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 September 30, 2013

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:

October 31, 2013 – 36,270,696 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements
	Consolidated Balance Sheets – September 30, 2013 and December 31, 2012 (not audited)	2 & 3
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2013 and 2012 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2013 and 2012 (not audited)	5
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2013 and 2012 (not audited)	6
	Notes to Condensed Consolidated Financial Statements (not audited)	7-36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36-55
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56-57
Item 4.	Controls and Procedures	58
Part II. Other Information
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 6.	Exhibits	59
Signatures		59

1

PART I. FINANCIAL INFORMATION

Item 1.  Condensed Consolidated Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	September 30, 2013		December 31, 2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	59,117	$	52,362
Accounts Receivable:
Trade—Net		98,164		91,170
Other		15,215		7,684
Inventories		72,658		69,336
Deferred Income Taxes		19,696		30,964
Unbilled Revenues		12,304		15,701
Costs and Estimated Earnings in Excess of Billings		4,858		3,663
Regulatory Assets		17,754		25,499
Other		10,167		8,161
Assets of Discontinued Operations		432		19,092
Total Current Assets		310,365		323,632
Investments		9,325		9,471
Other Assets		27,696		26,222
Goodwill		38,971		38,971
Other Intangibles—Net		13,572		14,305
Deferred Debits
Unamortized Debt Expense		4,341		5,529
Regulatory Assets		131,921		134,755
Total Deferred Debits		136,262		140,284
Plant
Electric Plant in Service		1,438,543		1,423,303
Nonelectric Operations		194,636		186,094
Construction Work in Progress		159,202		77,890
Total Gross Plant		1,792,381		1,687,287
Less Accumulated Depreciation and Amortization		670,298		637,835
Net Plant		1,122,083		1,049,452
Total Assets	$	1,658,274	$	1,602,337

See accompanying notes to consolidated financial statements.

2

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt	$	40,335		$	--
Current Maturities of Long-Term Debt		185			176
Accounts Payable		109,604			88,406
Accrued Salaries and Wages		18,122			20,571
Billings In Excess Of Costs and Estimated Earnings		16,202			16,204
Accrued Taxes		10,609			12,047
Derivative Liabilities		12,707			18,234
Other Accrued Liabilities		7,734			6,334
Liabilities of Discontinued Operations		4,080			11,156
Total Current Liabilities		219,578			173,128
Pensions Benefit Liability		109,139			116,541
Other Postretirement Benefits Liability		59,477			58,883
Other Noncurrent Liabilities		25,746			22,244
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		177,248			171,787
Deferred Tax Credits		28,791			31,299
Regulatory Liabilities		70,446			68,835
Other		643			466
Total Deferred Credits		277,128			272,387
Capitalization
Long-Term Debt, Net of Current Maturities		437,306			421,680
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value;  Outstanding 2013 – None; 2012 – 155,000 Shares		--			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, 2013—36,269,363 Shares; 2012—36,168,368 Shares		181,347			180,842
Premium on Common Shares		255,167			253,296
Retained Earnings		97,569			92,221
Accumulated Other Comprehensive Loss		(4,183	)		(4,385	)
Total Common Equity		529,900			521,974
Total Capitalization		967,206			959,154
Total Liabilities and Equity	$	1,658,274		$	1,602,337

See accompanying notes to consolidated financial statements.

3

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except share and per-share amounts)	2013		2012			2013		2012
Operating Revenues
Electric	$	86,275	$	88,550		$	270,089	$	257,458
Nonelectric		143,493		126,766			390,022		389,149
Total Operating Revenues		229,768		215,316			660,111		646,607
Operating Expenses
Production Fuel – Electric		18,785		20,622			52,341		48,501
Purchased Power - Electric System Use		8,691		8,138			36,575		34,624
Electric Operation and Maintenance Expenses		30,626		28,717			98,878		91,137
Asset Impairment Charge - Electric		--		--			--		432
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)		115,475		103,152			311,474		321,874
Other Nonelectric Expenses		12,857		12,424			38,811		39,305
Depreciation and Amortization		15,039		15,057			44,794		44,740
Property Taxes - Electric		3,163		2,833			9,088		8,120
Total Operating Expenses		204,636		190,943			591,961		588,733
Operating Income		25,132		24,373			68,150		57,874
Interest Charges		6,574		7,904			20,431		24,970
Loss on Early Retirement of Debt		--		13,106			--		13,106
Other Income		1,401		653			2,958		2,279
Income from Continuing Operations Before Income Taxes		19,959		4,016			50,677		22,077
Income Tax Expense (Benefit) – Continuing Operations		5,133		(785	)		13,113		200
Net Income from Continuing Operations		14,826		4,801			37,564		21,877
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $39, ($75), ($35) and $3,431 for the respective periods		312		(2,928	)		428		886
Impairment Loss - net of Income Tax (Benefit) of $0, $0, $0 and ($18,114) for the respective periods		--		--			--		(27,459	)
Gain (Loss) on Disposition - net of Income Tax Expense (Benefit) of $0, $0, $6, and ($169) for the respective periods		--		--			210		(3,544	)
Net Income (Loss) from Discontinued Operations		312		(2,928	)		638		(30,117	)
Net Income (Loss)		15,138		1,873			38,202		(8,240	)
Preferred Dividend Requirements and Other Adjustments		--		183			513		551
Earnings (Loss) Available for Common Shares	$	15,138	$	1,690		$	37,689	$	(8,791	)
Average Number of Common Shares Outstanding—Basic		36,179,507		36,061,002			36,141,664		36,043,276
Average Number of Common Shares Outstanding—Diluted		36,381,900		36,252,765			36,344,063		36,235,039
Basic Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$	0.41	$	0.13		$	1.02	$	0.59
Discontinued Operations		0.01		(0.08	)		0.02		(0.83	)
	$	0.42	$	0.05		$	1.04	$	(0.24	)
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$	0.41	$	0.13		$	1.02	$	0.59
Discontinued Operations		0.01		(0.08	)		0.02		(0.83	)
	$	0.42	$	0.05		$	1.04	$	(0.24	)
Dividends Declared Per Common Share	$	0.2975	$	0.2975		$	0.8925	$	0.8925

See accompanying notes to consolidated financial statements.

4

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Net Income (Loss)	$	15,138		$	1,873		$	38,202		$	(8,240	)
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period		--			--			(25	)		--
Gains (Losses) Arising During Period		19			72			(66	)		180
Income Tax (Expense) Benefit		(7	)		(29	)		32			(72	)
Change in Unrealized Gains on Available-for-Sale Securities  – net-of-tax		12			43			(59	)		108
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 12)		145			101			436			305
Income Tax Expense		(58	)		(41	)		(175	)		(122	)
Pension and Postretirement Benefit Plans – net-of-tax		87			60			261			183
Total Other Comprehensive Income		99			103			202			291
Total Comprehensive Income (Loss)	$	15,237		$	1,976		$	38,404		$	(7,949	)

See accompanying notes to consolidated financial statements.

5

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Nine Months Ended September 30,
(in thousands)	2013			2012
Cash Flows from Operating Activities
Net Income (Loss)	$	38,202		$	(8,240	)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net (Gain) Loss from Sale of Discontinued Operations		(210	)		3,544
Net (Income) Loss from Discontinued Operations		(428	)		26,573
Depreciation and Amortization		44,794			44,740
Asset Impairment Charge		--			432
Premium Paid for Early Retirement of Long-Term Debt		--			12,500
Deferred Tax Credits		(1,422	)		(1,568	)
Deferred Income Taxes		15,215			8,320
Change in Deferred Debits and Other Assets		9,817			16,493
Discretionary Contribution to Pension Plan		(10,000	)		(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		7,318			8,029
Allowance for Equity-Other Funds Used During Construction		(1,462	)		(518	)
Change in Derivatives Net of Regulatory Deferral		120			752
Stock Compensation Expense—Equity Awards		1,116			930
Other—Net		813			4,257
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(9,775	)		(16,536	)
Change in Inventories		(3,323	)		864
Change in Other Current Assets		(252	)		6,268
Change in Payables and Other Current Liabilities		4,170			15,021
Change in Interest and Income Taxes Receivable/Payable		1,156			(11,203	)
Net Cash Provided by Continuing Operations		95,849			100,658
Net Cash (Used in) Provided by Discontinued Operations		(2,499	)		48,724
Net Cash Provided by Operating Activities		93,350			149,382
Cash Flows from Investing Activities
Capital Expenditures		(109,690	)		(93,653	)
Net Proceeds from Disposal of Noncurrent Assets		2,615			2,380
Net Increase in Other Investments		(680	)		(1,393	)
Net Cash Used in Investing Activities - Continuing Operations		(107,755	)		(92,666	)
Net Proceeds from Sale of Discontinued Operations		12,842			24,278
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations		505			(11,494	)
Net Cash Used in Investing Activities		(94,408	)		(79,882	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		--			3,535
Net Short-Term Borrowings		40,335			12,417
Proceeds from Issuance of Common Stock		1,496			--
Common Stock Issuance Expenses		--			(181	)
Payments for Retirement of Capital Stock		(15,723	)		(110	)
Proceeds from Issuance of Long-Term Debt		40,900			--
Short-Term and Long-Term Debt Issuance Expenses		(126	)		(14	)
Payments for Retirement of Long-Term Debt		(25,266	)		(50,183	)
Premium Paid for Early Retirement of Long-Term Debt		--			(12,500	)
Dividends Paid and Other Distributions		(33,027	)		(33,033	)
Net Cash Provided by (Used in) Financing Activities - Continuing Operations		8,589			(80,069	)
Net Cash Used in Financing Activities - Discontinued Operations		--			(3,410	)
Net Cash Provided by (Used in) Financing Activities		8,589			(83,479	)
Net Change in Cash and Cash Equivalents - Discontinued Operations		(776	)		(2,015	)
Net Change in Cash and Cash Equivalents		6,755			(15,994	)
Cash and Cash Equivalents at Beginning of Period		52,362			15,994
Cash and Cash Equivalents at End of Period	$	59,117		$	--

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 (including normal recurring accruals) necessary for a fair presentation of the condensed consolidated financial statements for the periods presented. The condensed consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012. Because of seasonal and other factors, the earnings for the three and nine month periods ended September 30, 2013 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, 2012.

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 (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging (ASC 815). 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.

The companies in the Construction segment 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 costs incurred to total estimated costs on construction projects. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Percentage-of-Completion Revenues	20.6	%	17.1	%	16.4	%	16.8	%

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

	September 30,			December 31,
(in thousands)	2013			2012
Costs Incurred on Uncompleted Contracts	$	341,649		$	307,085
Less Billings to Date		(358,026	)		(321,388	)
Plus Estimated Earnings Recognized		5,033			1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

7

The following amounts are included in the Company’s consolidated balance sheets:

	September 30,			December 31,
(in thousands)	2013			2012
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	4,858		$	3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(16,202	)		(16,204	)
NetBillings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

The Company has a standard quarterly estimate at completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.

In 2012, Foley Company (Foley) experienced cost overruns in excess of estimated costs on several large projects. All of these projects were substantially completed as of December 31, 2012. Estimated costs on certain projects in excess of previous period estimates resulted in pretax charges of $0.1 million in the three months ended September 30, 2013 and $1.7 million in the three months ended September 30, 2012, and $0.6 million in the nine months ended September 30, 2013 and $10.4 million in the nine months ended September 30, 2012.

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 products sold by the Company 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. The warranty reserve balance as of December 31, 2012 and September 30, 2013 relates entirely to products that were produced by the Company’s manufacturers of wind towers and waterfront equipment prior to the Company selling the assets of these companies and is included in liabilities of discontinued operations. See note 17 to consolidated financial statements.

Retainage

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

	September 30,		December 31,
(in thousands)	2013		2012
Accounts Receivable Retained by Customers	$	6,989	$	12,227

8

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), 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 (NYMEX).

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 the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	316
Forward Gasoline Purchase Contracts				66
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,608
U.S. Government Debt Securities – Held by Captive Insurance Company				1,278
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		722
Equity Securities - Nonqualified Retirement Savings Plan		130
Total Assets	$	962	$	8,952	$	316
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	12,707
Total Liabilities	$	--	$	--	$	12,707

December 31, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	292	$	210
Forward Gasoline Purchase Contracts				136
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				7,620
U.S. Government Debt Securities – Held by Captive Insurance Company				1,305
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		357
Equity Securities - Nonqualified Retirement Savings Plan		125
Total Assets	$	2,092	$	9,353	$	210
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	242	$	17,992
Total Liabilities	$	--	$	242	$	17,992

9

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of September 30, 2013 and December 31, 2012, are based on prices indexed to observable prices at an active trading hub. The Level 3 forward electric price inputs ranged from $6.95 per megawatt-hour underthe active trading hub price to $2.45 per megawatt-hour over the active trading hub price. The weighted average price was $36.55 per megawatt-hour.

