	$	218	$	493	$	442

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)	2012		2013		2014		2015		2016
Estimated Amortization Expense – Intangible Assets	$	981	$	977	$	977	$	977	$	945

Supplemental Disclosures of Cash Flow Information

	As of June 30,
(in thousands)	2012		2011
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$	6,558	$	1,326

Reclassifications and Changes to Presentation

The Company’s consolidated statements of income for the three and six month periods ended June 30, 2011 and consolidated statement of cash flows for the six months ended June 30, 2011 reflect the reclassifications of the operating results and cash flows of E.W. Wylie Corporation (Wylie), DMS Health Technologies, Inc. (DMS), and Aviva Sports, Inc. (Aviva), a wholly owned subsidiary of ShoreMaster, Inc. (ShoreMaster), to discontinued operations as a result of the December 2011 sale of Wylie, the January 2012 sale of Aviva and the February 2012 sale of DMS. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or six month periods ended June 30, 2011.

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820, Fair Value Measurement.

	June 30, 2012						December 31, 2011
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	--		$	--		$	14,652		$	14,652
Long-Term Debt (including current maturities)	$	(471,999	)	$	(532,927	)	$	(474,948	)	$	(528,074	)

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Major Components of Assets and Liabilities of Discontinued Operations (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Discontinued Operations and Disposal Groups [Abstract]
Current Assets	$ 521	$ 29,320
Net Plant		372
Assets of Discontinued Operations	521	29,692
Current Liabilities	236	14,740
Deferred Income Taxes	(232)	(1,811)
Deferred Credits - Other		119
Long-Term Debt		715
Liabilities of Discontinued Operations	$ 4	$ 13,763

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Accounts Receivable Retained by Customers Pending Project Completion (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Accounts Receivable Retained by Customers	$ 14,390	$ 13,526

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Segment Information - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2012 Segments	Dec. 31, 2011 Wind Energy
Segment Reporting Information [Line Items]
Number of reportable segments	5
Percentage of revenue by one customer		10.80%

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Breakdown of Assignment of Consolidated Short-Term and Long-Term Debt Outstanding (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Short-Term Debt	$ 11,274
Long-Term Debt	472,003		474,952
Less: Current Maturities	50,170	[1]	3,033
Unamortized Debt Discount	4		4
Total Long-Term Debt	421,829		471,915
Total Short-Term and Long-Term Debt (with current maturities)	483,273		474,948
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	100,000		100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000		33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
Debt Instrument [Line Items]
Long-Term Debt	5,090		5,090
Senior Unsecured Note 8.89%, due November 30, 2017
Debt Instrument [Line Items]
Long-Term Debt	50,000	[1]	50,000
Senior Unsecured Notes 4.63 Percent Due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000		140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000		30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
Debt Instrument [Line Items]
Long-Term Debt	20,105		20,105
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000		42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000		50,000
Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt	1,808		4,757
Otter Tail Power Company
Debt Instrument [Line Items]
Short-Term Debt	8,985
Long-Term Debt	320,195		320,195
Less: Current Maturities
Unamortized Debt Discount
Total Long-Term Debt	320,195		320,195
Total Short-Term and Long-Term Debt (with current maturities)	329,180		320,195
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
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
Debt Instrument [Line Items]
Long-Term Debt	5,090		5,090
Otter Tail Power Company | Senior Unsecured Notes 4.63 Percent Due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000		140,000
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
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
Debt Instrument [Line Items]
Long-Term Debt	20,105		20,105
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000		42,000
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000		50,000
Varistar Corporation
Debt Instrument [Line Items]
Short-Term Debt
Long-Term Debt			2,868
Less: Current Maturities			2,868
Unamortized Debt Discount
Total Long-Term Debt
Total Short-Term and Long-Term Debt (with current maturities)			2,868
Varistar Corporation | Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt			2,868
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	2,289
Long-Term Debt	151,808		151,889
Less: Current Maturities	50,170	[1]	165
Unamortized Debt Discount	4		4
Total Long-Term Debt	101,634		151,720
Total Short-Term and Long-Term Debt (with current maturities)	154,093		151,885
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	100,000		100,000
Otter Tail Corporation | Senior Unsecured Note 8.89%, due November 30, 2017
Debt Instrument [Line Items]
Long-Term Debt	50,000	[1]	50,000
Otter Tail Corporation | Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt	$ 1,808		$ 1,889

[1] On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 - Subsequent Events.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Current Assets
Cash and Cash Equivalents			$ 14,652
Accounts Receivable:
Trade - Net	134,235		116,522
Other	16,602		18,807
Inventories	77,368		77,983
Deferred Income Taxes	12,320		12,307
Accrued Utility Revenues	11,325		13,719
Costs and Estimated Earnings in Excess of Billings	75,295		67,109
Regulatory Assets	25,334		27,391
Other	16,539		21,414
Assets of Discontinued Operations	521		29,692
Total Current Assets	369,539		399,596
Investments	9,056		11,093
Other Assets	27,309		26,997
Goodwill	39,119		39,406
Other Intangibles - Net	14,793		15,286
Deferred Debits
Unamortized Debt Expense	5,783		6,458
Regulatory Assets	118,672		124,137
Total Deferred Debits	124,455		130,595
Plant
Electric Plant in Service	1,380,680		1,372,534
Nonelectric Operations	217,391		310,320
Construction Work in Progress	82,523		54,439
Total Gross Plant	1,680,594		1,737,293
Less Accumulated Depreciation and Amortization	630,465		659,744
Net Plant	1,050,129		1,077,549
Total Assets	1,634,400		1,700,522
Current Liabilities
Short-Term Debt	11,274
Current Maturities of Long-Term Debt	50,170	[1]	3,033
Accounts Payable	118,954		115,514
Accrued Salaries and Wages	18,490		19,043
Accrued Taxes	8,664		11,841
Derivative Liabilities	20,339		18,770
Other Accrued Liabilities	5,540		5,540
Liabilities of Discontinued Operations	4		13,763
Total Current Liabilities	233,435		187,504
Pensions Benefit Liability	98,620		106,818
Other Postretirement Benefits Liability	49,356		48,263
Other Noncurrent Liabilities	22,150		19,002
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	152,598		177,264
Deferred Tax Credits	32,345		33,182
Regulatory Liabilities	68,071		69,106
Other	538		520
Total Deferred Credits	253,552		280,072
Capitalization
Long-Term Debt, Net of Current Maturities	421,829		471,915
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2012 - 36,164,448 Shares; 2011 - 36,101,695 Shares	180,822		180,509
Premium on Common Shares	253,113		253,123
Retained Earnings	109,267		141,248
Accumulated Other Comprehensive Loss	(3,244)		(3,432)
Total Common Equity	539,958		571,448
Total Capitalization	977,287		1,058,863
Total Liabilities and Equity	1,634,400		1,700,522
Cumulative Preferred Shares
Capitalization
Cumulative Preference Shares	15,500		15,500
Cumulative Preference Shares
Capitalization
Cumulative Preference Shares

[1] On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 - Subsequent Events.

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Summary of Changes to Goodwill by Business Segment (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Goodwill [Roll Forward]
Gross Balance December 31, 2011	$ 51,905
Accumulated Impairments	(12,499)
Balance (net of impairments) December 31, 2011	39,406
Adjustments to Goodwill in 2012	(287)
Balance (net of impairments) June 30, 2012	39,119
Electric
Goodwill [Roll Forward]
Gross Balance December 31, 2011	240
Accumulated Impairments	(240)
Balance (net of impairments) December 31, 2011
Adjustments to Goodwill in 2012
Balance (net of impairments) June 30, 2012
Wind Energy
Goodwill [Roll Forward]
Gross Balance December 31, 2011	288
Accumulated Impairments
Balance (net of impairments) December 31, 2011	288
Adjustments to Goodwill in 2012	(288)
Balance (net of impairments) June 30, 2012
Manufacturing
Goodwill [Roll Forward]
Gross Balance December 31, 2011	24,445
Accumulated Impairments	(12,259)
Balance (net of impairments) December 31, 2011	12,186
Adjustments to Goodwill in 2012
Balance (net of impairments) June 30, 2012	12,186
Construction
Goodwill [Roll Forward]
Gross Balance December 31, 2011	7,630
Accumulated Impairments
Balance (net of impairments) December 31, 2011	7,630
Adjustments to Goodwill in 2012	1
Balance (net of impairments) June 30, 2012	7,631
Plastics
Goodwill [Roll Forward]
Gross Balance December 31, 2011	19,302
Accumulated Impairments
Balance (net of impairments) December 31, 2011	19,302
Adjustments to Goodwill in 2012
Balance (net of impairments) June 30, 2012	$ 19,302

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement Of Income and Comprehensive Income [Abstract]
Net (Loss) Income	$ (17,356)	$ 18,828	$ (10,113)	$ 24,524
Unrealized Gain on Available-for-Sale Securities:
Gain Arising During Period	4	31	108	14
Income Tax Expense	(2)	(13)	(43)	(6)
Unrealized Gain on Available-for-Sale Securities - net-of-tax	2	18	65	8
Foreign Currency Translation Adjustment:
Unrealized Net Change During Period		(342)		303
Reversal of Previously Recognized Gains Realized on the Sale of Idaho Pacific Holdings, Inc. (IPH)		(6,068)		(6,068)
Income Tax Benefit		1,988		1,788
Foreign Currency Translation Adjustment - net-of-tax		(4,422)		(3,977)
Pension and Postretirement Benefit Plans:
Actuarial Loss -- Regulatory Allocation Adjustment (ESSRP)				(1,621)
Amortization of Unrecognized Postretirement Benefit Losses and Costs	102	713	204	884
Income Tax (Expense) Benefit	(40)	(285)	(81)	295
Pension and Postretirement Benefit Plans - net-of-tax	62	428	123	(442)
Total Other Comprehensive Income (Loss)	64	(3,976)	188	(4,411)
Total Comprehensive (Loss) Income	$ (17,292)	$ 14,852	$ (9,925)	$ 20,113