In the table above, the fair values for the Level 3 forward energy contracts as of September 30, 2013 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three or nine month periods ended September 30, 2013 and 2012.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the nine-month periods ended September 30, 2013 and 2012:

	Nine Months Ended
	September 30,
(in thousands)	2013			2012
Forward Energy Contracts  - Fair Values Beginning of Period	$	(17,782	)	$	--
Transfers into Level 3 from Level 2		--			(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		5,066			3,771
Changes in Fair Value of Contracts Entered into in Prior Periods		325			(4,517	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(12,391	)		(16,630	)
Net Increase in Value of Open Contracts Entered into in Current Period		--			22
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(12,391	)	$	(16,608	)

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2013		2012
Finished Goods	$	19,682	$	21,893
Work in Process		10,636		8,800
Raw Material, Fuel and Supplies		42,340		38,643
Total Inventories	$	72,658	$	69,336

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Goodwill

The following table summarizes changes to goodwill by business segment during 2013:

(in thousands)	Gross Balance December 31, 2012		Accumulated Impairments		Balance (net of impairments) December 31, 2012		Adjustments to Goodwill in 2013		Balance (net of impairments) September 30, 2013
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Construction		7,483		--		7,483		--		7,483
Plastics		19,302		--		19,302		--		19,302
Total	$	38,971	$	--	$	38,971	$	--	$	38,971

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,722	$	12,089		15 – 25 years
Other Intangible Assets Including Contracts		825		442		383		5 – 30 years
Total	$	17,636	$	5,164	$	12,472
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2012(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,085	$	12,726		15 – 25 years
Other Intangible Assets Including Contracts		1,092		613		479		5 – 30 years
Total	$	17,903	$	4,698	$	13,205
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Amortization Expense – Intangible Assets	$	245	$	244	$	733	$	737

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

(in thousands)	2013		2014		2015		2016		2017
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	977	$	945	$	849

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2013		2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	25,133	$	5,979
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	5,172	$	--
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. 2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

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Coyote Station Lignite Supply Agreement – Variable Interest Entity

In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, have the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE. Therefore, CCMC is not required to be consolidated in the Company’s consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through September 30, 2013 is $9.8 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC could be as high as $9.8 million as of September 30, 2013.

Reclassifications and Changes to Presentation

The Company’s consolidated income statement and consolidated statement of cash flows for the three and nine month periods ended September 30, 2012 reflect the reclassifications of the operating results and cash flows of discontinued operations as a result of the completion of the sale of the assets of the Company’s wind tower manufacturer and discontinuance of wind tower production activities in November 2012 and the sale of the assets of the Company’s waterfront equipment manufacturer on February 8, 2013. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or nine months ended September 30, 2012.

New Accounting Standards

Accounting Standards Update (ASU) 2011-11 and 2013-01

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2011-13), to clarify which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The amendments in ASU 2013-01 apply to derivatives accounted for in accordance with ASC 815 and clarify that only derivatives accounted for in accordance with ASC 815 are within the scope of the disclosure requirements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.

The Company implemented the disclosure guidance January 1, 2013. While, certain of the Company’s offsetting derivative asset and liability positions related to forward energy contracts with the same counterparty are subject to legally enforceable netting arrangements, the Company does not present its derivative assets and liabilities subject to legally enforceable netting arrangements, or any related payables or receivables, on a net basis on the face of its consolidated balance sheet. The Company has added disclosures and a table in note 5 to the consolidated financial statements indicating the amounts of its derivative forward energy contracts presented at fair value in accordance with ASC 815 that are subject to legally enforceable netting arrangements.

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ASU 2013-02

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, which requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under accounting principles generally accepted in the United States of America (U.S. GAAP) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail on these amounts. This ASU is effective for reporting periods beginning after December 15, 2012. Additional information required by this update is included on the face of the Company’s consolidated statement of comprehensive income for the period ending September 30, 2013. The amounts of accumulated other comprehensive losses associated with the Company’s pension and other post-retirement benefit programs that are being amortized and recognized as operating expenses and the income statement line item affected by the expense are disclosed in note 12 to the consolidated financial statements.

2. Segment Information

The Company’s businesses have been classified into four 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 four segments are: Electric, Manufacturing, Construction and Plastics.

The chart below indicates the companies included in each segment.

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 Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Additionally, the electric segment included Otter Tail Energy Services Company (OTESCO), which provided technical and engineering services. OTESCO ceased operations in July 2013. OTESCO has not recorded any operating revenues, expenses or net income in 2013.

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping and fabrication, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Illinois and Minnesota and sell products primarily in the United States.

Construction consists of businesses involved in 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 at plants in North Dakota and Arizona. The PVC pipe is sold primarily 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.

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No single customer accounted for over 10% of the Company’s consolidated revenues in 2012. All of the Company’s long-lived assets are within the United States.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
United States of America		97.7	%		97.7	%		97.7	%		97.7	%
Mexico		1.5	%		1.1	%		1.3	%		1.0	%
Canada		0.7	%		1.1	%		0.9	%		1.2	%
All Other Countries (none greater than 0.08%)		0.1	%		0.1	%		0.1	%		0.1	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three and nine months ended September 30, 2013 and 2012 and total assets by business segment as of September 30, 2013 and December 31, 2012 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	86,283		$	88,564		$	270,155		$	257,530
Manufacturing		49,323			46,618			152,282			159,091
Construction		47,509			37,931			108,928			111,482
Plastics		46,659			42,217			128,820			118,582
Intersegment Eliminations		(6	)		(14	)		(74	)		(78	)
Total	$	229,768		$	215,316		$	660,111		$	646,607

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Electric	$	3,960	$	4,880	$	13,032	$	14,493
Manufacturing		816		891		2,447		2,723
Construction		128		305		345		868
Plastics		249		342		753		1,034
Corporate and Intersegment Eliminations		1,421		1,486		3,854		5,852
Total	$	6,574	$	7,904	$	20,431	$	24,970

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	2,565		$	2,995		$	5,830		$	3,817
Manufacturing		1,124			1,288			4,715			5,286
Construction		1,193			(879	)		490			(4,819	)
Plastics		2,278			2,216			7,508			7,113
Corporate		(2,027	)		(6,405	)		(5,430	)		(11,197	)
Total	$	5,133		$	(785	)	$	13,113		$	200

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Earnings (Loss) Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	8,787		$	10,206		$	24,301		$	26,413
Manufacturing		2,970			1,914			8,333			7,880
Construction		1,784			(1,325	)		716			(7,252	)
Plastics		3,403			3,309			11,215			10,629
Corporate		(2,118	)		(9,486	)		(7,514	)		(16,344	)
Discontinued Operations		312			(2,928	)		638			(30,117	)
Total	$	15,138		$	1,690		$	37,689		$	(8,791	)

Identifiable Assets

	September 30,		December 31,
(in thousands)	2013		2012
Electric	$	1,280,682	$	1,226,145
Manufacturing		122,942		114,933
Construction		59,904		50,696
Plastics		83,254		78,855
Corporate		111,060		112,616
Discontinued Operations		432		19,092
Total	$	1,658,274	$	1,602,337

3. Rate and Regulatory Matters

Minnesota

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: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, a new standard established by the 2013 legislature requires 1.5% of total electric sales to be supplied by solar energy by the year 2020. OTP is currently evaluating the new legislation and potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the Minnesota Public Utilities Commission (MPUC) may modify or delay implementation of the standards. 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 recovery of Minnesota Renewable Resource Adjustment (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. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by a revised filing on July 25, 2012. Because the request to extend the period of the new rate for 18 months was still under review, a supplemental filing was submitted on February 15, 2013, requesting that the current rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the February 15, 2013 request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. As of May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs. OTP has a regulatory asset of $0.1 million for renewable resource costs and returns eligible for recovery from Minnesota customers that had not been billed to Minnesota customers as of September 30, 2013 that will remain until OTP’s next general rate case.

15

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 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 exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The 2013 legislature passed legislation that also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case, unless a different return is determined to be in the public interest. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s initial request for approval of a TCR rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010.

In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs then 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. On March 26, 2012 the MPUC approved OTP’s request for an update to the TCR rider, effective April 1, 2012.

In the April 2012 TCR rider update, the MPUC 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. On March 26, 2012 the MPUC approved an all-in method for MISO regional cost allocations 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 for projects included in the TCR.

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. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery. A determination of eligibility for inclusion of the remaining nine projects is still pending. OTP filed its annual update to the TCR on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. The Minnesota Department of Commerce (MNDOC) filed comments on May 24, 2013 recommending removal of capitalized internal labor costs and costs in excess of planning estimates used in prior CON proceedings. OTP filed reply comments on June 27, 2013 disagreeing with the MNDOC’s recommendations. Both parties have filed additional comments supportive of their positions. OTP had a regulatory liability of $0.1 million as of September 30, 2013 for amounts billed to Minnesota customers that are subject to refund through the Minnesota TCR rider.

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, transitioned from a conservation spending goal to a conservation energy savings goal.

The 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 Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

16

On January 11, 2012 the MPUC approved the recovery of $3.5 million for 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 recognized an additional $0.4 million of incentive related to 2011 and submitted its annual 2011 financial incentive filing request for $2.6 million. In December 2012, the MPUC approved the recovery of $2.6 million in financial incentives for 2011 and also ordered a change in the MNCIP cost recovery methodology used by OTP from a percentage of a customer’s bill to an amount per kilowatt-hour (kwh) consumed. On January 1, 2013 OTP’s MNCIP surcharge decreased from 3.8% of the customer’s bill to $0.00142 per kwh, which equates to approximately 1.9% of a customer’s bill. OTP recognized $2.6 million of MNCIP financial incentives in 2012 and an additional $0.1 million in 2013 relating to 2012 program results. On October 10, 2013 the MPUC approved OTP’s 2012 financial incentive request for $2.7 million as well as its request for an updated surcharge rate to be implemented on November 1, 2013.

OTP has a regulatory asset of $6.1 million for allowable costs and financial incentives that are eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of September 30, 2013. OTP recognized MNCIP-related revenues totaling $1.5 million in each of the three month periods ended September 30, 2013 and September 30, 2012, and $4.8 million in each of the nine month periods ended September 30, 2013 and September 30, 2012.

North Dakota

Renewable Resource Cost Recovery Rider— On May 21, 2008 the North Dakota Public Service Commission (NDPSC) approved OTP’s request for a North Dakota Renewable Resource Cost Recovery Rider Adjustment (NDRRA) to enable OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed. In its 2009 annual request to the NDPSC to increase the amount of the NDRRA, OTP included investment costs and expenses related to its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008. An NDRRA of $0.0051 per kwh was approved by the NDPSC on January 14, 2009 and went into effect beginning with billing statements sent on February 1, 2009. Terms of the approved settlement provide for the recovery of accrued costs and returns on investments in renewable energy facilities under the NDRRA over a period of 48 months beginning in January 2010.

The 2010 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, which was approved by the NDPSC on March 21, 2012. The 2011 NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. OTP submitted its annual update to the NDRRA on December 28, 2012 with a proposed April 1, 2013 effective date. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the rate implemented on April 1, 2013. OTP has a regulatory asset of $1.2 million for amounts eligible for recovery through the NDRRA rider that had not been billed to North Dakota customers as of September 30, 2013.

Transmission Cost Recovery Rider—OTP’s initial North Dakota TCR rider went into effect May 1, 2012. On August 31, 2012 OTP filed its annual update to the North Dakota TCR rider rate to reflect updated cost information associated with projects currently in the rider. In addition, OTP proposed to include costs associated with ten additional projects for recovery within the rider. The NDPSC approved OTP’s annual update on December 12, 2012 to go into effect January 1, 2013. OTP filed its annual update to the North Dakota TCR rider rate on August 30, 2013 with a proposed implementation date of January 1, 2014. OTP had a regulatory liability of $0.1 million as of September 30, 2013 for amounts billed to North Dakota customers that are subject to refund through the North Dakota TCR rider.

South Dakota

Transmission Cost Recovery Rider—OTP submitted a request for an initial South Dakota TCR rider to the South Dakota Public Utilities Commission (SDPUC) on November 5, 2010. The South Dakota TCR was approved by the SDPUC and implemented on December 1, 2011. OTP billed $0.6 million to South Dakota customers under the TCR rider from December 1, 2011 through December 31, 2012. On September 4, 2012, OTP filed its annual update to the South Dakota TCR rider rate. Updated rates were approved on April 23, 2013 and went into effect on May 1, 2013. OTP filed its annual update to the South Dakota TCR rider rate on August 30, 2013 with a proposed implementation date of January 1, 2014.

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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, which has 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 in OTP’s formula rate: (1) 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 Capacity Expansion 2020 (CapX2020) transmission projects in which OTP is an investor, discussed in more detail below.

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 June 7, 2013, in response to a challenge to the MVP cost allocation heard before the United States Court of Appeals, Seventh Circuit, the Court ruled in favor of MISO and MISO transmission owners, issuing an order affirming the FERC’s approval of the MVP cost allocation.On October 7, 2013 certain parties submitted a Writ of Certiorari to the U.S. Supreme Court appealing the Seventh Circuit decision.

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

The Big Stone South – Brookings MVP—This transmission line is planned at 345 kiloVolt (kV) and will extend 70 miles between a proposed substation near Big Stone City, South Dakota and the new Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy are joint owners of this project and Xcel Energy is the development manager. 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, expected to be in service in 2017, will use previously obtained Big Stone II transmission route permits and easements. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. OTP petitioned the SDPUC on December 19, 2012 to certify a portion of the line route that was originally approved as part of the Big Stone II transmission development. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. OTP and Xcel Energy jointly submitted an application to the SDPUC for a route permit for the southern portion of the Big Stone South to Brookings line on June 3, 2013.

The Big Stone South – Ellendale MVP—This transmission line is a proposed 345 kV line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. 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. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for the ten miles of the proposed line to be built in North Dakota. A joint route permit application was filed by OTP and MDU on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor and Compatibility along with an application for a route permit with the NDPSC on October 18, 2013. If the proposed project receives all the necessary approvals, OTP anticipates the line will be placed in service in 2019.

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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 initially 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. In addition, the Big Stone South – Brookings Multi-Value Project is also designated as a CapX2020 project. Recovery of OTP’s CapX2020 transmission investments will be through the MISO Tariff and the Minnesota, North Dakota and South Dakota TCR riders.

The Fargo Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Fargo Project. The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. Construction is underway for the remaining portions of the project, with completion scheduled for May 2015.

The Brookings Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Brookings Project. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. This project is anticipated to be completed in February 2015.

The Bemidji Project—The Bemidji-Grand Rapids transmission line was fully energized and put into service on September 17, 2012.

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 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 the 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 effective on May 29, 2012.

On January 14, 2011 OTP filed a petition asking the MPUC for an Advanced Determination of Prudence (ADP) for anticipated costs associated with 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). On May 24, 2013 legislation was enacted in Minnesota which allows OTP to file for an emission-reduction rider for recovery of the revenue requirements of the AQCS. The legislation authorizes the rider to allow a current return on investment (including CWIP) at the level approved in the utility’s last general rate case, unless a different return is determined by the MPUC to be in the public interest. OTP filed a petition requesting rider recovery on July 31, 2013, with comments received by the Minnesota Chamber of Commerce and the MNDOC on September 26, 2013 and September 30, 2013. OTP filed reply comments agreeing with the MNDOC and Minnesota Chamber of Commerce recommendations and supplying additional detail requested by the MNDOC on October 10, 2013. The MNDOC filed a response to OTP’s reply comments on October 21, 2013 supporting the filing and requesting approval.

On May 9, 2012 the NDPSC approved OTP’s application for an ADP for anticipated AQCS costs attributable to serving OTP’s North Dakota customers. On February 8, 2013, OTP filed a request with the NDPSC for an environmental rider to recover the revenue requirements of the AQCS project beginning January 1, 2013 while under construction, as well as after completion of the project until placed into base rates through the filing of a rate case. The NDPSC suspended the rate without approval on March 1, 2013 pending review of the request. An update of the estimated costs in the request for a rider was filed on May 8, 2013. The NDPSC held a hearing on September 16, 2013 to review OTP’s filing request for an environmental rider.

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On March 30, 2012 OTP requested approval from the SDPUC for an environmental rider to recover costs associated with the AQCS. The proposed rider was designed to recover the revenue requirements plus carrying charges of the 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. On April 17, 2013 OTP filed a request to either suspend or withdraw this filing. The SDPUC approved withdrawing this filing on April 23, 2013. Instead of receiving rider recovery on the portion of AQCS construction costs assignable to OTP’s South Dakota customers while the project is under construction, OTP will accrue an Allowance for Funds Used During Construction (AFUDC) on these costs and request recovery of, and a return on, the accumulated costs, including AFUDC, in a future rate filing in South Dakota.

Big Stone II Project

On June 30, 2005 OTP and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. On September 11, 2009 OTP announced its withdrawal—both as a participating utility and as the project’s lead developer—from Big Stone II. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project.

Minnesota—OTP requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers at that time was $3.2 million.

On December 30, 2010 OTP filed a request for an extension of the Minnesota Route Permit for the Big Stone II transmission facilities. The April 25, 2011 MPUC order in OTP’s general rate case, instructed OTP to transfer the $3.2 million Minnesota share of Big Stone II transmission costs to CWIP and to create a tracker account through which any over or under recoveries could be accumulated for refund or recovery determination in future rate cases as a regulatory liability or asset. If determined eligible for recovery under the FERC-approved MISO regional transmission tariff, the Minnesota portion of Big Stone II transmission costs and accumulated AFUDC will receive rate base treatment and recovery through the FERC-approved MISO regional transmission rates. Any amounts over or under collected through MISO rates or from other sources are included in the tracker account. The Minnesota Route Permit for these transmission facilities expired and subsequently OTP determined it was appropriate to treat the transmission projects as cancelled projects includable in the tracker account in the second quarter of 2013.

Approximately $0.4 million of the total Minnesota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP in the first quarter of 2013. The remaining transmission costs could not be used by other active transmission projects. Therefore, these costs, along with accumulated AFUDC, were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota long-term regulatory asset account in May 2013, based on recovery granted in the April 25, 2011 order. Because OTP will not earn a return on these deferred costs over their anticipated recovery period, the recoverable amount of approximately $3.5 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate. In May 2013, OTP recorded a charge of $0.7 million related to the discount in accordance with ASC Topic 980 - Regulated Operations (ASC 980), accounting requirements. The amount of the discount is expected to be recovered, along with the remaining balance of the Big Stone II Unrecovered Project Costs – Minnesota regulatory asset, over an anticipated 89-month recovery period beginning in May 2013 and ending in September 2020.

North Dakota—In an order issued June 25, 2010, the NDPSC authorized recovery of Big Stone II development costs from North Dakota ratepayers, pursuant to a final settlement agreement filed June 23, 2010, between the NDPSC advocacy staff, OTP and the North Dakota Large Industrial Energy Group Interveners. The terms of the settlement agreement indicate that OTP’s discontinuation of participation in the project was prudent and OTP should be authorized to recover the portion of costs it incurred related to the Big Stone II generation project. The North Dakota jurisdictional share of Big Stone II generation costs incurred by OTP and subject to recovery from North Dakota ratepayers was determined to be $4.1 million. The North Dakota portion of Big Stone II generation costs is being recovered over a 36-month period which began on August 1, 2010.

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The North Dakota jurisdictional share of Big Stone II costs incurred by OTP related to transmission was $1.1 million. OTP transferred the North Dakota share of Big Stone II transmission costs to CWIP, with such costs subject to AFUDC continuing from September 2009. According to the settlement agreement approved for recovery of the Big Stone II generation costs, if construction of all or a portion of the transmission facilities commences within three years of the NDPSC order approving the settlement agreement, the North Dakota portion of Big Stone II transmission costs and accumulated AFUDC shall be included in the rate base investment for these future transmission facilities. If construction is not commenced on any of the transmission facilities within three years of the NDPSC order approving the settlement agreement, OTP may petition the NDPSC to either continue accounting for these costs as CWIP or to commence recovery of such costs. Approximately $0.3 million of the total North Dakota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP during the first quarter of 2013. The remaining transmission costs have been determined not to be useable by other active transmission projects.

On March 29, 2013, OTP filed a request with the NDPSC for a six month extension of the Big Stone II Cost Recovery Rider. This extension would allow for the recovery of the remaining transmission related costs which have been determined to not be useable with other transmission projects. In the second quarter of 2013, OTP transferred the remaining North Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $1.0 million from CWIP to the Big Stone II Unrecovered Project Costs – North Dakota current regulatory asset account. OTP filed a supplement to the NDPSC request on May 7, 2013 adding AFUDC costs, thus increasing the amount to be collected and the duration of the regulatory asset to be extended eight months. The May 7, 2013 supplemental request was approved by the NDPSC on July 30, 2013, which allows OTP to keep the existing Big Stone II rates in place to recover the remaining transmission costs plus accumulated AFUDC over an eight month period ending March 31, 2014.

South Dakota—OTP requested recovery of the South Dakota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in South Dakota on August 20, 2010. In the first quarter of 2011, the SDPUC approved recovery of the South Dakota portion of Big Stone II generation development costs totaling approximately $1.0 million from South Dakota ratepayers over a ten-year period beginning in February 2011 with the implementation of interim rates. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates. A portion of the Big Stone II transmission costs were transferred out of CWIP in February 2013 to be included within the Big Stone South - Brookings MVP. On March 28, 2013, OTP filed a petition with the SDPUC requesting deferred accounting for the remaining unrecovered Big Stone II Transmission costs until OTP’s next South Dakota general rate case. The petition was approved by the SDPUC on April 23, 2013 and in May 2013 OTP transferred the remaining South Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $0.2 million from CWIP to the Big Stone II Unrecovered Project Costs – South Dakota long-term regulatory asset account.

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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. 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. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	September 30, 2013						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,410	$	103,232	$	111,642	see note
Deferred Marked-to-Market Losses1		4,363		8,344		12,707	63 months
Conservation Improvement Program Costs and Incentives2		1,821		4,332		6,153	21 months
Big Stone II Unrecovered Project Costs – Minnesota1		550		4,075		4,625	84 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,515		4,515	asset lives
Debt Reacquisition Premiums1		351		2,329		2,680	228 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,014		1,473		2,487	27 months
Deferred Income Taxes1		--		1,820		1,820	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		313		864		1,177	18 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		869		969	116 months
Big Stone II Unrecovered Project Costs – North Dakota1		763		--		763	6 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		41		--		41	9 months
General Rate Case Recoverable Expenses – South Dakota1		24		--		24	4 months
South Dakota Transmission Rider Accrued Revenues2		4		--		4	12 months
Total Regulatory Assets	$	17,754	$	131,921	$	149,675
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	67,610	$	67,610	asset lives
Deferred Income Taxes		--		2,248		2,248	asset lives
Refundable Fuel Clause Adjustment Revenues		555		--		555	12 months
Deferred Marked-to-Market Gains		--		316		316	59 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		165		165	see note
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		107		113	243 months
North Dakota Transmission Rider Accrued Refund		75		--		75	12 months
Minnesota Transmission Rider Accrued Refund		54		--		54	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		44		--		44	3 months
Total Regulatory Liabilities	$	734	$	70,446	$	71,180
Net Regulatory Asset Position	$	17,020	$	61,475	$	78,495
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

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	December 31, 2012						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,411	$	109,538	$	117,949	see note
Deferred Marked-to-Market Losses1		7,949		10,050		17,999	72 months
Conservation Improvement Program Costs and Incentives2		3,707		2,560		6,267	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,137		4,137	asset lives
Debt Reacquisition Premiums1		268		1,978		2,246	237 months
Big Stone II Unrecovered Project Costs – Minnesota1		526		1,618		2,144	45 months
Recoverable Fuel and Purchased Power Costs1		1,737		--		1,737	12 months
Deferred Income Taxes1		--		1,691		1,691	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		532		1,087		1,619	15 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		--		1,352		1,352	see note
Minnesota Renewable Resource Rider Accrued Revenues2		915		--		915	5 months
Big Stone II Unrecovered Project Costs – North Dakota1		908		--		908	7 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		711		811	97 months
General Rate Case Recoverable Expenses1		279		6		285	13 months
North Dakota Transmission Rider Accrued Revenues2		110		--		110	12 months
Deferred Holding Company Formation Costs1		55		27		82	18 months
South Dakota Transmission Rider Accrued Revenue2		2		--		2	12 months
Total Regulatory Assets	$	25,499	$	134,755	$	160,254
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,960	$	65,960	asset lives
Deferred Income Taxes		--		2,553		2,553	asset lives
Minnesota Transmission Rider Accrued Refund		489		--		489	12 months
Deferred Marked-to-Market Gains		8		210		218	68 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		112		118	252 months
South Dakota – Nonasset-Based Margin Sharing Excess		56		--		56	12 months
Total Regulatory Liabilities	$	559	$	68,835	$	69,394
Net Regulatory Asset Position	$	24,940	$	65,920	$	90,860
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset related to 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 Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

All Deferred Marked-to-Market Gains and Losses recorded as of September 30, 2013 are related to forward purchases of energy scheduled for delivery through December 2018.

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

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

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

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 228 months.

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MISO Schedule 26/26A Transmission Cost Recovery Rider True-up relates to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-up also includes the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule. The September 30, 2013 balance will be amortized on a straight-line basis over two consecutive 12-month periods beginning in January 2014.

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

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2013.

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

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

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of September 30, 2013. A supplemental filing was submitted to the MPUC on February 15, 2013, requesting that the then current MNRRA rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

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

The South Dakota Transmission Rider Accrued Revenues relate to revenues billed for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers net of transmission revenues that have not been billed to South Dakota customers as of September 30, 2013.

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

Revenue for Rate Case Expenses Subject to Refund - Minnesota relate to revenues collected under general rates to recover   costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.

The North Dakota Transmission Rider Accrued Refund relates to revenues earned on qualifying transmission system facilities and operating costs incurred to serve North Dakota customers net of transmission revenues that are refundable to North Dakota customers as of September 30, 2013.

The Minnesota Transmission Rider Accrued Refund relates to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers net of transmission revenues that are refundable to Minnesota customers as of September 30, 2013.

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.