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Recognized but Unrealized Net Gains on Forward Energy and Capacity Purchases and Sales Expected to be Realized on Settlement (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012
Derivative [Line Items]
Net Gain	$ 131
Forward Contracts | 3rd Qtr 2012
Derivative [Line Items]
Net Gain	5
Forward Contracts | 4th Qtr 2012
Derivative [Line Items]
Net Gain	123
Forward Contracts | 1st Qtr 2013
Derivative [Line Items]
Net Gain	$ 3

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Percentages of Consolidated Revenues Recorded under Percentage-of-Completion Method (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Summary Of Significant Accounting Policies [Abstract]
Percentage-of-Completion Revenues	36.20%	38.00%	34.20%	36.80%

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Outstanding Stock Options with Exercise Prices Greater than Average Market Price Excluded from Calculation of Diluted Earnings per Share (Detail) (Stock Options, USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options Outstanding	92,497	172,460	92,497	172,460
Range of Exercise Prices, Lower Range	$ 24.93	$ 24.93	$ 24.93	$ 24.93
Range of Exercise Prices, Upper Range	$ 27.25	$ 31.34	$ 27.25	$ 31.34

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Subsequent Events

6 Months Ended

Jun. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

18. Subsequent Events

Early Repayment of Debt

On July 13, 2012 the Company prepaid in full its outstanding $50 million, 8.89% Senior Unsecured Note due November 30, 2017 (the Cascade Note) issued pursuant to the Note Purchase Agreement dated as of February 23, 2007, as amended, between the Company and Cascade Investment, L.L.C. (Cascade). Immediately before the prepayment, the Cascade Note bore interest at 8.89% annually. The price paid by the Company to prepay the Cascade Note was $63,031,000, which included the principal amount of the Cascade Note plus accrued interest of $531,000 and a negotiated prepayment premium of $12,500,000. The Company used funds available under the Otter Tail Corporation Credit Agreement for the prepayment. This early retirement reflects the Company’s desire to lower its long-term debt outstanding given its recent divestitures and its anticipated divestiture of DMI. On repayment, $606,000 in unamortized debt expense related to this note was immediately recognized as expense along with the $12,500,000 negotiated prepayment premium, which will reduce diluted earnings per share by $0.22 in 2012. The $50,000,000 of debt retired on July 13, 2012 was included in current maturities of long-term debt on the Company’s June 30, 2012 consolidated balance sheet. Cascade owned approximately 9.6% of the Company’s outstanding common stock as of December 31, 2011.

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Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$ 533,627	$ 583,346
Less Billings to Date	(500,959)	(550,070)
Plus Estimated Earnings Recognized	27,299	24,478
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$ 59,967	$ 57,754

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2012

Summary Of Significant Accounting Policies [Abstract]

Percentages of Consolidated Revenues Recorded under Percentage-of-Completion Method

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Percentage-of-Completion Revenues		36.2	%		38.0	%		34.2	%		36.8	%

Costs and Estimated Earnings in Excess of Billings that are Included in Consolidated Balance Sheets

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs Incurred on Uncompleted Contracts	$	533,627		$	583,346
Less Billings to Date		(500,959	)		(550,070	)
Plus Estimated Earnings Recognized		27,299			24,478
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

Costs and Estimated Earnings in Excess of Billings that are Included in 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.

	June 30,			December 31,
(in thousands)	2012			2011
Costs and Estimated Earnings in Excess of Billings	$	75,295		$	67,109
Billings in Excess of Costs and Estimated Earnings		(15,328	)		(9,355	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

Costs and Estimated Earnings in Excess of Billings of DMI Industries, Inc. (DMI)

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:

	June 30,		December 31,
(in thousands)	2012		2011
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	61,834	$	54,541

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, 2011	$	3,170
Provision for Warranties Issued During the Year		426
Settlements Made During the Year		(552	)
Adjustments to Warranty Estimates for Prior Years		(38	)
Warranty Reserve Balance, June 30, 2012	$	3,006

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:

	June 30,		December 31,
(in thousands)	2012		2011
Accounts Receivable Retained by Customers	$	14,390	$	13,526

Schedule Of Trade Receivables Under Receivables Purchase Agreement

Following are the amounts of accounts receivable sold under DMI’s receivables sales agreement with GECC:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Accounts Receivable Sold	$	11,087	$	9,092	$	32,115	$	28,140

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables present, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	2,402
Forward Gasoline Purchase Contracts				27
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,114
U.S. Government Debt Securities – Held by Captive Insurance Company				1,303
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		734
Equity Securities - Nonqualified Retirement Savings Plan		127
Total Assets	$	2,471	$	10,846
Liabilities:
Derivative Liabilities:
Forward Energy Contracts	$	--	$	20,337
Forward Gasoline Purchase Contracts				2
Total Liabilities	$	--	$	20,339
In 2012, the Company’s investments in forward gasoline contracts and U.S. government debt securities were moved to level 2 of the fair value hierarchy and the regulatory assets and liabilities are no longer included in the fair value table.

December 31, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	3,803
Forward Gasoline Purchase Contracts		9
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Regulatory Assets – Current:
Deferred Mark-to-Market Losses on Forward Energy Contracts				5,208
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				8,083
U.S. Government Debt Securities – Held by Captive Insurance Company		707
Money Market Fund - Escrow Account IPH Sale		1,501
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		254
Regulatory Assets – Deferred:
Deferred Mark-to-Market Losses on Forward Energy Contracts				10,749
Total Assets	$	4,081	$	27,843
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	18,770
Regulatory Liabilities – Current:
Deferred Mark-to-Market Gains on Forward Energy Contracts				96
Total Liabilities	$	--	$	18,866

Inventories

Inventories consist of the following:

	June 30,		December 31,
(in thousands)	2012		2011
Finished Goods	$	24,333	$	21,373
Work in Process		11,365		11,951
Raw Material, Fuel and Supplies		41,670		44,659
Total Inventories	$	77,368	$	77,983

Schedule Of Asset Impairment Charges

Based on the Company’s second quarter 2012 decision to divest DMI’s assets and the price for the fixed assets agreed to in the nonbinding letter of interest, DMI recorded a noncash asset impairment charge of $45.6 million ($27.5 million net-of-tax), or $0.76 per share, in the second quarter of 2012 broken down as follows:

(in thousands)
Long-Lived Assets	$	90,846
Accumulated Depreciation – Long-Lived Assets		(45,561	)
Goodwill		288
Total Asset Impairment Charges	$	45,573

Summary of Changes to Goodwill by Business Segment

Goodwill and Other Intangible Assets

The following table summarizes changes to goodwill by business segment during 2012:

(in thousands)	Gross Balance December 31, 2011		Accumulated Impairments			Balance (net of impairments) December 31, 2011		Adjustments to Goodwill in 2012			Balance (net of impairments) June 30, 2012
Electric	$	240	$	(240	)	$	--	$	--		$	--
Wind Energy		288		--			288		(288	)		--
Manufacturing		24,445		(12,259	)		12,186		--			12,186
Construction		7,630		--			7,630		1			7,631
Plastics		19,302		--			19,302		--			19,302
Total	$	51,905	$	(12,499	)	$	39,406	$	(287	)	$	39,119

Components Of Intangible Assets

The following table summarizes the components of the Company’s intangible assets at June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,661	$	13,150	15 – 25 years
Other Intangible Assets Including Contracts		1,092		549		543	5 – 30 years
Total	$	17,903	$	4,210	$	13,693
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2011(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,236	$	13,575	15 – 25 years
Covenants Not to Compete		713		709		4	3 – 5 years
Other Intangible Assets Including Contracts		1,092		485		607	5 – 30 years
Total	$	18,616	$	4,430	$	14,186
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

Amortization Expense for Intangible Assets

The amortization expense for these intangible assets was:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Amortization Expense – Intangible Assets	$	246	$	218	$	493	$	442

Estimated Amortization Expense for Intangible Assets

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)	2012		2013		2014		2015		2016
Estimated Amortization Expense – Intangible Assets	$	981	$	977	$	977	$	977	$	945

Supplemental Disclosure of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of June 30,
(in thousands)	2012		2011
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$	6,558	$	1,326