As of September 30, 2013 OTP had no unrealized mark-to-market gains or losses in its income statement related to forward contracts for the purchase and sale of electricity. 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 3 of the fair value hierarchy set forth in ASC 820.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of September 30, 2013 and December 31, 2012, and the change in the Company’s consolidated balance sheet position from December 31, 2012 to September 30, 2013 and December 31, 2011 to September 30, 2012:

(in thousands)	September 30, 2013			December 31, 2012
Current Asset – Marked-to-Market Gain	$	316		$	502
Regulatory Asset – Current Deferred Marked-to-Market Loss		4,363			7,949
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		8,344			10,050
Total Assets		13,023			18,501
Current Liability – Marked-to-Market Loss		(12,707	)		(18,234	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(8	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(316	)		(210	)
Total Liabilities		(13,023	)		(18,452	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	49

(in thousands)	Year-to-Date September 30, 2013			Year-to-Date September 30, 2012
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	49		$	894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(49	)		(781	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--			(33	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			80
Changes in Fair Value of Contracts Entered into in Current Period		--			(121	)
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	(41	)

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013		2012			2013		2012
Net Gains (Losses) on Forward Electric Energy Contracts	$	1	$	(274	)	$	255	$	(130	)

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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 September 30, 2013 and December 31, 2012:

	September 30, 2013				December 31, 2012
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	335		2	$	580		6
Net Credit Risk to Single Largest Counterparty	$	321			$	285

OTP had a net credit risk exposure to two counterparties with investment grade credit ratings. OTP had no exposure at September 30, 2013 or December 31, 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 credit risk exposures include net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains on forward contracts for the purchase of gasoline scheduled for settlement subsequent to September 30, 2013. Individual counterparty exposures are offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amount of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of September 30, 2013 and December 31, 2012 are indicated in the following table:

(in thousands)	September 30, 2013			December 31, 2012
Derivative assets subject to legally enforceable netting arrangements	$	382		$	638
Derivative liabilities subject to legally enforceable netting arrangements		(12,707	)		(18,234	)
Net balance subject to legally enforceable netting arrangements	$	(12,325	)	$	(17,596	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2013 and December 31, 2012:

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2013			December 31, 2012
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	2,176
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		12,707			16,058
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	12,707		$	18,234
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	$	12,707		$	16,058
Offsetting Gains with Counterparties under Master Netting Agreements		(316	)		(416	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	12,391		$	15,642

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6. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share

Reconciliation of Common Shareholders’ Equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2012	$	180,842		$	253,296		$	92,221		$	(4,385	)	$	521,974
Common Stock Issuances, Net of Expenses		551			1,848									2,399
Common Stock Retirements and Forfeitures		(46	)		(177	)								(223	)
Net Income								38,202						38,202
Other Comprehensive Income											202			202
Tax Benefit – Stock Compensation					59									59
Employee Stock Incentive Plan Expense					313									313
Premium on Purchase of Stock for Employee Purchase Plan					(258	)								(258	)
Cumulative Preferred Dividends								(427	)					(427	)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares					86			(86	)					--
Common Dividends								(32,341	)					(32,341	)
Balance, September 30, 2013	$	181,347		$	255,167		$	97,569		$	(4,183	)	$	529,900

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2012 through September 30, 2013:

Common Shares Outstanding, December 31, 2012	36,168,368
Issuances:
Stock Options Exercised	55,109
Vesting of Restricted Stock Units	17,535
Restricted Stock Issued to Employees	17,000
Restricted Stock Issued to Directors	16,000
Director’s Compensation	4,535
Retirements:
Shares Withheld for Individual Income Tax Requirements	(7,184	)
Forfeiture of Unvested Restricted Stock	(2,000	)
Common Shares Outstanding, September 30, 2013	36,269,363

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is earnings available for common shares with no adjustments for the three and nine month periods ended September 30, 2013 and 2012. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting outstanding shares for the following: (1) all potentially dilutive stock options, (2) underlying shares related to nonvested restricted stock units granted to employees, (3) nonvested restricted shares, (4) shares expected to be awarded for stock performance awards granted to executive officers, and (5) shares expected to be issued under the deferred compensation program for directors. The adjustments to the denominators used to calculate basic and diluted earnings per share resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in each of the three and nine month periods ended September 30, 2013 and 2012.

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the three and nine month periods ended September 30, 2013 and 2012:

	Options Outstanding	Range of Exercise Prices
Three Months Ended September 30, 2013	--	--
Three Months Ended September 30, 2012	92,497	$24.93 – $27.245
Nine Months Ended September 30, 2013	--	--
Nine Months Ended September 30, 2012	92,497	$24.93 – $27.245

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7. Share-Based Payments

The Company has five share-based payment programs.

Stock Incentive Awards

On April 8, 2013 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 (the Stock Incentive Plan):

Award	Shares/Units Granted	Grant-Date Fair Value per Award	Vesting
Restricted Stock Granted to Nonemployee Directors	16,000	$31.03	25% per year through April 8, 2017
Restricted Stock Granted to Executive Officers	17,000	$31.03	25% per year through April 8, 2017
Stock Performance Awards Granted to Executive Officers	50,200	$37.51	December 31, 2015
Restricted Stock Units Granted to Employees	15,150	$25.30	100% on April 8, 2017

The restricted shares granted to the Company’s nonemployee directors and executive officers are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement. 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 100,400 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, 2013 through December 31, 2015. The aggregate target share award is 50,200 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 average projected payout percentage rendered by the simulation was 118.7% of target, which would result in a payout of 57,587 shares with a current fair value of $1,883,000 or $32.70 per share, which equates to $37.51 per targeted share award. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC Topic 718,Compensation—Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

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

As of September 30, 2013 the remaining unrecognized compensation expense related to stock-based compensation was approximately $5.5 million (before income taxes) which will be amortized over a weighted-average period of 2.1 years.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Employee Stock Purchase Plan (15% discount)	$	39	$	31	$	98	$	119
Restricted Stock Granted to Directors		119		139		488		413
Restricted Stock Granted to Employees		111		87		315		232
Restricted Stock Units Granted to Employees		61		60		215		165
Stock Performance Awards Granted to Executive Officers		347		146		2,148		439
Totals	$	677	$	463	$	3,264	$	1,368

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8. Retained Earnings Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP’s credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2013 the Company was in compliance with the debt covenants. See note 10 to the Company’s financial statements on Form 10-K for the year ended December 31, 2012 for further information on the covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account.  What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 44.8% and 54.8%. OTP’s equity to total capitalization ratio including short-term debt was 49.5% as of September 30, 2013. Total capitalization for OTP cannot currently exceed $874 million.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2012 OTP had commitments under contracts in connection with construction programs aggregating approximately $79.4 million. At September 30, 2013 OTP had commitments under contracts in connection with construction programs aggregating approximately $127.5 million. The increase in construction commitments from December 31, 2012 to September 30, 2013 is mainly for OTP’s share of commitments related to the construction of a new air quality control system at Big Stone Plant.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

As of December 31, 2012 OTP had commitments for the purchase of capacity and energy requirements under agreements extending through 2032 totaling $170.1 million. In the second quarter of 2013, OTP entered into a 25-year power purchase agreement (PPA) with Ashtabula Wind III, LLC for the purchase of wind generated electricity from the LLC’s 39 wind turbines located in Barnes County, North Dakota. At its regular agenda meeting on August 22, 2013 the MPUC provided an affirmative determination that OTP’s execution of this agreement is reasonable, in the public interest, and that costs incurred under this agreement to serve OTP’s Minnesota customers will be recoverable. On October 1, 2013 OTP began accepting delivery of energy under the PPA. In September of 2013, OTP entered into an agreement with Great River Energy for the purchase of 25 megawatts (MW) of capacity from June 1, 2017 through May 31, 2019 and 50 MW of capacity from June 1, 2019 through May 31, 2021 to meet OTP’s future capacity requirements. OTP’s commitments under the Ashtabula Wind III, LLC PPA and the Great River Energy capacity purchase agreement have increased OTP’s total estimated commitments under capacity and energy purchase agreements by $193.4 million.

As of December 31, 2012 OTP had contracts providing for the purchase and delivery of a significant portion of its then current coal requirements totaling $797.0 million. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2014, 2016 and 2040. In February, May and September of 2013, OTP entered into agreements for the purchase of additional coal to meet a portion of Big Stone Plant’s remaining coal requirements for 2013 and 2014. In September of 2013, OTP entered into an agreement for the purchase of additional coal to meet a portion of Hoot Lake Plant’s coal requirements for the remainder of 2013 and 2015. OTP’s share of the additional commitments subsequent to September 30, 2013 total $3.9 million for 2013, $3.2 million for 2014 and $4.2 million for 2015.

Contingencies

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, environmental remediation, litigation matters and the resolution of matters related to open tax years. Should all of these known items result in liabilities being incurred, the loss could be as high as $2.0 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, such as possible warranty claims on products that are beyond their warranty period but where a customer may claim to have provided notice of a defect while the product was under warranty. If these claims were to occur, it could result in the Company incurring a significantly greater liability than it anticipates.

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Other

The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2013 will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2013 and December 31, 2012:

(in thousands)	Line Limit		In Use on September 30, 2013		Restricted due to Outstanding Letters of Credit		Available on September 30, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	680	$	149,320	$	149,267
OTP Credit Agreement		170,000		40,335		1,189		128,476		166,811
Total	$	320,000	$	40,335	$	1,869	$	277,796	$	316,078

On October 29, 2013 both the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were amended to extend the expiration dates by one year from October 29, 2017 to October 29, 2018.

Long-Term Debt Issuances, Retirements and Preferred Stock Redemption

On March 1, 2013 OTP entered into a Credit Agreement (the Loan Agreement) with JPMorgan Chase Bank, N.A. (JPMorgan) providing for a $40.9 million unsecured term loan (the Term Loan) to OTP originally due on June 1, 2014, which was fully drawn on March 1, 2013. The Loan Agreement was amended on October 29, 2013 to extend the due date on the Term Loan to January 15, 2015. Borrowings under the Loan Agreement bear interest at LIBOR plus 0.875%. On March 1, 2013, OTP utilized approximately $25.1 million of Term Loan proceeds to fund the redemption price for all of the 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds outstanding on that date, in each case for which OTP pays debt service. All such bonds had been called for redemption in full on March 1, 2013. Also on March 1, 2013, OTP utilized approximately $15.7 million of Term Loan proceeds to satisfy an intercompany note to the Company that had a balance and interest rate designed to equate to the balances and dividend rates of the Company’s cumulative preferred shares. Those cumulative preferred shares were redeemed on March 1, 2013 for $15.7 million, including $0.2 million in call premiums charged to equity and included with preferred dividends paid and as part of our preferred dividend requirement for the nine-month period ending September 30, 2013.

The Loan Agreement contains a number of restrictions on the business of OTP similar to the OTP Credit Agreement, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Loan Agreement also contains affirmative covenants and events of default, as well as a financial covenant under which OTP may not permit the ratio of its Interest bearing Debt to Total Capitalization (as defined in the Loan Agreement) to be greater than 0.60 to 1.00. The Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the Loan Agreement are not guaranteed by any other party. OTP may prepay borrowings without premium or penalty upon notice to JPMorgan as provided in the Loan Agreement. In the event of certain “Senior Indebtedness Prepayment Events” as defined in the Loan Agreement, OTP must offer to prepay a ratable portion of the Term Loan.

On August 14, 2013, OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the 2029 Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the 2044 Notes and, together with the 2029 Notes, the Notes). The Notes are expected to be issued on February 27, 2014, subject to the satisfaction of certain customary conditions to closing.

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The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (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, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states the Company must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP that will be effective on issuance of the Notes. These include restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants.  Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2013 Note Purchase Agreement) to exceed 60% of Total Capitalization (as defined in the 2013 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the 2013 Note Purchase Agreement) to exceed 20% of Total Capitalization, also determined as of the end of each fiscal quarter. The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings.  The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement.  The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

OTP intends to use a portion of the proceeds of the Notes to retire early the Term Loan, due January 15, 2015. The remaining proceeds of the Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the Notes and for other general corporate purposes, including planned construction program expenditures.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	40,335	$	--	$	--	$	40,335
Long-Term Debt:
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	$	40,900					$	40,900
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
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
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 September 30, 2013		--				1,594		1,594
Total	$	335,900			$	101,594	$	437,494
Less: Current Maturities		--				185		185
Unamortized Debt Discount		--				3		3
Total Long-Term Debt	$	335,900			$	101,406	$	437,306
Total Short-Term and Long-Term Debt (with current maturities)	$	376,235	$	--	$	101,591	$	477,826

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December 31, 2012 (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		5,065						5,065
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		20,070						20,070
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, 2012						1,725		1,725
Total	$	320,135			$	101,725	$	421,860
Less: Current Maturities		--				176		176
Unamortized Debt Discount		--				4		4
Total Long-Term Debt	$	320,135			$	101,545	$	421,680
Total Short-Term and Long-Term Debt (with current maturities)	$	320,135	$	--	$	101,721	$	421,856

12. Pension Plan and Other Postretirement Benefits

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	1,359		$	1,271		$	4,195		$	3,813
Interest Cost on Projected Benefit Obligation		3,021			3,116			9,093			9,349
Expected Return on Assets		(3,627	)		(3,608	)		(10,891	)		(10,823	)
Amortization of Prior-Service Cost:
From Regulatory Asset		84			100			250			299
From Other Comprehensive Income1		3			3			7			8
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,624			1,229			4,950			3,683
From Other Comprehensive Income1		42			31			132			97
Net Periodic Pension Cost	$	2,506		$	2,142		$	7,736		$	6,426
1Corporate cost included in Other Nonelectric Expenses.

Cash flows—The Company made a discretionary plan contribution of $10,000,000 in January 2013. The Company currently is not required and does not expect to make an additional contribution to the plan in 2013. The Company also made a discretionary plan contribution of $10,000,000 in January 2012.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2013		2012		2013		2012
Service Cost—Benefit Earned During the Period	$	12	$	11	$	38	$	34
Interest Cost on Projected Benefit Obligation		352		370		1,056		1,109
Amortization of Prior-Service Cost:
From Regulatory Asset		6		5		16		16
From Other Comprehensive Income1		13		13		39		39
Amortization of Net Actuarial Loss:
From Regulatory Asset		52		39		156		116
From Other Comprehensive Income2		79		43		235		129
Net Periodic Pension Cost	$	514	$	481	$	1,540	$	1,443
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5	$	5	$	15	$	15
Other Nonelectric Expenses		8		8		24		24
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	49	$	36	$	145	$	108
Other Nonelectric Expenses		30		7		90		21

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of the Medicare Part D Subsidy:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	184		$	386		$	1,066		$	1,158
Interest Cost on Projected Benefit Obligation		318			644			1,538			1,931
Amortization of Transition Obligation:
From Regulatory Asset		--			182			--			546
From Other Comprehensive Income1		--			5			--			15
Amortization of Prior-Service Cost:
From Regulatory Asset		52			51			154			154
From Other Comprehensive Income1		2			2			4			4
Amortization of Net Actuarial Loss:
From Regulatory Asset		(478	)		160			18			481
From Other Comprehensive Income1		(12	)		4			--			13
Net Periodic Postretirement Benefit Cost	$	66		$	1,434		$	2,780		$	4,302
Effect of Medicare Part D Subsidy	$	(227	)	$	(509	)	$	(1,355	)	$	(1,529	)
1Corporate cost included in Other Nonelectric Expenses.

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13. Fair Value of Financial Instruments

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

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

Short-Term Debt—The carrying amount approximates fair value because the debt obligation is short-term and the balance outstanding related to the OTP Credit Agreement is subject to a variable interest rate that approximates current market rates (LIBOR plus 1.25%).

Long-Term Debt including Current Maturities—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 Company’s long-term debt subject to variable interest rates approximates fair value. 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.

	September 30, 2013						December 31, 2012
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	59,117		$	59,117		$	52,362		$	52,362
Short-Term Debt		(40,335	)		(40,335	)		--			--
Long-Term Debt including Current Maturities		(437,491	)		(486,719	)		(421,856	)		(491,244	)

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 month and nine month periods ended September 30, 2013 and 2012:

	Three Months Ended  September 30,						Nine Months Ended  September 30,
(in thousands)	2013			2012			2013			2012
Income Before Income Taxes – Continuing Operations	$	19,959		$	4,016		$	50,677		$	22,077
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,784			1,566			19,764			8,610
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,162	)		(1,239	)		(4,592	)		(5,057	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			--			(676	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(297	)		(651	)		(668	)
Corporate Owned Life Insurance		(227	)		(118	)		(621	)		(503	)
Medicare Part D Subsidy		--			(196	)		--			(587	)
Employee Stock Ownership Plan Dividend Deduction		(190	)		(190	)		(568	)		(571	)
Research and Development Tax Credits from 2012		(520	)		--			(520	)		--
Deferred Tax Asset reduction – North Dakota, due to Tax Rate Decrease		--			--			365			--
Other Items - Net		(340	)		(311	)		(64	)		(348	)
Income Tax Expense (Benefit) – Continuing Operations	$	5,133		$	(785	)	$	13,113		$	200
Effective Income Tax Rate – Continuing Operations		25.7	%		(19.5	)%		25.9	%		0.9	%

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

(in thousands)	2013
Balance on January 1	$	4,436
Increases Related to Tax Positions for Prior Years		97
Uncertain Positions Adjusted During Year		(288	)
Balance on September 30	$	4,245

The balance of unrecognized tax benefits as of September 30, 2013 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2013 is not expected to change significantly within the next three 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 September 30, 2013.

17. Discontinued Operations

On February 8, 2013 the Company completed the sale of substantially all the assets of its waterfront equipment manufacturing company, formerly included in the Company’s Manufacturing segment, for approximately $13.0 million in cash and received a working capital true up of approximately $2.4 million in June 2013. On November 30, 2012 the Company completed the sale of the assets of its wind tower manufacturing company and on February 29, 2012 the Company completed the sale of DMS Health Technologies, Inc. Following are summary presentations of the results of discontinued operations for the three and nine-month periods ended September 30, 2013 and 2012:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Operating Revenues	$	--		$	61,827		$	2,016		$	208,186
Operating Expenses		(452	)		64,866			2,094			203,961
Asset Impairment Charge		--			--			--			45,573
Operating Income (Loss)		452			(3,039	)		(78	)		(41,348	)
Interest Charges		--			--			--			174
Other (Deductions) Income		(101	)		36			471			266
Income Tax Expense (Benefit)		39			(75	)		(35	)		(14,683	)
Net Income (Loss) from Operations		312			(2,928	)		428			(26,573	)
Gain (Loss) on Disposition Before Taxes		--			--			216			(3,713	)
Income Tax Expense (Benefit) on Disposition		--			--			6			(169	)
Net Gain (Loss) on Disposition		--			--			210			(3,544	)
Net Income (Loss)	$	312		$	(2,928	)	$	638		$	(30,117	)

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2013 and December 31, 2012:

(in thousands)	September 30,  2013		December 31, 2012
Current Assets	$	432	$	18,487
Investments		--		85
Net Plant		--		520
Assets of Discontinued Operations	$	432	$	19,092
Current Liabilities	$	4,080	$	11,156
Liabilities of Discontinued Operations	$	4,080	$	11,156

35

Included in current liabilities are warranty reserves. Details regarding the warranty reserves follow:

(in thousands)
Warranty Reserve Balance, December 31, 2012	$	5,027
Provision for Warranties Used During the Year		120
Less Settlements Made During the Year		(675	)
Decrease in Warranty Estimates for Prior Years		(1,112	)
Warranty Reserve Balance, September 30, 2013	$	3,360

The warranty reserve balance as of December 31, 2012 and September 30, 2013 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies. For wind towers, 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. For example, 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.

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

RESULTS OF OPERATIONS

Following is an analysis of our operating results by business segment for the three and nine month periods ended September 30, 2013 and 2012, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2013 and our business outlook for the remainder of 2013.

Comparison of the Three Months Ended September 30, 2013 and 2012

Consolidated operating revenues were $229.8 million for the three months ended September 30, 2013 compared with

$215.3 million for the three months ended September 30, 2012. Operating income was $25.1 million for the three months ended September 30, 2013 compared with $24.4 million for the three months ended September 30, 2012. The Company recorded diluted earnings per share from continuing operations of $0.41 for the three months ended September 30, 2013 compared with $0.13 for the three months ended September 30, 2012 and total diluted earnings per share of $0.42 for the three months ended September 30, 2013 compared to $0.05 for the three months ended September 30, 2012.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended September 30, 2013 and 2012 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2013			September 30, 2012
Operating Revenues:
Electric	$	8		$	14
Nonelectric		(2	)		--
Cost of Goods Sold		1			31
Other Nonelectric Expenses		5			(17	)

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Electric

	Three Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Retail Sales Revenues	$	72,758	$	74,622	$	(1,864	)		(2.5	)
Wholesale Revenues – Company Generation		5,182		5,347		(165	)		(3.1	)
Net Revenue – Energy Trading Activity		353		241		112			46.5
Other Revenues		7,990		8,354		(364	)		(4.4	)
Total Operating Revenues	$	86,283	$	88,564	$	(2,281	)		(2.6	)
Production Fuel		18,785		20,622		(1,837	)		(8.9	)
Purchased Power – System Use		8,691		8,138		553			6.8
Other Operation and Maintenance Expenses		30,626		28,717		1,909			6.6
Depreciation and Amortization		10,787		10,504		283			2.7
Property Taxes		3,163		2,833		330			11.6
Operating Income	$	14,231	$	17,750	$	(3,519	)		(19.8	)
Electric kwh Sales (in thousands)
Retail kilowatt-hour (kwh) Sales		982,887		1,002,921		(20,034	)		(2.0	)
Wholesale kwh Sales – Company Generation		158,486		170,589		(12,103	)		(7.1	)
Wholesale kwh Sales – Purchased Power Resold		81,609		15,202		66,407			436.8
Heating Degree Days		186		262		(76	)		(29.0	)
Cooling Degree Days		421		497		(76	)		(15.3	)

The $1.9 million decrease in retail sales revenues reflects the following:

● a $1.1 million decrease in Fuel Clause Adjustment (FCA) revenues and fuel and purchased power costs recovered in base rates as a result of a 7.3% reduction in fuel costs per kwh generated at Otter Tail Power Company’s (OTP) steam-powered and combustion turbine generators in combination with a 2.0% decrease in retail kwh sales,

● a $1.0 million decrease in revenues related to the 2.0% decrease in retail kwh sales due, in part, to milder weather as evidenced by a decrease in both heating and cooling degree days of 29.0% and 15.3%, respectively, between the quarters, and

● a $1.0 million decrease in various environmental, renewable, regulatory and conservation cost recovery related revenues driven by commensurate increases in other revenues or reductions in costs that are components of these alternative revenue recovery mechanisms,

offset by:

● a $1.2 million increase in Transmission Cost Recovery Rider revenues resulting from increased investment in transmission lines.

Wholesale electric revenues from company-owned generation decreased $0.2 million as a result of a 7.1% decrease in wholesale kwh sales, partially offset by a 4.3% increase in wholesale electric prices driven, in part, by an increase in natural gas prices.

Other electric operating revenues decreased $0.4 million mainly as a result of a reduction in revenues from electric construction work completed for other regional utilities.

Fuel costs decreased $1.8 million as a result of a 7.3% decrease in the cost of fuel per kwh generated combined with a 1.7% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators. The decrease in the average cost of fuel per kwh of generation reflects a 10.8% decrease in the cost of fuel per kwh generated at OTP’s Big Stone Plant and a 5.0% decrease in the cost of fuel per kwh generated at OTP’s Hoot Lake Plant as a result of reductions in contracted coal prices.

The cost of purchased power for retail sales increased $0.6 million as a result of an 8.3% increase in kwhs purchased, partially offset by a 1.4% decrease in the cost per kwh purchased. The increase in kwhs purchased made up for a decrease in kwhs generated from company-owned plants to serve retail customers.

37

Electric operating and maintenance expenses increased $1.9 million mainly due to the following:

● a $1.0 million increase in Midcontinent Independent System Operator, Inc. (MISO) transmission tariff charges related to increasing investments in regional CapX2020 and MISO-designated Multi-Value (MVP) transmission projects, and

● a $0.9 million increase in general and administrative expenses, mostly related to a $0.7 million increase in corporate costs allocated to the Electric segment due, in part, to changes in allocation factors resulting from the corporation’s recent divestitures.

The $0.3 million increase in property tax expense is related to higher property value assessments in Minnesota and South Dakota.

Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Revenues	$	49,323	$	46,618	$	2,705			5.8
Cost of Goods Sold		37,197		35,493		1,704			4.8
Operating Expenses		4,463		3,935		528			13.4
Depreciation and Amortization		2,755		3,118		(363	)		(11.6	)
Operating Income	$	4,908	$	4,072	$	836			20.5

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 $2.3 million as a result of higher sales volume due to increased demand from customers in end markets serving the recreational equipment and agricultural industries.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased by $0.4 million as a result of increases in product sales and tooling revenues.

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

● Cost of goods sold at BTD increased $1.8 million, mainly as a result of increases in labor and material costs related to an increase in sales volume.

● Cost of goods sold at T.O. Plastics decreased $0.1 million as a result of reductions in conversion costs due to productivity improvements.

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

● Operating expenses at BTD increased $0.3 million due to a 2012 reduction in incentive compensation.

● Operating expenses at T.O. Plastics increased $0.2 million due to increases in labor and employee recruitment costs.

Depreciation expense decreased as a result of certain assets, mainly equipment, at BTD’s Illinois plant being fully depreciated early in 2013.

38

Construction

	Three Months Ended
	September 30,								%
(in thousands)	2013		2012			Change			Change
Operating Revenues	$	47,509	$	37,931		$	9,578			25.3
Cost of Goods Sold		40,998		36,184			4,814			13.3
Operating Expenses		2,847		3,105			(258	)		(8.3	)
Depreciation and Amortization		560		550			10			1.8
Operating Income (Loss)	$	3,104	$	(1,908	)	$	5,012			262.7

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

● Revenues at Foley Company (Foley), a mechanical and prime contractor on industrial projects, increased $15.6 million as a result of the recognition of more revenue in the third quarter of 2013 on several large projects initiated in 2012.

● Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, decreased $6.0 million as a result of a strategic reduction in the volume of telecommunications jobs pursued in 2013 and a delay in securing and initiating new substation construction. Also, Aevenia’s third quarter 2012 results included revenues of $1.7 million from Moorhead Electric, Inc. (MEI), an Aevenia subsidiary that was sold in October 2012.

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

● Cost of goods sold at Foley increased $10.2 million reflecting a combination of increased costs related to the increase in work volume in the third quarter of 2013 partially offset by a reduction in cost overruns incurred on certain large projects under construction in 2012.

● Cost of goods sold at Aevenia decreased $5.4 million in direct relation to the reduction in sales revenue and as a result of the sale of MEI in October 2012. MEI’s cost of goods sold totaled $0.9 million in the third quarter of 2012.

Aevenia’s operating expenses decreased $0.2 million in the third quarter of 2013 compared to the third quarter of 2012 as a result of decreased labor costs and the sale of MEI in October 2012.

Plastics

	Three Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Revenues	$	46,659	$	42,217	$	4,442			10.5
Cost of Goods Sold		37,281		31,506		5,775			18.3
Operating Expenses		2,585		2,869		(284	)		(9.9	)
Depreciation and Amortization		887		764		123			16.1
Operating Income	$	5,906	$	7,078	$	(1,172	)		(16.6	)

The increase in Plastics segment revenue is the result of a 12.1% increase in pounds of polyvinyl chloride (PVC) pipe sold, partially offset by a 1.4% decrease in the price per pound of pipe sold. Sales volume increased as construction and housing markets continued to improve in the South Central and Southwest regions of the United States and construction activity increased in the North Central United States as favorable weather allowed contractors to make up for a slow start due to a colder and wetter spring in 2013. The increase in costs of goods sold was due to the increase in pounds of pipe sold and a 5.5% increase in the cost per pound of PVC pipe sold related to higher PVC resin costs driven by high global demand and an increase in the cost of ethylene, a key ingredient in the production of PVC resin. The reduction in operating expenses reflects a reduction in incentive compensation related to the decrease in profit margins between the quarters. The increase in depreciation and amortization expense is related to equipment replacement costs incurred in 2013 at our Arizona plant.