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Amounts of Compensation Expense Recognized under Stock-Based Payment Programs (Parenthetical) (Detail) (Employee Stock Purchase Plan)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
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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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash Flows from Operating Activities
Net (Loss) Income	$ (10,113)	$ 24,524
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Loss (Gain) from Sale of Discontinued Operations	3,544	(13,252)
Income from Discontinued Operations	(826)	(934)
Depreciation and Amortization	34,171	34,658
Asset Impairment Charge	46,005
Deferred Tax Credits	(1,045)	(1,281)
Deferred Income Taxes	(9,632)	5,650
Change in Deferred Debits and Other Assets	9,960	7,648
Discretionary Contribution to Pension Plan	(10,000)
Change in Noncurrent Liabilities and Deferred Credits	6,095	1,212
Allowance for Equity (Other) Funds Used During Construction	(378)	(292)
Change in Derivatives Net of Regulatory Deferral	748	45
Stock Compensation Expense - Equity Awards	612	921
Other-Net	453	654
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(15,508)	(30,298)
Change in Inventories	615	(6,235)
Change in Other Current Assets	(10,917)	(2,743)
Change in Payables and Other Current Liabilities	6,905	8,967
Change in Interest and Income Taxes Receivable/Payable	(6,549)	(162)
Net Cash Provided by Continuing Operations	44,140	29,082
Net Cash Provided by Discontinued Operations	1,377	11,655
Net Cash Provided by Operating Activities	45,517	40,737
Cash Flows from Investing Activities
Capital Expenditures	(69,443)	(39,777)
Proceeds from Disposal of Noncurrent Assets	5,560	1,233
Net (Increase) Decrease in Other Investments	(268)	937
Net Cash Used in Investing Activities - Continuing Operations	(64,151)	(37,607)
Net Proceeds from Sale of Discontinued Operations	24,278	84,363
Net Cash Used in Investing Activities - Discontinued Operations	(11,705)	(13,503)
Net Cash (Used in) Provided by Investing Activities	(51,578)	33,253
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	7,352	(5,627)
Net Short-Term Borrowings (Repayments)	11,274	(46,777)
Payments for Retirement of Common Stock and Common Stock Issuance Expenses	(196)	(152)
Proceeds from Issuance of Long-Term Debt		2,007
Short-Term and Long-Term Debt Issuance Expenses	(10)	(688)
Payments for Retirement of Long-Term Debt	(2,949)	(167)
Dividends Paid and Other Distributions	(21,980)	(21,952)
Net Cash Used in Financing Activities - Continuing Operations	(6,509)	(73,356)
Net Cash Used in Financing Activities - Discontinued Operations	(1,409)	(310)
Net Cash Used in Financing Activities	(7,918)	(73,666)
Net Change in Cash and Cash Equivalents - Discontinued Operations	(673)
Effect of Foreign Exchange Rate Fluctuations on Cash - Discontinued Operations		(324)
Net Change in Cash and Cash Equivalents	(14,652)
Cash and Cash Equivalents at Beginning of Period	14,652
Cash and Cash Equivalents at End of Period

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Consolidated Balance Sheets (Parentheticals) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Common Shares, Par Value	$ 5	$ 5
Common Shares, Authorized	50,000,000	50,000,000
Common Shares, Outstanding	36,164,448	36,101,695
Cumulative Preferred Shares
Cumulative Shares, Authorized	1,500,000	1,500,000
Cumulative Shares, Without Par Value
Cumulative Shares, Outstanding	155,000	155,000
Cumulative Preference Shares
Cumulative Shares, Authorized	1,000,000	1,000,000
Cumulative Shares, Without Par Value
Cumulative Shares, Outstanding

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Short-Term and Long-Term Borrowings

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

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 June 30, 2012 and December 31, 2011:

(in thousands)	Line Limit		In Use on June 30, 2012		Restricted due to Outstanding Letters of Credit		Available on June 30, 2012		Available on December 31, 2011
Otter Tail Corporation Credit Agreement1	$	200,000	$	2,289	$	850	$	196,861	$	198,776
OTP Credit Agreement		170,000		8,985		3,050		157,965		165,950
Total	$	370,000	$	11,274	$	3,900	$	354,826	$	364,726
1   On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

Long-Term Debt Retirement

In April 2012, ShoreMaster, Inc. (ShoreMaster), a wholly owned subsidiary of Varistar Corporation, exercised a purchase option on a building it had been leasing under a capital lease and paid off the remaining $2.8 million balance of its lease obligation.

The following tables provide a breakdown of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	8,985	$	--	$	2,289	$	11,274
Long-Term Debt:
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, 20171						50,000		50,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at June 30, 2012						1,808		1,808
Total	$	320,195	$	--	$	151,808	$	472,003
Less: Current Maturities1		--		--		50,170		50,170
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	101,634	$	421,829
Total Short-Term and Long-Term Debt (with current maturities)	$	329,180	$	--	$	154,093	$	483,273
1On July 13, 2012 the Company used funds available under the Otter Tail Corporation Credit Agreement to repay in full the $50 million Cascade Note referred to in Note 18 – Subsequent Events.

December 31, 2011 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	--	$	--	$	--
Long-Term Debt:
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 4.63%, due December 1, 2021		140,000						140,000
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 3.95% at December 31, 2011			$	2,868		1,889		4,757
Total	$	320,195	$	2,868	$	151,889	$	474,952
Less: Current Maturities		--		2,868		165		3,033
Unamortized Debt Discount		--		--		4		4
Total Long-Term Debt	$	320,195	$	--	$	151,720	$	471,915
Total Short-Term and Long-Term Debt (with current maturities)	$	320,195	$	2,868	$	151,885	$	474,948

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 31, 2012
Document And Entity Information [Abstract]
Entity Registrant Name	OTTER TAIL CORP
Entity Central Index Key	0001466593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		36,164,448
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2

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Pension Plan and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2012

Compensation and Retirement Disclosure [Abstract]

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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	1,248		$	1,175		$	2,542		$	2,350
Interest Cost on Projected Benefit Obligation		3,125			3,175			6,233			6,350
Expected Return on Assets		(3,607	)		(3,538	)		(7,215	)		(7,075	)
Amortization of Prior-Service Cost		102			100			204			200
Amortization of Net Actuarial Loss		1,289			650			2,520			1,300
Net Periodic Pension Cost	$	2,157		$	1,562		$	4,284		$	3,125

Cash flows—The Company had a minimum pension plan funding requirement of $3,015,000 as of December 31, 2011, and made a discretionary plan contribution of $10,000,000 in January 2012. The Company is not required to make, and has not made, any additional contributions in 2012. The Company did not make a contribution to its pension plan in the six months ended June 30, 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 June 30,				Six Months Ended June 30,
(in thousands)	2012		2011		2012		2011
Service Cost—Benefit Earned During the Period	$	12	$	21	$	23	$	41
Interest Cost on Projected Benefit Obligation		369		408		739		816
Amortization of Prior-Service Cost		19		18		37		37
Amortization of Net Actuarial Loss		81		61		163		122
Net Periodic Pension Cost	$	481	$	508	$	962	$	1,016

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 June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Service Cost—Benefit Earned During the Period	$	439		$	425		$	900		$	850
Interest Cost on Projected Benefit Obligation		869			850			1,750			1,700
Amortization of Transition Obligation		187			187			374			374
Amortization of Prior-Service Cost		53			50			105			100
Amortization of Net Actuarial Loss		368			213			759			426
Effect of Medicare Part D Expected Subsidy		(533	)		(525	)		(1,020	)		(1,050	)
Net Periodic Postretirement Benefit Cost	$	1,383		$	1,200		$	2,868		$	2,400

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Income Tax Expense - Continuing Operations Unrecognized tax benefits (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance on January 1	$ 12,138
Increases Related to Tax Positions for Prior Years
Uncertain Positions Resolved During Year	(8,354)
Balance on June 30	$ 3,784

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Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues
Electric	$ 78,909	$ 77,978	$ 168,847	$ 169,504
Nonelectric	204,800	205,320	392,451	362,942
Total Operating Revenues	283,709	283,298	561,298	532,446
Operating Expenses
Production Fuel - Electric	12,455	17,080	27,879	36,657
Purchased Power - Electric System Use	12,328	7,894	26,486	20,271
Electric Operation and Maintenance Expenses	32,407	28,687	62,420	57,395
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)	167,612	179,241	330,602	319,580
Other Nonelectric Expenses	17,189	17,014	34,680	30,090
Asset Impairment Charge	45,573		46,005
Depreciation and Amortization	17,118	17,552	34,171	34,658
Property Taxes - Electric	2,670	2,417	5,287	4,826
Total Operating Expenses	307,352	269,885	567,530	503,477
Operating (Loss) Income	(23,643)	13,413	(6,232)	28,969
Interest Charges	8,477	9,138	17,093	18,614
Other Income	741	765	1,734	1,136
(Loss) Income from Continuing Operations Before Income Taxes	(31,379)	5,040	(21,591)	11,491
Income Tax (Benefit) Expense - Continuing Operations	(14,493)	(85)	(14,196)	1,153
Net (Loss) Income from Continuing Operations	(16,886)	5,125	(7,395)	10,338
Discontinued Operations
(Loss) Income - net of Income Tax (Benefit) Expense of ($11), $280, $573, and $568 for the respective periods	(15)	451	826	934
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of ($35), $3,515, ($169), and $3,515 for the respective periods	(455)	13,252	(3,544)	13,252
Net (Loss) Income from Discontinued Operations	(470)	13,703	(2,718)	14,186
Net (Loss) Income	(17,356)	18,828	(10,113)	24,524
Preferred Dividend Requirements and Other Adjustments	184	506	368	690
Earnings Available for Common Shares	$ (17,540)	$ 18,322	$ (10,481)	$ 23,834
Average Number of Common Shares Outstanding - Basic	36,031,447	35,926,124	36,013,313	35,901,489
Average Number of Common Shares Outstanding - Diluted	36,031,447	36,163,805	36,013,313	36,139,170
Basic Earnings Per Common Share:
Continuing Operations	$ (0.48)	$ 0.14	$ (0.22)	$ 0.28
Discontinued Operations	$ (0.01)	$ 0.37	$ (0.07)	$ 0.38
Earnings Per Share, Basic, Total	$ (0.49)	$ 0.51	$ (0.29)	$ 0.66
Diluted Earnings Per Common Share:
Continuing Operations	$ (0.48)	$ 0.14	$ (0.22)	$ 0.28
Discontinued Operations	$ (0.01)	$ 0.37	$ (0.07)	$ 0.38
Earnings Per Share, Diluted, Total	$ (0.49)	$ 0.51	$ (0.29)	$ 0.66
Dividends Declared Per Common Share	$ 0.2975	$ 0.2975	$ 0.5950	$ 0.5950

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Forward Contracts Classified as Derivatives

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, Fair Value Measurement.