39

Corporate

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

	Three Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Expenses	$	2,967	$	2,498	$	469			18.8
Depreciation and Amortization		50		121		(71	)		(58.7	)

The increase in Corporate operating expense reflects increases in employee benefit expenses and higher insurance costs totaling $0.7 million, which were partially offset by the allocation of a portion of the increased costs to the Electric segment.

Interest Charges

An increase in capitalized interest expense at OTP related to OTP’s increasing investment in the Big Stone Plant Air Quality Control System (AQCS) project contributed $0.5 million to the $1.3 million decrease in interest charges between the quarters. Interest on Otter Tail Corporation’s line of credit borrowings were $0.4 million in the third quarter of 2012 compared to $0 in the third quarter of 2013. The early redemption, on July 13, 2012, of our $50 million, 8.89% senior unsecured note, resulted in a $0.2 million decrease in interest charges between quarters. Interest charges also decreased by $0.2 million as a result of OTP’s debt refinancing on March 1, 2013, when it borrowed $40.9 million under an unsecured term loan due June 1, 2014, bearing interest at LIBOR plus 0.875%, and used a portion of the proceeds to redeem its $25.1 million in outstanding 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds.

Loss on Early Retirement of Debt

On July 13, 2012 we prepaid in full our outstanding $50 million, 8.89% Senior Unsecured Note due November 30, 2017 (the Cascade Note). The price 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. On repayment, $606,000 in unamortized debt expense related to the Cascade Note was immediately recognized as expense along with the $12,500,000 negotiated prepayment premium. The $13,106,000 ($7,864,000 net-of-tax) loss on early retirement of debt had a negative impact on third quarter 2012 diluted earnings per share of $0.22.

Other Income

Other income increased $0.7 million in the three months ended September 30, 2013 compared with the three months ended September 30, 2012 due to an increase in allowance for equity funds used during construction (AFUDC) related to costs incurred in the construction of the new air quality control system (AQCS) at OTP’s Big Stone Plant.

40

Income Taxes – Continuing Operations

Income taxes - continuing operations increased $5.9 million in the third quarter of 2013 compared with the third quarter of 2012. 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 September 30, 2013 and 2012:

	Three Months Ended September 30,
(in thousands)	2013			2012
Income Before Income Taxes – Continuing Operations	$	19,959		$	4,016
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,784			1,566
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,162	)		(1,239	)
Research and Development Tax Credits from 2012		(520	)		--
Corporate Owned Life Insurance		(227	)		(118	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(297	)
Employee Stock Ownership Plan Dividend Deduction		(190	)		(190	)
Medicare Part D Subsidy		--			(196	)
Other Items – Net		(340	)		(311	)
Income Tax Expense (Benefit) – Continuing Operations	$	5,133		$	(785	)
Effective Income Tax Rate – Continuing Operations		25.7	%		(19.5	)%

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. The research and development tax credits were recorded at BTD in conjunction with the filing of our 2012 extended federal tax return. The Research and Development Tax Credit expired at the end of 2011 and had not been extended as of December 31, 2012. The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, extended the credits retroactively through the end of 2013.

Discontinued Operations

On February 8, 2013 we completed the sale of substantially all the assets of our waterfront equipment business for approximately $13.0 million in cash and received a working capital true up of approximately $2.4 million in June 2013. On November 30, 2012 we completed the sale of the assets of our wind tower manufacturing business. On February 29, 2012 we sold DMS Health Technologies, Inc. (DMS) and in 2011 we sold E.W. Wylie Corporation (Wylie), our trucking business. The financial position of our waterfront equipment and wind tower manufacturing companies and the results of operations and cash flows of our waterfront equipment and wind tower manufacturing companies, DMS and Wylie are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the three month periods ended September 30, 2013 and 2012:

	For the Three Months Ended September 30,
(in thousands)	2013			2012
Operating Revenues	$	--		$	61,827
Operating Expenses		(452	)		64,866
Operating Income (Loss)		452			(3,039	)
Other (Deductions) Income		(101	)		36
Income Tax Expense (Benefit)		39			(75	)
Net Income (Loss)	$	312		$	(2,928	)

41

Comparison of the Nine Months Ended September 30, 2013 and 2012

Consolidated operating revenues were $660.1 million for the nine months ended September 30, 2013 compared with $646.6 million for the nine months ended September 30, 2012. Operating income was $68.2 million for the nine months ended September 30, 2013 compared with $57.9 million for the nine months ended September 30, 2012. The Company recorded diluted earnings per share from continuing operations of $1.02 for the nine months ended September 30, 2013 compared to $0.59 for the nine months ended September 30, 2012 and total diluted earnings per share of $1.04 for the nine months ended September 30, 2013 compared to ($0.24) for the nine months ended September 30, 2012.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the nine month periods ended September 30, 2013 and 2012 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2013		September 30, 2012
Operating Revenues:
Electric	$	66	$	72
Nonelectric		8		6
Cost of Goods Sold		15		51
Other Nonelectric Expenses		59		27

Electric

	Nine Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Retail Sales Revenues	$	237,344	$	224,763	$	12,581			5.6
Wholesale Revenues – Company Generation		10,247		9,454		793			8.4
Net Revenue – Energy Trading Activity		1,294		1,214		80			6.6
Other Revenues		21,270		22,099		(829	)		(3.8	)
Total Operating Revenues	$	270,155	$	257,530	$	12,625			4.9
Production Fuel		52,341		48,501		3,840			7.9
Purchased Power – System Use		36,575		34,624		1,951			5.6
Other Operation and Maintenance Expenses		98,878		91,137		7,741			8.5
Asset Impairment Charge		--		432		(432	)		(100.0	)
Depreciation and Amortization		32,090		31,351		739			2.4
Property Taxes		9,088		8,120		968			11.9
Operating Income	$	41,183	$	43,365	$	(2,182	)		(5.0	)
Electric kwh Sales (in thousands)
Retail kwh Sales		3,255,205		3,115,055		140,150			4.5
Wholesale kwh Sales – Company Generation		333,743		337,344		(3,601	)		(1.1	)
Wholesale kwh Sales – Purchased Power Resold		131,463		80,234		51,229			63.8
Heating Degree Days		6,191		4,521		1,670			36.9
Cooling Degree Days		539		654		(115	)		(17.6	)

The $12.6 million increase in retail sales revenues reflects the following:

● a $5.7 million increase in retail revenue related to increases in FCA revenues and fuel and purchased power costs recovered in base rates driven by increased kwh generation to meet higher retail kwh sales demand and higher prices for purchased power,

● a $3.9 million increase in revenues related to a 4.5% increase in retail kwh sales resulting from significantly colder weather in 2013 compared to 2012 as evidenced by a 36.9% increase in heating-degree days between the periods, and

● a $3.4 million increase in Transmission Cost Recovery Rider revenuesresulting from increased investment in transmission lines,

42

offset by:

● a $0.3 million reduction in Minnesota and North Dakota renewable rider revenues.

Wholesale electric revenues from company-owned generation increased $0.8 million as a result of a 9.6% increase in wholesale electric prices driven by higher natural gas prices and increased market demand due to more seasonal weather in the first nine months of 2013 compared to milder weather in the first nine months of 2012.

Other electric operating revenues decreased $0.8 million as a result of:

● a $1.6 million reduction in estimated revenue from shared use of transmission facilities with other regional transmission providers, and

● a $0.4 million reduction in revenues from electric construction work completed for other regional utilities,

offset by:

● a $0.6 million increase in revenue from steam sales to an ethanol producer adjacent to OTP’s Big Stone Plant site, due to the customer burning less natural gas to meet its steam requirements in 2013 in response to rising natural gas prices, and

● a $0.6 million increase in MISO tariff revenue related to increasing investments in regional transmission projects, mainly CapX2020 projects.

Fuel costs increased $3.8 million due to an 11.7% increase in kwhs generated from OTP’s steam-powered and combustion turbine generators as a result of greater plant availability in 2013 and higher system demand driven by more seasonal weather in the first nine months of 2013 compared to the first nine months of 2012. The increase in fuel costs related to the increase in kwhs generated was partially offset by a 3.4% decrease in the cost of fuel per kwh generated.

The cost of purchased power for retail sales increased $2.0 million as a result of a 7.2% increase in the cost per kwh purchased. The increase in purchased power prices was driven by rising natural gas prices and an increase in demand due to more seasonal weather in the first nine months of 2013 compared to milder weather in the first nine months of 2012.

Electric operating and maintenance expenses increased $7.7 million mainly due to the following:

● a $3.1 million increase in MISO transmission tariff charges related to increasing investments in regional CapX2020 and MISO-designated MVPs,

● a $2.7 million increase in labor and benefit expenses due to increases in pension and retirement health benefit costs resulting from reductions in discount rates related to projected benefit obligations, wage increases and a reduction in capitalized labor in 2013 compared with 2012,

● a $1.8 million increase in general and administrative expenses, mostly related to an increase in corporate costs allocated to the Electric segment due, in part, to changes in allocation factors resulting from the corporation’s recent divestitures and an increase in accrued performance incentives,

● a $0.7 million discount on OTP’s investment in the Minnesota jurisdictional share of abandoned transmission plant that was transferred from Construction Work in Progress to a regulatory asset account for future recovery, as the initial investment was deemed prudent but potential future uses for the assets did not materialize, and

● a $0.7 million increase in transportation expenses related to higher gasoline prices and a reduction in capitalized transportation expenses due, in part, to the completion of the Bemidji to Grand Rapids 230 kiloVolt (kV) transmission line in September 2012,

 offset by:

● a $1.4 million reduction in external service, material and operating supply costs, which were higher in 2012 primarily as a result of a seven-week scheduled maintenance outage at Coyote Station.

Otter Tail Energy Services Company (OTESCO) recorded a $0.4 million asset impairment charge related to wind farm development rights at its Sheridan Ridge and Stutsman County sites in North Dakota in the first quarter of 2012 as a potential sale of the rights did not occur as expected. OTESCO ceased operations in July 2013. OTESCO has not recorded any operating revenues, expenses or net income in 2013.

The $1.0 million increase in property tax expense is related to higher property value assessments in Minnesota and South Dakota.

43

Manufacturing

	Nine Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Revenues	$	152,282	$	159,091	$	(6,809	)		(4.3	)
Cost of Goods Sold		113,970		120,346		(6,376	)		(5.3	)
Operating Expenses		14,282		13,754		528			3.8
Depreciation and Amortization		8,541		9,200		(659	)		(7.2	)
Operating Income	$	15,489	$	15,791	$	(302	)		(1.9	)

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

● Revenues at BTD decreased $6.8 million as a result of lower sales volume due to reduced demand from customers in end markets serving the construction and energy industries, partially offset by increased salesto customers in end markets serving the recreational equipment and agricultural industries.

● Revenues at T.O. Plastics were unchanged between the periods.

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

● Cost of goods sold at BTD decreased $5.6 million due to reductions in material costs related to decreased sales volume.

● Cost of goods sold at T.O. Plastics decreased $0.8 million as a result of reductions in raw material costs and reduced conversion costs related to productivity improvements.

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

● Operating expenses at BTD increased $0.3 million as a result of an increase in contracted service costs and compensation-related expenses.

● Operating expenses at T.O. Plastics increased $0.2 million due to increases in contracted service costs.

Depreciation expense decreased as a result of certain assets, mainly equipment, at BTD’s Illinois plant being fully depreciated early in 2013.

Construction

	Nine Months Ended
	September 30,								%
(in thousands)	2013		2012			Change			Change
Operating Revenues	$	108,928	$	111,482		$	(2,554	)		(2.3	)
Cost of Goods Sold		96,875		111,869			(14,994	)		(13.4	)
Operating Expenses		8,981		9,415			(434	)		(4.6	)
Depreciation and Amortization		1,518		1,454			64			4.4
Operating Income (Loss)	$	1,554	$	(11,256	)	$	12,810			113.8

The decrease in revenues in our Construction segment revenues reflects the following:

● Revenues at Aevenia decreased $13.4 million as a result of a decrease in construction activity due to a strategic reduction in the volume of telecommunications jobs pursued in 2013 and to a harsher winter and colder and wetter spring in 2013 that delayed the start of many construction projects, relative to the early start to construction that was facilitated by extremely mild weather in the first six months of 2012. Aevenia’s revenues in the first nine months of 2012 also included $5.0 million from MEI, an Aevenia subsidiary that was sold in October 2012.

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● Revenues at Foley increased $10.9 million, mainly as a result of as a result of recognizing more revenue in 2013 on several large projects initiated in 2012.

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

● Cost of goods sold at Aevenia decreased $10.7 million as a result of a decrease in construction activitydue to the strategic reduction in telecommunications jobs pursued in 2013 and the harsher winter and colder and wetter spring in 2013 delaying the start of many construction projects, and due to the sale of MEI in October 2012.MEI’s cost of goods sold totaled $4.1 million in the first nine months of 2012.

● Cost of goods sold at Foley decreased $4.3 million as a result of a $9.8 million reduction in cost overruns between the periods on major projects nearing completion during the periods, partially offset by a $5.5 million increase in costs mainly related to the increased volume of work being done in 2013 on several large projects that were initiated during 2012.

Aevenia’s operating expenses decreased $0.4 million in 2013 as a result of the sale of MEI in October 2012.

Plastics

	Nine Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Revenues	$	128,820	$	118,582	$	10,238			8.6
Cost of Goods Sold		100,644		89,710		10,934			12.2
Operating Expenses		6,262		6,560		(298	)		(4.5	)
Depreciation and Amortization		2,483		2,362		121			5.1
Operating Income	$	19,431	$	19,950	$	(519	)		(2.6	)

The increase in Plastics segment revenue is the result of a 9.8% increase in pounds of PVC pipe sold, partially offset by a 1.1% decrease in the price per pound of pipe sold. Sales volume increased as construction and housing markets continued to improve in the South Central and Southwest regions of the United Statesand construction activity increased in the North Central United States in the third quarter of 2013. The increase in costs of goods sold was mostly due to the increase in pounds of pipe sold, but also reflects a 2.1% increase in the cost per pound of pipe sold related to higher PVC resin costs driven by high global demand and an increase in the cost of ethylene, a key ingredient in the production of PVC resin. The reduction in operating expenses reflects a reduction in incentive compensation related to the decrease in profit margins between the periods. The increase in depreciation and amortization expense is related to equipment replacement costs incurred in 2013 at our Arizona plant.

Corporate

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

	Nine Months Ended
	September 30,							%
(in thousands)	2013		2012		Change			Change
Operating Expenses	$	9,345	$	9,603	$	(258	)		(2.7	)
Depreciation and Amortization		162		373		(211	)		(56.6	)

The decrease in Corporate operating expense reflects a $0.8 million decrease in various corporate administrative and general expensesand a $2.0 million increase in Corporate expenses allocated to our Electric segment, partially offset by a $1.8 million increase in stock incentive award accruals resulting from the strong performance of our common stock price as measured against the stock performances of our peer group of companies in the Edison Electric Institute Index and a $0.6 million increase in labor costs mainly related to staffing additions at Varistar Corporation (Varistar).

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Interest Charges

The $4.5 million decrease in interest charges in the first nine months of 2013 compared with the first nine months of 2012, is due, in part, to the early redemption, in July 2012, of our $50 million, 8.89% senior unsecured note, which resulted in a $2.7 million decrease in interest and debt amortization charges between periods. Interest on Otter Tail Corporation’s line of credit borrowings decreased $0.5 million from 2012 and our line of credit non-use fees decreased by $0.3 million in 2012 as a result of reducing the line limit by $50 million in October 2012. An increase in capitalized interest expense at OTP related to OTP’s increasing investment in the Big Stone Plant AQCS contributed $0.6 million to the decrease in interest charges. Interest charges decreased $0.4 million as a result of OTP’s debt refinancing on March 1, 2013, when it borrowed $40.9 million under an unsecured term loan due June 1, 2014, bearing interest at LIBOR plus 0.875% and used a portion of the proceeds to redeem its $25.1 million in outstanding 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds.

Loss on Early Retirement of Debt

On July 13, 2012 we prepaid in full the Cascade Note at a price of $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. 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. The $13,106,000 ($7,864,000 net-of-tax) loss on early retirement of debt had a negative impact on 2012 diluted earnings per share of $0.22.

Other Income

Other income increased $0.7 million in the nine months ended September 30, 2013 compared with the nine months ended September 30, 2012, mainly due to an increase in equity AFUDC related to costs incurred in the construction of the new AQCS at OTP’s Big Stone Plant.

Income Taxes – Continuing Operations

Income taxes - continuing operations increased $12.9 million in the first nine months of 2013 compared with the first nine months of 2012. 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 nine month periods ended September 30, 2013 and 2012:

	Nine Months Ended September 30,
(in thousands)	2013			2012
Income Before Income Taxes – Continuing Operations	$	50,677		$	22,077
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		19,764			8,610
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(4,592	)		(5,057	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			(676	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(651	)		(668	)
Corporate Owned Life Insurance		(621	)		(503	)
Medicare Part D Subsidy		--			(587	)
Employee Stock Ownership Plan Dividend Deduction		(568	)		(571	)
Research and Development Tax Credits from 2012		(520	)		--
Deferred Tax Asset Reduction – North Dakota, due to Tax Rate Decrease		365			--
Other Items – Net		(64	)		(348	)
Income Tax Expense – Continuing Operations	$	13,113		$	200
Effective Income Tax Rate – Continuing Operations		25.9	%		0.9	%

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. The research and development tax credits were recorded at BTD in conjunction with the filing of our 2012 extended federal tax return. The Research and Development Tax Credit expired at the end of 2011 and had not been extended as of December 31, 2012. The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, extended the credits retroactively through the end of 2013.

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Discontinued Operations

On February 8, 2013 we closed on the sale of substantially all the assets of our water front equipment business for approximately $13.0 million in cash and received a working capital true up of approximately $2.4 million in June 2013. In the first quarter of 2013, we paid approximately $0.8 million in expenses related to the sale of our waterfront equipment business and we also paid a $1.7 million working capital settlement to the purchaser of DMS, which was sold on February 29, 2012. On November 30, 2012 we completed the sale of the assets of our wind tower manufacturing business and in 2011 we sold Wylie, our trucking business. The financial position of our waterfront equipment and wind tower manufacturing companies and the results of operations and cash flows of our waterfront equipment and wind tower manufacturing companies, DMS and Wylie are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the nine month periods ended September 30, 2013 and 2012:

	For the Nine Months Ended September 30,
(in thousands)	2013			2012
Operating Revenues	$	2,016		$	208,186
Operating Expenses		2,094			203,961
Asset Impairment Charge		--			45,573
Operating Loss		(78	)		(41,348	)
Interest Charges		--			174
Other Income		471			266
Income Tax Benefit		(35	)		(14,683	)
Net Income (Loss) from Operations		428			(26,573	)
Gain (Loss) on Disposition Before Taxes		216			(3,713	)
Income Tax Expense (Benefit) on Disposition		6			(169	)
Net Gain (Loss) on Disposition		210			(3,544	)
Net Income (Loss)	$	638		$	(30,117	)

FINANCIAL POSITION

The following table presents the status of our lines of credit as of September 30, 2013 and December 31, 2012:

(in thousands)	Line Limit		In Use on September 30, 2013		Restricted due to Outstanding Letters of Credit		Available on September 30, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	680	$	149,320	$	149,267
OTP Credit Agreement		170,000		40,335		1,189		128,476		166,811
Total	$	320,000	$	40,335	$	1,869	$	277,796	$	316,078

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

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 11, 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 (the 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.

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Equity or debt financing will be required in the period 2013 through 2017 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, 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 five 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 and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 8 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the Board of Directors.

Cash provided by operating activities from continuing operations was $95.8 million for the nine months ended September 30, 2013 compared with $100.7 million for the nine months ended September 30, 2012. The $4.9 million decrease in cash provided by operating activities from continuing operations reflects a $2.4 million increase in cash used for working capital items in the first nine months of 2013 compared to the first nine months of 2012. The $48.7 million in cash provided by discontinued operations in 2012 came mostly from collection of accounts receivable at our former wind tower manufacturing company as it wound down business in 2012. This cash was used to pay down borrowings on our line of credit, which were drawn on to fund the early retirement of our $50 million, 8.89% senior unsecured note on July 13, 2012.

Net cash used in investing activities of continuing operations was $107.8 million for the nine months ended September 30, 2013 compared to $92.7 million for the nine months ended September 30, 2012 mainly due to increases in cash used for capital expenditures of $13.5 million at OTP and $1.9 million at Aevenia between the periods. OTP’s $96.9 million in capital expenditures in the first nine months of 2013 includes a significant level of expenditures for the construction of Big Stone Plant’s AQCS and expenditures for the construction of two major CapX2020 transmission line projects, the Fargo–Monticello 345 kV Project and the Brookings–Southeast Twin Cities 345 kV Project. Net proceeds from the sale of discontinued operations of $12.8 million in the first nine months of 2013 reflect $14.5 million in net proceeds from the sale of the assets of our waterfront equipment manufacturing business less a $1.7 million working capital settlement paid to the buyer of DMS, which we sold in the first quarter of 2012. Net proceeds from the sale of discontinued operations of $24.3 million in the first nine months 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 January 2012 sale of the assets of Aviva Sports, Inc., a wholly owned subsidiary of our waterfront equipment manufacturing company. Net cash used in investing activities of discontinued operations of $11.5 million in the first nine months of 2012 reflects cash used by DMS to purchase assets held under operating leases.

Net cash provided by financing activities of continuing operations of $8.6 million reflects $40.3 million in proceeds from short term borrowings at OTP to fund its significant level of capital expenditures, and $1.5 million from the issuance of common stock, offset by $33.0 million in common and preferred stock dividend payments. On March 1, 2013 OTP used proceeds from a $40.9 million unsecured term loan to fund the redemption of all $25.1 million of the then outstanding 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds, and to pay off an intercompany note to us that mirrored our $15.5 million in outstanding cumulative preferred shares, which were also redeemed on March 1, 2013. We also paid out an additional $0.3 million for the retirement of debt and $0.1 million in debt issuance expenses.

CAPITAL REQUIREMENTS

2013-2017 Capital Expenditures

We plan to invest in generation and transmission projects for the Electric segment that are expected to positively impact our earnings and returns on capital. In addition to the Big Stone Plant air quality control system project, current Electric segment projects include investment in four new transmission line projects.

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In May 2013, we revised our consolidated capital expenditures expectation for 2013 from the range of $200 million to $210 million anticipated in our initial capital budget to a range of $165 million to $175 million. In the first quarter of 2013 OTP revised downward its estimates of its share of capital expenditures required for the construction of a new air quality control system at Big Stone Plant from $265 million to $218 million as a result of a reduction in expected costs due to prudent design changes, low bids in a buyer’s market and in-house project management. In addition, changes were made to revise the anticipated timing of a portion of Big Stone area transmission project capital costs from 2016 and 2017 into 2018 and 2019.

The following table shows our revised 2013 through 2017 anticipated capital expenditures and electric utility average rate base:

(in millions)	2012 Actual		2013		2014		2015		2016		2017
Capital Expenditures:
Electric Segment:
Transmission			$	51	$	61	$	45	$	105	$	62
Environmental				74		79		55		1		--
Other				34		36		37		36		39
Total Electric Segment	$	102	$	159	$	176	$	137	$	142	$	101
Manufacturing and Infrastructure Segments		14		12		19		19		15		20
Total Capital Expenditures	$	116	$	171	$	195	$	156	$	157	$	121
Total Electric Utility Average Rate Base	$	694	$	767	$	890	$	999	$	1,067	$	1,133

Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2013 through 2017 timeframe. Our 2013 through 2017 electric utility capital expenditures are subject to periodic review and revision, and actual construction costs may be lower or higher than these estimates due to numerous factors. Some of the factors include: the cost and efficiency of construction labor, equipment and materials; project scope and design changes; changes in construction schedules; business and economic conditions; the cost and availability of capital; and environmental requirements. Changes in the estimates to the actual construction costs could have an impact on the growth in the utility’s rate base and future earnings. We intend to maintain the equity-to-total capitalization ratio near its present level of 52% in our Electric segment and will seek to earn the electric utility’s authorized overall return on equity of approximately 10.5% in its regulatory jurisdictions.

Contractual Obligations

Our contractual obligations reported in the table on page 51 of our Annual Report on Form 10-K for the year ended December 31, 2012 have increased by $292 million as of September 30, 2013.

Our obligations for the purchase of coal have increased by $4 million for 2013 and $7 million for 2014 and 2015 related to agreements entered into in February, May and September 2013 for the purchase of additional coal to meet portions of Big Stone Plant’s and Hoot Lake Plant’s remaining coal requirements for 2013, 2014 and 2015.

Our long-term debt obligations have increased by $41 million for 2014 related to OTP’s March 2013 borrowings under an unsecured term loan, and decreased by $5 million for 2017 and $20 million for the years beyond 2017 related to the early redemption of all of the 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds outstanding on March 1, 2013.

As a result of the March 1, 2013 debt issuance and redemptions, our interest obligations on long-term debt decreased by $1 million for 2013, $2 million for 2014 and 2015, $2 million for 2016 and 2017 and $5 million for the years beyond 2017.

Our obligations under capacity and energy purchase agreements have increased by $1 million for 2013, $12 million for 2014 and 2015, $13 million for 2016 and 2017 and $167 million for the years beyond 2017. In the second quarter of 2013, OTP entered into a 25-year agreement for the purchase of wind generated electricity from the Ashtabula Wind III, LLC’s 39 wind turbines located in Barnes County, North Dakota. In September of 2013, OTP entered into an agreement with Great River Energy for the purchase of 25 megawatts (MW) of capacity from June 1, 2017 through May 31, 2019 and 50 MW of capacity from June 1, 2019 through May 31, 2021 to meet OTP’s future capacity requirements.

Other Purchase Obligations have increased by $47 million for 2013 and $35 million for 2014 and 2015, mainly for contracts and the acceleration of the timing of committed expenditures related to the construction of Big Stone Plant’s new AQCS.

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CAPITAL RESOURCES

Short-Term Debt

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Credit Agreement), which is an unsecured $150 million revolving credit facility with an accordion feature whereby the line can be increased to $250 million on the terms and subject to the conditions described in the Credit Agreement. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of our subsidiaries. Borrowings under the Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our senior unsecured credit ratings. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Credit Agreement contains a number of restrictions on us and the businesses of Varistar and its material subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, 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 $40 million.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility 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. OTP can draw on this credit facility 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 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay 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, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default. The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

On October 29, 2013 both the Credit Agreement and the OTP Credit Agreement were amended to extend the expiration dates by one year from October 29, 2017 to October 29, 2018.