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 June 30, 2012 and December 31, 2011, and the change in the Company’s consolidated balance sheet position from December 31, 2011 to June 30, 2012 and December 31, 2010 to June 30, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Other Current Asset – Derivative Asset	$	2,402		$	3,803
Regulatory Asset – Current Deferred Marked-to-Market Loss		6,952			5,208
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		11,175			10,749
Total Assets		20,529			19,760
Derivative Liability		(20,337	)		(18,770	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(61	)		(96	)
Total Liabilities		(20,398	)		(18,866	)
Fair Value Adjustments Included in Earnings	$	131		$	894

(in thousands)	Year-to-Date June 30, 2012			Year-to-Date June 30, 2011
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	894		$	763
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(700	)		(151	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33	)		(86	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		161			526
Changes in Fair Value of Contracts Entered into in Current Period		(30	)		120
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	131		$	646

The recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on June 30, 2012 are expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	3rd Qtr 2012		4th Qtr 2012		1st Qtr 2013		Total
Net Gain	$	5	$	123	$	3	$	131

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					Six Months Ended
	June 30,					June 30,
(in thousands)	2012			2011		2012		2011
Net Gains (Losses) on Forward Electric Energy Contracts	$	(50	)	$	139	$	144	$	131

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. The Company has 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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	860		8	$	1,677		10
Net Credit Risk to Single Largest Counterparty	$	348			$	737

OTP had a net credit risk exposure to eight counterparties with investment grade credit ratings. OTP had no exposure at June 30, 2012 or December 31, 2011 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The 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 June 30, 2012 and December 31, 2011:

Current Liability – Marked-to-Market Loss  (in thousands)	June 30, 2012			December 31, 2011
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	2,000		$	3,423
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		18,337			15,347
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	20,337		$	18,770
1Certain 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	$	18,337		$	15,347
Offsetting Gains with Counterparties under Master Netting Agreements		(2,355	)		(3,471	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	15,982		$	11,876

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Regulatory Assets and Liabilities

6 Months Ended

Jun. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

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:

	June 30, 2012						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	7,047	$	91,808	$	98,855	see notes
Deferred Marked-to-Market Losses		6,952		11,175		18,127	38 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		2,456		3,724		6,180	24 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,895		3,895	asset lives
Big Stone II Unrecovered Project Costs – Minnesota		510		1,885		2,395	51 months
Debt Reacquisition Premiums		273		2,113		2,386	243 months
Accrued Cost-of-Energy Revenues		2,065		--		2,065	12 months
Deferred Income Taxes		--		2,018		2,018	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,007		960		1,967	21 months
Big Stone II Unrecovered Project Costs – North Dakota		1,388		157		1,545	13 months
North Dakota Renewable Resource Rider Accrued Revenues		1,264		79		1,343	21 months
North Dakota Transmission Rider Accrued Revenues		1,103		--		1,103	12 months
Big Stone II Unrecovered Project Costs – South Dakota		100		761		861	103 months
General Rate Case Recoverable Expenses		596		42		638	19 months
Minnesota Transmission Rider Accrued Revenue		208		--		208	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		156		--		156	5 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		126		--		126	6 months
Deferred Holding Company Formation Costs		55		55		110	24 months
South Dakota Transmission Rider Accrued Revenues		28		--		28	6 months
Total Regulatory Assets	$	25,334	$	118,672	$	144,006
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	64,996	$	64,996	asset lives
Deferred Income Taxes		--		2,961		2,961	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		114		120	258 months
South Dakota – Nonasset-Based Margin Sharing Excess		72		--		72	6 months
Deferred Marked-to-Market Gains		61		--		61	8 months
Total Regulatory Liabilities	$	139	$	68,071	$	68,210
Net Regulatory Asset Position	$	25,195	$	50,601	$	75,796

	December 31, 2011						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	6,304	$	96,074	$	102,378	see notes
Deferred Marked-to-Market Losses		5,208		10,749		15,957	44 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		5,234		2,208		7,442	18 months
Accrued Cost-of-Energy Revenue		4,043		--		4,043	12 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,662		3,662	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,461		1,306		2,767	33 months
Big Stone II Unrecovered Project Costs – Minnesota		495		2,144		2,639	57 months
Debt Reacquisition Premiums		280		2,246		2,526	249 months
Deferred Income Taxes		--		2,382		2,382	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		1,340		862		2,202	19 months
North Dakota Renewable Resource Rider Accrued Revenues		785		1,325		2,110	24 months
General Rate Case Recoverable Expenses		721		285		1,006	25 months
Big Stone II Unrecovered Project Costs – South Dakota		100		811		911	109 months
North Dakota Transmission Rider Accrued Revenue		518		--		518	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		343		--		343	11 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		252		--		252	12 months
Deferred Holding Company Formation Costs		55		83		138	30 months
South Dakota – Asset-Based Margin Sharing Shortfall		138		--		138	2 months
South Dakota Transmission Rider Accrued Revenues		114		--		114	12 months
Total Regulatory Assets	$	27,391	$	124,137	$	151,528
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,610	$	65,610	asset lives
Deferred Income Taxes		--		3,379		3,379	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		117		123	264 months
Deferred Marked-to-Market Gains		96		--		96	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		54		--		54	12 months
Minnesota Transmission Rider Accrued Refund		28		--		28	see notes
Total Regulatory Liabilities	$	184	$	69,106	$	69,290
Net Regulatory Asset Position	$	27,207	$	55,031	$	82,238

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 June 30, 2012 are related to forward purchases of energy scheduled for delivery through August 2015.

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

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 – 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 243 months.

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

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 through June 30, 2012 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of June 30, 2012.

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.

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 June 30, 2012.

North Dakota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facility and net operating costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of June 30, 2012.

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. 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.

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

Minnesota Transmission Rider Accrued Revenue relates to revenues earned on qualifying transmission system facilities and net operating costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of June 30, 2012.

MISO Schedule 26 Transmission Cost Recovery Rider True-up relates to the Minnesota jurisdictional portion of MISO Schedule 26 for regional transmission cost recovery that was included in the calculation of the Minnesota Transmission Rider and subsequently adjusted to reflect actual billing amounts in the schedule.

South Dakota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facility and net operating costs incurred to serve South Dakota customers that have not been billed to South Dakota customers as of June 30, 2012.

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

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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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Summary Of Significant Accounting Policies [Abstract]

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 (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) 815, Derivatives and Hedging. 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Percentage-of-Completion Revenues		36.2	%		38.0	%		34.2	%		36.8	%

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs Incurred on Uncompleted Contracts	$	533,627		$	583,346
Less Billings to Date		(500,959	)		(550,070	)
Plus Estimated Earnings Recognized		27,299			24,478
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

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

	June 30,			December 31,
(in thousands)	2012			2011
Costs and Estimated Earnings in Excess of Billings	$	75,295		$	67,109
Billings in Excess of Costs and Estimated Earnings		(15,328	)		(9,355	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts	$	59,967		$	57,754

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:

	June 30,		December 31,
(in thousands)	2012		2011
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$	61,834	$	54,541

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, 2011	$	3,170
Provision for Warranties Issued During the Year		426
Settlements Made During the Year		(552	)
Adjustments to Warranty Estimates for Prior Years		(38	)
Warranty Reserve Balance, June 30, 2012	$	3,006

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:

	June 30,		December 31,
(in thousands)	2012		2011
Accounts Receivable Retained by Customers	$	14,390	$	13,526

Sales of Receivables

Sales of Receivables

DMI was a party to a $40 million receivables sales agreement whereby designated customer accounts receivable were sold to General Electric Capital Corporation (GECC) on a revolving basis. This agreement was terminated effective April 26, 2012. 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 under DMI’s receivables sales agreement with GECC:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Accounts Receivable Sold	$	11,087	$	9,092	$	32,115	$	28,140

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 tables present, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	2,402
Forward Gasoline Purchase Contracts				27
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,114
U.S. Government Debt Securities – Held by Captive Insurance Company				1,303
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		734
Equity Securities - Nonqualified Retirement Savings Plan		127
Total Assets	$	2,471	$	10,846
Liabilities:
Derivative Liabilities:
Forward Energy Contracts	$	--	$	20,337
Forward Gasoline Purchase Contracts				2
Total Liabilities	$	--	$	20,339
In 2012, the Company’s investments in forward gasoline contracts and U.S. government debt securities were moved to level 2 of the fair value hierarchy and the regulatory assets and liabilities are no longer included in the fair value table.

December 31, 2011 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	3,803
Forward Gasoline Purchase Contracts		9
Money Market Fund - Escrow Account IPH Sale		1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Regulatory Assets – Current:
Deferred Mark-to-Market Losses on Forward Energy Contracts				5,208
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				8,083
U.S. Government Debt Securities – Held by Captive Insurance Company		707
Money Market Fund - Escrow Account IPH Sale		1,501
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		254
Regulatory Assets – Deferred:
Deferred Mark-to-Market Losses on Forward Energy Contracts				10,749
Total Assets	$	4,081	$	27,843
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	18,770
Regulatory Liabilities – Current:
Deferred Mark-to-Market Gains on Forward Energy Contracts				96
Total Liabilities	$	--	$	18,866

Inventories

Inventories

Inventories consist of the following:

	June 30,		December 31,
(in thousands)	2012		2011
Finished Goods	$	24,333	$	21,373
Work in Process		11,365		11,951
Raw Material, Fuel and Supplies		41,670		44,659
Total Inventories	$	77,368	$	77,983

Asset Impairment Charges

Asset Impairment Charge

The Company entered into a nonbinding letter of interest in June 2012 to sell the property, plant and equipment of DMI for $20 million, with the Company retaining DMI’s net working capital—approximately $66 million on June 30, 2012. The transaction is expected to close no later than January 3, 2013. The market value for DMI’s assets has been significantly impacted by reduced demand for wind towers due to adverse market conditions affecting the industry, including uncertainty regarding renewal or extension of the Federal Production Tax Credit (PTC) for investments in renewable energy resources, which is set to expire at the end of 2012. Based on the Company’s second quarter 2012 decision to divest DMI’s assets and the price for the fixed assets agreed to in the nonbinding letter of interest, DMI recorded a noncash asset impairment charge of $45.6 million ($27.5 million net-of-tax), or $0.76 per share, in the second quarter of 2012 broken down as follows:

(in thousands)
Long-Lived Assets	$	90,846
Accumulated Depreciation – Long-Lived Assets		(45,561	)
Goodwill		288
Total Asset Impairment Charges	$	45,573

Under the terms of the nonbinding letter of interest, DMI must complete its current backlog of towers ordered for delivery in 2012 before closing can occur. Under these circumstances, accounting rules require that DMI’s assets and results of operations continue to be reported as continuing operations. However, on completion of all remaining tower orders, DMI’s assets will be considered available for immediate sale and the Company expects DMI’s results and any remaining assets will be reported as discontinued operations at the end of 2012. Should the transaction not be completed, the Company plans to close DMI’s plants in West Fargo, North Dakota and Tulsa, Oklahoma and sell DMI’s fixed assets, after DMI finishes its backlog of orders for 2012.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

The following table summarizes changes to goodwill by business segment during 2012:

(in thousands)	Gross Balance December 31, 2011		Accumulated Impairments			Balance (net of impairments) December 31, 2011		Adjustments to Goodwill in 2012			Balance (net of impairments) June 30, 2012
Electric	$	240	$	(240	)	$	--	$	--		$	--
Wind Energy		288		--			288		(288	)		--
Manufacturing		24,445		(12,259	)		12,186		--			12,186
Construction		7,630		--			7,630		1			7,631
Plastics		19,302		--			19,302		--			19,302
Total	$	51,905	$	(12,499	)	$	39,406	$	(287	)	$	39,119

Other Intangible Assets

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at June 30, 2012 and December 31, 2011:

June 30, 2012 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,661	$	13,150	15 – 25 years
Other Intangible Assets Including Contracts		1,092		549		543	5 – 30 years
Total	$	17,903	$	4,210	$	13,693
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2011(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	3,236	$	13,575	15 – 25 years
Covenants Not to Compete		713		709		4	3 – 5 years
Other Intangible Assets Including Contracts		1,092		485		607	5 – 30 years
Total	$	18,616	$	4,430	$	14,186
Indefinite-lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Amortization Expense – Intangible Assets	$	246	$	218	$	493	$	442

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)	2012		2013		2014		2015		2016
Estimated Amortization Expense – Intangible Assets	$	981	$	977	$	977	$	977	$	945

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of June 30,
(in thousands)	2012		2011
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$	6,558	$	1,326

Reclassifications and Changes to Presentation

Reclassifications and Changes to Presentation

The Company’s consolidated statements of income for the three and six month periods ended June 30, 2011 and consolidated statement of cash flows for the six months ended June 30, 2011 reflect the reclassifications of the operating results and cash flows of E.W. Wylie Corporation (Wylie), DMS Health Technologies, Inc. (DMS), and Aviva Sports, Inc. (Aviva), a wholly owned subsidiary of ShoreMaster, Inc. (ShoreMaster), to discontinued operations as a result of the December 2011 sale of Wylie, the January 2012 sale of Aviva and the February 2012 sale of DMS. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or six month periods ended June 30, 2011.

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

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 Cash Equivalents—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 market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820, Fair Value Measurement.

	June 30, 2012						December 31, 2011
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	--		$	--		$	14,652		$	14,652
Long-Term Debt (including current maturities)	$	(471,999	)	$	(532,927	)	$	(474,948	)	$	(528,074	)

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Discontinued Operations - Additional Information (Detail) (USD $)	6 Months Ended		0 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	May 06, 2012 IPH	May 31, 2012 IPH	Dec. 31, 2011 IPH	Dec. 29, 2011 Wylie	Jan. 31, 2012 Aviva	Feb. 29, 2012 DMS
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations	$ 24,278,000	$ 84,363,000	$ 87,000,000			$ 25,000,000	$ 300,000	$ 28,300,000
Proceeds from sale of discontinued operations, deposited in an escrow account			3,000,000
Portion Of Deposits Released From Escrow Account				1,500,000
Discontinued operations, purchase price adjustments					$ 1,200,000

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Retained Earnings Restriction

6 Months Ended

Jun. 30, 2012

Retained Earnings Restrictions [Abstract]

Retained Earnings Restriction

8. Retained Earnings Restriction

The Company’s Restated Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders by the amount of any declared but unpaid dividends to holders of the Company’s cumulative preferred shares. Under these provisions none of the Company’s retained earnings were restricted at June 30, 2012.

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Realized and Unrealized Net (Losses)/Gains on Forward Energy Contracts Included in Electric Operating Revenues (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Gains (Losses) on Forward Electric Energy Contracts	$ (50)	$ 139	$ 144	$ 131

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Common Shares and Earnings Per Share

6 Months Ended

Jun. 30, 2012

Stockholders Equity And Earnings Per Share [Abstract]

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, 2011 through June 30, 2012:

Common Shares Outstanding, December 31, 2011	36,101,695
Issuances:
Restricted Stock Issued to Employees	24,500
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	21,150
Retirements:
Shares Withheld for Individual Income Tax Requirements	(5,072	)
Forfeiture of Unvested Restricted Stock	(1,825	)
Common Shares Outstanding, June 30, 2012	36,164,448

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 June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$24.93 – $31.34

Six Months Ended June 30,	Options Outstanding	Range of Exercise Prices
2012	92,497	$24.93 – $27.25
2011	172,460	$24.93 – $31.34

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Share-Based Payments

6 Months Ended

Jun. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Payments

7. Share-Based Payments

The Company has five share-based payment programs.

Stock Incentive Awards

On April 16, 2012 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	$21.32	25% per year through April 8, 2016
Restricted Stock Granted to Executive Officers	24,500	$21.32	25% per year through April 8, 2016
Stock Performance Awards Granted to Executive Officers	80,800	$21.75	December 31, 2014
Restricted Stock Units Granted to Employees	12,800	$17.14	100% on April 8, 2016

The restricted shares granted to the Company’s nonemployee directors and executive officers 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 161,600 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, 2012 through December 31, 2014. The aggregate target share award is 80,800 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, 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 June 30, 2012 the remaining unrecognized compensation expense related to stock-based compensation was approximately $4.1 million (before income taxes) which will be amortized over a weighted-average period of 2.7 years.

Compensation expense recognized under the Company’s stock-based payment programs are presented in the table below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2012		2011		2012		2011
Employee Stock Purchase Plan (15% discount)	$	49	$	72	$	88	$	134
Restricted Stock Granted to Directors		138		195		274		387
Restricted Stock Granted to Employees		87		133		145		248
Restricted Stock Units Granted to Employees		51		70		105		153
Stock Performance Awards Granted to Executive Officers		293		--		293		--
Totals	$	618	$	470	$	905	$	922

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Construction Commitments

At December 31, 2011 OTP had commitments under contracts in connection with construction programs aggregating approximately $41.0 million for 2012. OTP’s share of additional commitments under contracts entered into in 2012 related to CapX2020 transmission projects, the Big Stone AQCS project, and a water handling project at Coyote Station increased its total construction commitments as of June 30, 2012 by $18.7 million for the remainder of 2012, $21.9 million for 2013, $4.2 million for 2014 and $19.5 million for 2015.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for capacity and energy requirements under agreements extending through 2032. OTP did not enter into any agreements for the purchase of additional capacity or energy to meet future capacity and energy requirements in the first six months of 2012.

OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP did not commit to any additional coal purchases in the first six months of 2012.

Commitment for Development of New Coal Source for Coyote Station

Coyote Station owners, including OTP, entered into an agreement on May 1, 2012 with the North American Coal Corporation for pre-commencement development work at Coyote Creek Mine near Coyote Station. OTP’s current share of the Coyote Station owners’ commitment to develop Coyote Creek Mine is for up to $0.9 million plus any interest or capital charges. All applicable development work is to be completed in 2012. If the lignite sales agreement (LSA) currently under negotiation is signed, the pre-contract development costs will be paid over a 52-month period starting in May 2016 when the first coal would be delivered under the LSA. If the LSA is not signed, the Coyote Station owners can terminate development activities and would be billed for all pre-contract costs incurred with payment due within 30 days of receipt of the invoice.

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 June 30, 2012 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 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 all of these items result in a liabilities being incurred, the loss could be as high as $7.0 million. Additionally, the Company may become subject to significant claims of which its management is unaware, or the claims of which its management is aware may result in the Company incurring a significantly greater liability than it anticipates.

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Reconciliation of Common Shares Outstanding (Detail)	6 Months Ended
	Jun. 30, 2012
Stockholders Equity And Earnings Per Share [Abstract]
Common Shares Outstanding, December 31, 2011	36,101,695
Issuances:
Restricted Stock Issued to Employees	24,500
Restricted Stock Issued to Nonemployee Directors	24,000
Vesting of Restricted Stock Units	21,150
Retirements:
Shares Withheld for Individual Income Tax Requirements	(5,072)
Forfeiture of Unvested Restricted Stock	(1,825)
Common Shares Outstanding, June 30, 2012	36,164,448

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Subsequent Events - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended		0 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jul. 13, 2012 Subsequent Event	Jul. 13, 2012 Subsequent Event 8.89% Senior Unsecured Note due November 30, 2017	Dec. 31, 2011 Subsequent Event Cascade Investment, L.L.C. (Cascade) 8.89% Senior Unsecured Note due November 30, 2017
Subsequent Event [Line Items]
Prepayment of cascade note pursuant to the Note Purchase Agreement						$ 50,000,000
Effective interest rate during the period pursuant to the Note Purchase Agreement						8.89%
Aggregate price paid pursuant to the Note Purchase Agreement						63,031,000
Accrued interest pursuant to the Note Purchase Agreement						531,000
Negotiated prepayment premium pursuant to the Note Purchase Agreement						12,500,000
Unamortized debt expense recognized pursuant to the Note Purchase Agreement						$ 606,000
Income Loss From Continuing Operations Per Diluted Share	$ (0.48)	$ 0.14	$ (0.22)	$ 0.28	$ (0.22)
Ownership interest in parent by cascade							9.60%

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Summary of Stock Incentive Awards to Nonemployee Directors, Executive Officers and Key Employees (Detail) (USD $)	0 Months Ended
	Apr. 16, 2012
Restricted Stock | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	24,000
Grant-Date Fair Value per Share	$ 21.32
Vesting Percentage	25.00%
Vesting Date	Apr. 08, 2016
Restricted Stock | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	24,500
Grant-Date Fair Value per Share	$ 21.32
Vesting Percentage	25.00%
Vesting Date	Apr. 08, 2016
Performance Awards | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	80,800
Grant-Date Fair Value per Share	$ 21.75
Vesting Percentage
Vesting Date	Dec. 31, 2014
Restricted Stock Units (RSUs) | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	12,800
Grant-Date Fair Value per Share	$ 17.14
Vesting Percentage	100.00%
Vesting Date	Apr. 08, 2016

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Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions (Parenthetical) (Detail) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$ 18,337	[1]	$ 15,347	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	(2,355)		(3,471)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$ 15,982		$ 11,876

[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 $ 18,337 $ 15,347 Offsetting Gains with Counterparties under Master Netting Agreements (2,355) (3,471) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,982 $ 11,876

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Major Components of Assets and Liabilities of Discontinued Operations

Following are summary presentations of the results of discontinued operations for three and six month periods ended June 30, 2012 and 2011:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Operating Revenues	$	--		$	41,282		$	16,352		$	99,460
Operating Expenses		26			41,799			14,928			99,343
Operating (Loss) Income		(26	)		(517	)		1,424			117
Interest Charges		--			11			147			31
Other Income		--			1,259			122			1,416
Income Tax (Benefit) Expense		(11	)		280			573			568
Net (Loss) Income from Operations		(15	)		451			826			934
(Loss) Gain on Disposition Before Taxes		(490	)		16,767			(3,713	)		16,767
Income Tax (Benefit) Expense on Disposition		(35	)		3,515			(169	)		3,515
Net (Loss) Gain on Disposition		(455	)		13,252			(3,544	)		13,252
Net (Loss) Income	$	(470	)	$	13,703		$	(2,718	)	$	14,186

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Current Assets	$	521		$	29,320
Net Plant		--			372
Assets of Discontinued Operations	$	521		$	29,692
Current Liabilities	$	236		$	14,740
Deferred Income Taxes		(232	)		(1,811	)
Deferred Credits - Other		--			119
Long-Term Debt		--			715
Liabilities of Discontinued Operations	$	4		$	13,763

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Percent of Sales Revenue by Country (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	97.50%	97.90%	97.70%	98.30%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	1.60%	1.90%	1.50%	1.50%
All Other Countries
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.90%	0.20%	0.80%	0.20%

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Discontinued Operations

6 Months Ended

Jun. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

17. Discontinued Operations

On May 6, 2011, the Company completed the sale of IPH for approximately $87.0 million in cash, including $3.0 million deposited in an escrow account, of which $1.5 million was released to the Company in May 2012. In the second half of 2011, the IPH sales proceeds were reduced by $1.2 million related to a purchase price adjustment. On December 29, 2011 the Company completed the sale of Wylie, its trucking business, for approximately $25.0 million in cash. On January 18, 2012 the Company sold the assets of Aviva for $0.3 million in cash. On February 29, 2012 the Company sold DMS for $28.3 million in cash. Following are summary presentations of the results of discontinued operations for three and six month periods ended June 30, 2012 and 2011:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
Operating Revenues	$	--		$	41,282		$	16,352		$	99,460
Operating Expenses		26			41,799			14,928			99,343
Operating (Loss) Income		(26	)		(517	)		1,424			117
Interest Charges		--			11			147			31
Other Income		--			1,259			122			1,416
Income Tax (Benefit) Expense		(11	)		280			573			568
Net (Loss) Income from Operations		(15	)		451			826			934
(Loss) Gain on Disposition Before Taxes		(490	)		16,767			(3,713	)		16,767
Income Tax (Benefit) Expense on Disposition		(35	)		3,515			(169	)		3,515
Net (Loss) Gain on Disposition		(455	)		13,252			(3,544	)		13,252
Net (Loss) Income	$	(470	)	$	13,703		$	(2,718	)	$	14,186

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of June 30, 2012 and December 31, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Current Assets	$	521		$	29,320
Net Plant		--			372
Assets of Discontinued Operations	$	521		$	29,692
Current Liabilities	$	236		$	14,740
Deferred Income Taxes		(232	)		(1,811	)
Deferred Credits - Other		--			119
Long-Term Debt		--			715
Liabilities of Discontinued Operations	$	4		$	13,763

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Regulatory Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet

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

	June 30, 2012						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	7,047	$	91,808	$	98,855	see notes
Deferred Marked-to-Market Losses		6,952		11,175		18,127	38 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		2,456		3,724		6,180	24 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,895		3,895	asset lives
Big Stone II Unrecovered Project Costs – Minnesota		510		1,885		2,395	51 months
Debt Reacquisition Premiums		273		2,113		2,386	243 months
Accrued Cost-of-Energy Revenues		2,065		--		2,065	12 months
Deferred Income Taxes		--		2,018		2,018	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,007		960		1,967	21 months
Big Stone II Unrecovered Project Costs – North Dakota		1,388		157		1,545	13 months
North Dakota Renewable Resource Rider Accrued Revenues		1,264		79		1,343	21 months
North Dakota Transmission Rider Accrued Revenues		1,103		--		1,103	12 months
Big Stone II Unrecovered Project Costs – South Dakota		100		761		861	103 months
General Rate Case Recoverable Expenses		596		42		638	19 months
Minnesota Transmission Rider Accrued Revenue		208		--		208	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		156		--		156	5 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		126		--		126	6 months
Deferred Holding Company Formation Costs		55		55		110	24 months
South Dakota Transmission Rider Accrued Revenues		28		--		28	6 months
Total Regulatory Assets	$	25,334	$	118,672	$	144,006
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	64,996	$	64,996	asset lives
Deferred Income Taxes		--		2,961		2,961	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		114		120	258 months
South Dakota – Nonasset-Based Margin Sharing Excess		72		--		72	6 months
Deferred Marked-to-Market Gains		61		--		61	8 months
Total Regulatory Liabilities	$	139	$	68,071	$	68,210
Net Regulatory Asset Position	$	25,195	$	50,601	$	75,796

	December 31, 2011						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	$	6,304	$	96,074	$	102,378	see notes
Deferred Marked-to-Market Losses		5,208		10,749		15,957	44 months
Deferred Conservation Improvement Program Costs & Accrued Incentives		5,234		2,208		7,442	18 months
Accrued Cost-of-Energy Revenue		4,043		--		4,043	12 months
Accumulated ARO Accretion/Depreciation Adjustment		--		3,662		3,662	asset lives
Minnesota Renewable Resource Rider Accrued Revenues		1,461		1,306		2,767	33 months
Big Stone II Unrecovered Project Costs – Minnesota		495		2,144		2,639	57 months
Debt Reacquisition Premiums		280		2,246		2,526	249 months
Deferred Income Taxes		--		2,382		2,382	asset lives
Big Stone II Unrecovered Project Costs – North Dakota		1,340		862		2,202	19 months
North Dakota Renewable Resource Rider Accrued Revenues		785		1,325		2,110	24 months
General Rate Case Recoverable Expenses		721		285		1,006	25 months
Big Stone II Unrecovered Project Costs – South Dakota		100		811		911	109 months
North Dakota Transmission Rider Accrued Revenue		518		--		518	12 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND		343		--		343	11 months
MISO Schedule 26 Transmission Cost Recovery Rider True-up		252		--		252	12 months
Deferred Holding Company Formation Costs		55		83		138	30 months
South Dakota – Asset-Based Margin Sharing Shortfall		138		--		138	2 months
South Dakota Transmission Rider Accrued Revenues		114		--		114	12 months
Total Regulatory Assets	$	27,391	$	124,137	$	151,528
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,610	$	65,610	asset lives
Deferred Income Taxes		--		3,379		3,379	asset lives
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		117		123	264 months
Deferred Marked-to-Market Gains		96		--		96	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		54		--		54	12 months
Minnesota Transmission Rider Accrued Refund		28		--		28	see notes
Total Regulatory Liabilities	$	184	$	69,106	$	69,290
Net Regulatory Asset Position	$	27,207	$	55,031	$	82,238

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Supplemental Disclosure of Cash Flow Information (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Jun. 30, 2011
Summary Of Significant Accounting Policies [Abstract]
Accounts Payable Outstanding Related to Capital Additions	$ 6,558	$ 1,326

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Amounts of Accounts Receivable Sold and Discounts, Fees and Commissions Paid (Detail) (DMI Industries, Inc, USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
DMI Industries, Inc
Receivables [Line Items]
Accounts Receivable Sold	$ 11,087	$ 9,092	$ 32,115	$ 28,140

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Consolidated Statements of Income (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Statement [Abstract]
Income tax expense or benefit on Income (Loss) from discontinued operation during phase-out period	$ (11)	$ 280	$ 573	$ 568
Income Tax (Benefit) Expense on Disposition	$ (35)	$ 3,515	$ (169)	$ 3,515

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Rate and Regulatory Matters

6 Months Ended

Jun. 30, 2012

Rate And Regulatory Matters [Abstract]

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, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (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. Final rates went into effect October 1, 2011. The overall increase to customers was approximately 1.6% compared to the authorized interim rate increase of 3.8%, which resulted in an interim rate refund to Minnesota retail electric customers of approximately $3.9 million in the fourth quarter of 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%. OTP’s authorized rates of return are based on a capital structure of 48.28% long term debt and 51.72% common equity.

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

Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.

The MPUC issued an order on January 12, 2010 finding OTP’s Luverne Wind Farm project eligible for cost recovery through the Minnesota Renewable Resource Adjustment (MNRRA). The 2010 annual MNRRA cost recovery filing was made on December 31, 2009 with a requested effective date of April 1, 2010. The MPUC approved OTP’s petition for a 2010 MNRRA in the third quarter of 2010 with implementation effective September 1, 2010. The 2010 MNRRA was in place from September 1, 2010 through September 30, 2011 with a recovery of $17.0 million.

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 the MNRRA regulatory asset. OTP has a regulatory asset of $2.0 million for revenues that are eligible for recovery through the MNRRA rider that have not been billed to Minnesota customers as of June 30, 2012. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by revised filing on July 25, 2012. The filing included a request to extend the period of the new rate for 18 months, which would reduce the current balance of unrecovered costs to zero.

Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or otherwise deemed eligible by the MPUC. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

OTP requested recovery of its transmission investments being recovered through its Minnesota TCR rider rate as part of its general rate case filed on April 2, 2010. In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs currently being recovered through OTP’s Minnesota 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 has a regulatory asset of $0.2 million for revenues that are eligible for recovery through the Minnesota TCR rider that have not been billed to Minnesota customers as of June 30, 2012. OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. The update to OTP’s Minnesota TCR rider, approved by the MPUC on March 26, 2012, went into effect April 1, 2012.

In this TCR rider update, the MNPUC addressed how to handle utility investments in transmission facilities that qualify for regional cost allocation under the MISO tariff. MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from the other MISO utilities. The MPUC considered two possible approaches to recovery of OTP’s transmission investments in excess of amounts allocated back to its retail load-serving obligations: (1) a split method in which OTP’s Minnesota retail customers would be responsible only for the investment allocated back to OTP through the MISO tariff, or (2) an all-in method in which OTP’s retail customers would be responsible for the entire investment OTP made with an offsetting credit for revenues received from other MISO utilities under the MISO tariff. The MPUC approved using the all-in method on March 26, 2012.

On May 24, 2012, OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. If approval is obtained to include projects in the rider, investment in the approved projects will be included in the annual Minnesota TCR rider update filings and recovery of the investment will begin through the TCR rider rates if subsequently approved by the MPUC.

Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal. On July 1, 2010 OTP filed its plan for 2011-2013. The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.

A written order was issued by the MPUC on January 11, 2012 approving the recovery of $3.5 million for the 2010 MNCIP financial incentives. Beginning in January 2012, OTP’s MNCIP Conservation Cost Recovery Adjustment (CCRA) increased from 3.0% to 3.8% for all Minnesota retail electric customers. On March 30, 2012 OTP submitted its annual 2011 financial incentive filing request for $2.6 million.

OTP has a regulatory asset of $6.2 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 June 30, 2012. OTP recognized revenue for Minnesota conservation costs earned totaling $0.9 million and $1.7 million, respectively, in the three and six month periods ended June 30, 2012, compared with $1.2 million and $3.0 million, respectively, in the three and six month periods ended June 30, 2011.

North Dakota

Renewable Resource Cost Recovery Rider—The 2010 North Dakota Renewable Resource Adjustment (NDRRA) was in place for the period of September 1, 2010 through March 31, 2012 with a recovery of $15.6 million. On December 29, 2011 OTP submitted its annual update to the renewable rider with an April 1, 2012 effective date. OTP’s request for an updated NDRRA was approved by the North Dakota Public Service Commission (NDPSC) on March 21, 2012 and went into effect April 1, 2012. The 2011 NDRRA has an expected recovery of $10.1 million over the period April 1, 2012 through March 31, 2013. OTP has a regulatory asset of $1.3 million for revenues that are eligible for recovery through the NDRRA rider that have not been billed to North Dakota customers as of June 30, 2012.

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 filed a request for an initial North Dakota TCR rider with the NDPSC on April 29, 2011. On April 25, 2012 the NDPSC approved the use of the split method of cost recovery for the North Dakota TCR rider and the rider rate to be effective May 1, 2012. OTP has a regulatory asset of $1.1 million for revenues that are eligible for recovery through the North Dakota TCR rider that have not been billed to North Dakota customers as of June 30, 2012.

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% 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 was approved by the SDPUC and implemented on December 1, 2011.

Federal

Wholesale power sales and transmission rates are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Federal Power Act of 1935, as amended. The FERC is an independent agency, with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

Effective January 1, 2010, the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). OTP was also authorized by the FERC to recover: (1) in its formula rate 100% of prudently incurred Construction Work in Progress (CWIP) in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects that OTP is investing in, including the Fargo project, Bemidji project and Brookings project.

On December 16, 2010, FERC approved the cost allocation for a new classification of projects in MISO called Multi-Value Projects (MVP). MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011, FERC reaffirmed the MVP cost allocation on Rehearing. The MVP cost allocation is currently being challenged at the United States Court of Appeals, Seventh Circuit.

Effective January 1, 2012, the FERC authorized OTP to recover 100% CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVP’s in MISO’s 2011 Transmission Expansion Plan: the Big Stone South – Brookings MVP and the Ellendale – Big Stone South MVP.

The Big Stone South – Brookings Project—OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. A portion of this line is anticipated to use previously obtained Big Stone II transmission route permits and easements and is expected to be in service in 2017. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. OTP expects, in the third quarter of 2012, to file a request with the SDPUC for recertification of a portion of the line route that was approved as part of the Big Stone II transmission development. OTP and Xcel Energy expect to make a joint route permit filing in the first quarter of 2013 for the remaining portion of the project.

The Ellendale – Big Stone South Project—OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU).  MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. This project will require regulatory approval from both the SDPUC and the NDPSC. Route permits are expected to be filed with the respective commissions in the third quarter of 2013.

Capacity Expansion 2020 (CapX2020)

CapX2020 is a joint initiative of eleven 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 230 kV 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. Recovery of OTP’s CapX2020 transmission investments will be through the MISO Tariff (the Brookings Project as an MVP) and Minnesota, North Dakota and South Dakota TCR Riders.

The Fargo Project—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011.

The MPUC approved a route permit for the St. Cloud to Fargo portion of the Fargo Project 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. Construction on Phase 2 began in November 2011 and is expected to be completed in the fourth quarter of 2013.

A combined North Dakota Certificate of Corridor Compatibility and route permit application was submitted to the NDPSC on October 3, 2011. The NDPSC conducted a hearing on January 30, 2012. The project expects to receive final permit approval from the NDPSC during the third quarter of 2012. Once all final permits have been received from the NDPSC, project agreements for Phase 3, which consists of the line section between Alexandria, Minnesota and Fargo, North Dakota, would be executed with the project partners.

The Brookings Project—The MPUC approved the final line segment route permit for the Brookings Project on February 3, 2011. OTP executed project agreements with co-owners on January 13, 2012. The NDPSC approved the request for an Advanced Determination of Prudence (ADP) on November 10, 2011. The South Dakota route permit was approved by the SDPUC in June 2011. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011.This project will be placed in service in segments with the earliest segment being placed in service in the summer of 2013 and the last segment placed in service during the first quarter of 2015.

The Bemidji Project—OTP serves as the lead utility for the Bemidji Project. This line is expected to be in service before the end of 2012. The MPUC approved the CON for this project on July 9, 2009. A route permit application was approved by the MPUC on October 28, 2010. The joint state and federal Environmental Impact Statement 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 a judgment 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 August 6, 2012 a Consent Order Approving Stipulation for Entry of Consent Decree was issued in federal court, which enjoins the LLBO from interfering with the construction, operation, maintenance or repair of the transmission line. The federal litigation is now concluded. In conjunction with the stipulated agreement, the tribal court dismissed the LLBO’s action and the LLBO has withdrawn its petition to the MPUC.

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. On March 29, 2012 the EPA took final action to approve South Dakota’s Regional Haze State Implementation Plan (SIP), finding that South Dakota’s SIP submittal met all applicable regional haze regulations. The EPA’s final approval of the SIP was published in the Federal Register on April 26, 2012, with an effective date of May 29, 2012.

On January 14, 2011 OTP filed a petition asking the MPUC for 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 December 20, 2011 the MPUC granted OTP’s petition for ADP for the Big Stone Plant Air Quality Control System (AQCS). The MPUC written order was issued on January 23, 2012.

OTP filed an application for an ADP with the NDPSC on May 20, 2011, and the NDPSC approved OTP’s request for an ADP on May 9, 2012.

On March 30, 2012 OTP requested approval from the SDPUC for an Environmental Cost Recovery Rider to recover costs associated with the Big Stone Plant AQCS, with a proposed effective date of October 1, 2012. This rider is designed to recover the revenue requirements plus carrying charges of the Big Stone AQCS project while under construction as well as after completion of the project until placed into base rates through the filing of a rate case. For the initial period of October 1, 2012 through September 30, 2013, OTP is requesting revenue requirement recovery on expenditures incurred for the Big Stone Plant AQCS. Information requests for this filing were received on July 13, 2012.

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Change in Consolidated Balance Sheet Location and Fair Values of Forward Contracts for Purchase and Sale of Electricity (Detail) (Forward Contracts, USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Forward Contracts
Derivatives, Fair Value [Line Items]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$ 894	$ 763
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods	(700)	(151)
Changes in Fair Value of Contracts Entered into in Prior Periods	(33)	(86)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period	161	526
Changes in Fair Value of Contracts Entered into in Current Period	(30)	120
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$ 131	$ 646

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Results of Discontinued Operations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Discontinued Operations and Disposal Groups [Abstract]
Operating Revenues		$ 41,282	$ 16,352	$ 99,460
Operating Expenses	26	41,799	14,928	99,343
Operating (Loss) Income	(26)	(517)	1,424	117
Interest Charges		11	147	31
Other Income		1,259	122	1,416
Income Tax (Benefit) Expense	(11)	280	573	568
Net (Loss) Income from Operations	(15)	451	826	934
(Loss) Gain on Disposition Before Taxes	(490)	16,767	(3,713)	16,767
Income Tax (Benefit) Expense on Disposition	(35)	3,515	(169)	3,515
Net (Loss) Gain on Disposition	(455)	13,252	(3,544)	13,252
Net (Loss) Income	$ (470)	$ 13,703	$ (2,718)	$ 14,186

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Share-Based Payments - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	0 Months Ended			6 Months Ended
	Jun. 30, 2012 Project	Apr. 16, 2012 Performance Shares Executive Officer	Apr. 16, 2012 Performance Shares Maximum Executive Officer	Apr. 16, 2012 Performance Shares Minimum Executive Officer	Jun. 30, 2012 Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of share-based payment programs	5
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		161,600
Aggregate target common shares award		80,800
Percentage of actual payment of the target amount			200.00%	0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period					4 years
Unrecognized amount of compensation expense related to stock-based compensation	$ 4.1
Weighted-average period of amortization	2 years 8 months

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Forward Contracts Classified as Derivatives (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of Marking to Market Forward Contracts for Purchase and Sale of Electricity and Location and Fair Value Amounts of Related Derivatives

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 June 30, 2012 and December 31, 2011, and the change in the Company’s consolidated balance sheet position from December 31, 2011 to June 30, 2012 and December 31, 2010 to June 30, 2011:

(in thousands)	June 30, 2012			December 31, 2011
Other Current Asset – Derivative Asset	$	2,402		$	3,803
Regulatory Asset – Current Deferred Marked-to-Market Loss		6,952			5,208
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		11,175			10,749
Total Assets		20,529			19,760
Derivative Liability		(20,337	)		(18,770	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(61	)		(96	)
Total Liabilities		(20,398	)		(18,866	)
Fair Value Adjustments Included in Earnings	$	131		$	894

Change in Consolidated Balance Sheet Location and Fair Values of Forward Contracts for Purchase and Sale of Electricity

(in thousands)	Year-to-Date June 30, 2012			Year-to-Date June 30, 2011
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	894		$	763
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(700	)		(151	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33	)		(86	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		161			526
Changes in Fair Value of Contracts Entered into in Current Period		(30	)		120
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	131		$	646

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

The recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on June 30, 2012 are expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)	3rd Qtr 2012		4th Qtr 2012		1st Qtr 2013		Total
Net Gain	$	5	$	123	$	3	$	131

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					Six Months Ended
	June 30,					June 30,
(in thousands)	2012			2011		2012		2011
Net Gains (Losses) on Forward Electric Energy Contracts	$	(50	)	$	139	$	144	$	131

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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	860		8	$	1,677		10
Net Credit Risk to Single Largest Counterparty	$	348			$	737

Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of June 30, 2012 and December 31, 2011:

Current Liability – Marked-to-Market Loss  (in thousands)	June 30, 2012			December 31, 2011
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	2,000		$	3,423
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		18,337			15,347
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	20,337		$	18,770
1Certain 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	$	18,337		$	15,347
Offsetting Gains with Counterparties under Master Netting Agreements		(2,355	)		(3,471	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	15,982		$	11,876

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Short Term and Long Term Borrowings - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended	6 Months Ended
	Jul. 13, 2012 Subsequent Event 8.89% Senior Unsecured Note due November 30, 2017	Jun. 30, 2012 ShoreMaster, Inc.
Debt Instrument [Line Items]
Repayment of capital lease obligation		$ 2.8
Prepayment of cascade note pursuant to the Note Purchase Agreement	$ 50

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Costs and Estimated Earnings in Excess of Billings (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Uncompleted Contracts [Line Items]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$ 75,295	$ 67,109
DMI Industries, Inc
Uncompleted Contracts [Line Items]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI	$ 61,834	$ 54,541

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Income Tax Expense Continuing Operations

6 Months Ended

Jun. 30, 2012

Income Tax Disclosure [Abstract]

Income Tax Expense - Continuing Operations

15. Income Tax Expense – Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three and six month periods ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2012			2011			2012			2011
(Loss) Income Before Income Taxes – Continuing Operations	$	(31,379	)	$	5,040		$	(21,591	)	$	11,491
Add Back Canadian Losses not Subject to Income Tax Benefits		917			3,283			1,368			6,780
(Loss) Income Before Income Taxes – Continuing Operations, Subject to Taxes		(30,462	)		8,323			(20,223	)		18,271
Income Tax (Benefit) Expense Computed at the Company’s Net Composite Federal and State Statutory Rate (39%)		(11,880	)		3,246			(7,887	)		7,126
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,831	)		(1,929	)		(3,818	)		(3,905	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			(676	)		--
Corporate Owned Life Insurance		(13	)		(178	)		(385	)		(266	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(149	)		(265	)		(371	)		(555	)
Medicare Part D Subsidy		(194	)		(169	)		(391	)		(361	)
Employee Stock Ownership Plan Dividend Deduction		(191	)		(190	)		(381	)		(384	)
Canadian Revenue Authority Audit Settlement		--			--			--			156
Investment Tax Credit		(180	)		(214	)		(360	)		(427	)
Other Items – Net		(55	)		(386	)		73			(231	)
Income Tax (Benefit) Expense – Continuing Operations	$	(14,493	)	$	(85	)	$	(14,196	)	$	1,153
Effective Income Tax Rate – Continuing Operations		46.2	%		(1.7	)%		65.7	%		10.0	%

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2012
Balance on January 1	$	12,138
Increases Related to Tax Positions for Prior Years		--
Uncertain Positions Resolved During Year		(8,354	)
Balance on June 30	$	3,784

The balance of unrecognized tax benefits as of June 30, 2012 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 30, 2012 is not expected to change significantly within the next six months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. No interest is accrued on tax uncertainties as of June 30, 2012.