Long-Term Debt

On March 1, 2013 OTP entered into a Credit Agreement (the Loan Agreement) with JPMorgan Chase Bank, N.A. (JPMorgan) providing for a $40.9 million unsecured term loan (the Term Loan) to OTP originally due on June 1, 2014, which was fully drawn on March 1, 2013. The Loan Agreement was amended on October 29, 2013 to extend the due date on the Term Loan to January 15, 2015. Borrowings under the Loan Agreement bear interest at LIBOR plus 0.875%. The Loan Agreement permits OTP to use the Term Loan proceeds to fund working capital, capital expenditures and for other corporate purposes. On March 1, 2013, OTP utilized approximately $25.1 million of Term Loan proceeds to fund the redemption price for all of the 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds outstanding on that date, in each case for which OTP paid debt service. All such bonds were called for redemption in full on March 1, 2013. Also on March 1, 2013, OTP utilized approximately $15.7 million of Term Loan proceeds to satisfy an intercompany note to us that had a balance and interest rate designed to equate to the balances and dividend rates of our cumulative preferred shares which were redeemed on March 1, 2013 for $15.7 million, including $0.2 million in call premiums charged to equity and included with preferred dividends paid and as part of our preferred dividend requirement for the nine month period ending September 30, 2013.

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The Loan Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Loan Agreement also contains affirmative covenants and events of default. The Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the Loan Agreement are not guaranteed by any other party. OTP may prepay borrowings without premium or penalty upon notice to JPMorgan as provided in the Loan Agreement. In the event of certain “Senior Indebtedness Prepayment Events” as defined in the Loan Agreement, OTP must offer to prepay a ratable portion of the Term Loan.

On August 14, 2013, OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the 2029 Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the 2044 Notes and, together with the 2029 Notes, the Notes). The Notes are expected to be issued on February 27, 2014, subject to the satisfaction of certain customary conditions to closing.

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (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, provided that if no default or event of default under the Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states the Company must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP that will be effective upon issuance of the Notes. These include restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants.  Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2013 Note Purchase Agreement) to exceed 60% of Total Capitalization (as defined in the 2013 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the 2013 Note Purchase Agreement) to exceed 20% of Total Capitalization, also determined as of the end of each fiscal quarter. The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings.  The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the Note Purchase Agreement.  The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the credit agreement, provided that no default or event of default has occurred and is continuing.

OTP intends to use a portion of the proceeds of the Notes to retire early the Term Loan, due January 15, 2015. The remaining proceeds of the Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the Notes and for other general corporate purposes, including planned construction program expenditures.

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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 note purchase agreement relating to OTP’s $140 million 4.63% senior unsecured notes due December 1, 2021 (the 2011 Note Purchase Agreement) each states that OTP 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 OTP 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 2011 Note Purchase Agreement.

The 2007 Note Purchase Agreement and the 2011 Note Purchase Agreement each also states 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, and each contains a number of restrictions on OTP. These include restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties.

Financial Covenants

As of September 30, 2013 we were in compliance with the financial statement covenants 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 borrowing 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 September 30, 2013 our Interest and Dividend Coverage Ratio calculated under the requirements of the Credit Agreement was 3.66 to 1.00.

● Under the OTP Credit Agreement and the Loan Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

● Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, 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 agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of September 30, 2013 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 3.51 to 1.00.

● On issuance of the Notes under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Debt to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement.

As of September 30, 2013 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.

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OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $8.6 million, but our line of credit borrowing limits are only restricted by $1.9 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.

2013 BUSINESS OUTLOOK

We are narrowing our consolidated earnings per share from continuing operations guidance for 2013 to be in the range of $1.38 to $1.50 from our previous guidance of $1.30 to $1.50. This guidance reflects the current mix of businesses owned by us and considers the cyclical nature of some of our businesses.

Segment components of our 2013 earnings per share guidance range are as follows:

	Previous 2013 EPS Guidance		Current 2013 EPS Guidance
	Low	High	Low	High
Electric	$1.02	$1.06	$1.02	$1.04
Manufacturing	$0.27	$0.31	$0.30	$0.33
Construction	$0.01	$0.05	$0.03	$0.05
Plastics	$0.31	$0.35	$0.35	$0.37
Corporate	($0.31)	($0.27)	($0.32)	($0.29)
Total – Continuing Operations	$1.30	$1.50	$1.38	$1.50

Contributing to the earnings guidance for 2013 are the following items:

● We are narrowing our previous 2013 guidance for our Electric segment based on third quarter 2013 results and current expectations for fourth quarter earnings.

● We are increasing and narrowing the range of our previous 2013 guidance for our Manufacturing segment reflecting the following factors:

o Increasing productivity improvements and better than expected third quarter results at BTD, combined with the expectation of recording additional research and development tax credits for the 2013 tax year in the fourth quarter of 2013.

o Stronger than expected third quarter sales at T.O. Plastics, combined with a reduction in expected labor costs.

o Backlog for the manufacturing companies is approximately $47 million for 2013 compared with $45 million one year ago.

● We are narrowing the range of our previous 2013 guidance for our Construction segment. Segment net income is expected to be higher in 2013 than 2012 due to improved cost control processes in construction management and selective bidding on projects with the potential for higher margins. Foley’s performance on certain large projects negatively impacted 2012 results. These projects were substantially completed in 2012 and Foley’s internal bidding and estimating project review procedures have been improved such that we expect Foley to be profitable in 2013. The change in guidance from the second quarter in this segment is also due to improved business conditions at Aevenia. Backlog in place for the construction businesses is $34 million for 2013 compared with $39 million one year ago.

● We are increasing and narrowing the range of our previous 2013 guidance for our Plastics segment based on the strength of its performance in the first nine months of 2013.

● We now expect a minor increase in corporate general and administrative costs in the fourth quarter of 2013 and have adjusted our previous 2013 guidance accordingly.

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Critical Accounting Policies Involving Significant Estimates

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

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, accrued renewable resource and transmission rider revenues, valuations of forward energy contracts, 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 56 through 60 of our Annual Report on Form 10-K for the year ended December 31, 2012. There were no material changes in critical accounting policies or estimates during the quarter ended September 30, 2013.

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:

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

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

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

● 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 2013. 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.

● 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.

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● We currently have $7.3 million of goodwill and a $1.1 million indefinite-lived trade name recorded on our consolidated balance sheet related to the acquisition of Foley Company in 2003. Foley Company generated a large operating loss in 2012 due to significant cost overruns on certain construction projects. If operating margins do not meet our projections, the reductions in anticipated cash flows from Foley Company may indicate that its fair value is less than its book value, resulting in an impairment of some or all of the goodwill and indefinite-lived trade name associated with Foley along with a corresponding charge against earnings.

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

● We may, from time to time, sell assets 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 assets sold and other potential liabilities. The sale of any of our businesses could expose us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

● Our plans to grow and operate our manufacturing and infrastructure businesses could be limited by state law.

● 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.

● 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.

● We may experience fluctuations in revenues and expenses related to our electric 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.

● 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.

● Competition from foreign and domestic manufacturers, the price and availability of raw materials 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 or contracts by our construction businesses could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.

● Our construction subsidiaries enter into contracts 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.

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

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

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

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Item 3.  Quantitative and Qualitative Disclosures about Market Risk

At September 30, 2013 we had exposure to market risk associated with interest rates because we had $40.3 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 1.25% under OTP’s $170 million revolving credit facility.

The majority 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. As of September 30, 2013 we had $40.9 million of long-term debt outstanding under an unsecured term loan subject to a variable interest rate of LIBOR plus 0.875%. Assuming no change in our financial structure, if variable interest rates were to average one percentage point higher or lower than the average variable rate in effect on September 30, 2013, annualized interest expense and pre-tax earnings would change by approximately $409,000.

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

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum and Polystyrene (PS) and other plasticsresins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

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 volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

OTP has market, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of September 30, 2013 we had no unrealized mark-to-market gains or losses in our consolidated statements of income related to forward contracts for the purchase and sale of electricity, but we do have mark-to-market gains and losses deferred on our September 30, 2013 consolidated balance sheet related to contracts for the purchase of electricity to serve OTP’s retail electric customers. 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.

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.

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.

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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 September 30, 2013 and December 31, 2012, and the change in our consolidated balance sheet position from December 31, 2012 to September 30, 2013 and December 31, 2011 to September 30, 2012:

(in thousands)	September 30, 2013			December 31, 2012
Current Asset – Marked-to-Market Gain	$	316		$	502
Regulatory Asset – Current Deferred Marked-to-Market Loss		4,363			7,949
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		8,344			10,050
Total Assets		13,023			18,501
Current Liability – Marked-to-Market Loss		(12,707	)		(18,234	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(8	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(316	)		(210	)
Total Liabilities		(13,023	)		(18,452	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	49

(in thousands)	Year-to-Date September 30, 2013			Year-to-Date September 30, 2012
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	49		$	894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(49	)		(781	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--			(33	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			80
Changes in Fair Value of Contracts Entered into in Current Period		--			(121	)
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	(41	)

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013		2012			2013		2012
Net Gains (Losses) on Forward Electric Energy Contracts	$	1	$	(274	)	$	255	$	(130	)

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. OTP’s credit risk with its largest counterparty on delivered and marked-to-market forward contracts as of September 30, 2013 was $321,000. As of September 30, 2013 OTP had a net credit risk exposure of $335,000 from two counterparties with investment grade credit ratings. OTP had no exposure at September 30, 2013 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 $335,000 credit risk exposure included net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains on forward contracts for the purchase of gasoline scheduled for settlement subsequent September 30, 2013. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

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Item 4.  Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of September 30, 2013, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2013.

During the fiscal quarter ended September 30, 2013, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

Other

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

Item 1A.  Risk Factors

There has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 29 through 35 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

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Item 6.     Exhibits

4.1 Note Purchase Agreement dated as of August 14, 2013, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 16, 2013).

4.2 First Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West and Union Bank, N.A., as Banks (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).

4.3 First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).

4.4 First Amendment to Credit Agreement, dated as of October 29, 2013, between Otter Tail Power Company and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).

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 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended September 30, 2013, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Condensed Consolidated Financial Statements.

SIGNATURES

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

OTTER TAIL CORPORATION

	By:	/s/ Kevin G. Moug
		Kevin G. Moug
		Chief Financial Officer
(Chief Financial Officer/Authorized Officer)

Dated:  November 12, 2013

59

EXHIBIT INDEX

Exhibit Number		Description
	4.1	Note Purchase Agreement dated as of August 14, 2013, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 16, 2013).
	4.2	First Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West and Union Bank, N.A., as Banks (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).
	4.3	First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).
	4.4	First Amendment to Credit Agreement, dated as of October 29, 2013, between Otter Tail Power Company and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by Otter Tail Corporation on November 1, 2013).
	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	Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended September 30, 2013, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Condensed Consolidated Financial Statements.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Edward J. McIntyre, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 12, 2013

/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: November 12, 2013

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2013 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

November 12, 2013

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

November 12, 2013

XML

Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Balance on January 1	$ 4,436
Increases Related to Tax Positions for Prior Years	97
Uncertain Positions Adjusted During Year	(288)
Balance on September 30	$ 4,245

XML

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015
Debt Instrument [Line Items]
Long-Term Debt, Due Date	Jan. 15, 2015
Description of variable rate basis	LIBOR
Basis spread on variable rate	0.875%
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 | Otter Tail Power Company
Debt Instrument [Line Items]
Long-Term Debt, Due Date	Jan. 15, 2015
Description of variable rate basis	LIBOR
Basis spread on variable rate	0.875%
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
9.000% Notes, due December 15, 2016 | Otter Tail Corporation
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
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | Otter Tail Power Company
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%
Long-Term Debt, Due Date		Sep. 01, 2017
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017 | Otter Tail Power Company
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate		4.65%
Long-Term Debt, Due Date		Sep. 01, 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 4.63%, due December 1, 2021 | Otter Tail Power Company
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
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | Otter Tail Power Company
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%
Long-Term Debt, Due Date		Sep. 01, 2022
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022 | Otter Tail Power Company
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate		4.85%
Long-Term Debt, Due Date		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 6.37%, Series C, due August 20, 2027 | Otter Tail Power Company
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
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | Otter Tail Power Company
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%
Other Obligations - Various up to 3.95% | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%

XML

Short-Term and Long-Term Borrowings (Detail textuals 1) (Otter Tail Power Company, Note Purchase Agreement 2013, USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2013

Aug. 14, 2013

Series A Senior Unsecured Notes due on February 27, 2029

Aug. 14, 2013

Series B Senior Unsecured Notes due on February 27, 2044

Debt Instrument [Line Items]

Aggregate principal amount of note

$ 60

$ 90

Debt instrument, interest rate

4.68%

5.47%

Debt Instrument Description Of Prepayment

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (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, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount.

Interest bearing debt, maximum percentage of total capitalization

60.00%

Priority indebtedness, maximum percentage of total capitalization

20.00%

XML

Short-Term and Long-Term Borrowings

9 Months Ended

Sep. 30, 2013

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 September 30, 2013 and December 31, 2012:

(in thousands)	Line Limit		In Use on September 30, 2013		Restricted due to Outstanding Letters of Credit		Available on September 30, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	680	$	149,320	$	149,267
OTP Credit Agreement		170,000		40,335		1,189		128,476		166,811
Total	$	320,000	$	40,335	$	1,869	$	277,796	$	316,078

On October 29, 2013 both the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were amended to extend the expiration dates by one year from October 29, 2017 to October 29, 2018.

Long-Term Debt Issuances, Retirements and Preferred Stock Redemption

On March 1, 2013 OTP entered into a Credit Agreement (the Loan Agreement) with JPMorgan Chase Bank, N.A. (JPMorgan) providing for a $40.9 million unsecured term loan (the Term Loan) to OTP originally due on June 1, 2014, which was fully drawn on March 1, 2013. The Loan Agreement was amended on October 29, 2013 to extend the due date on the Term Loan to January 15, 2015. Borrowings under the Loan Agreement bear interest at LIBOR plus 0.875%. On March 1, 2013, OTP utilized approximately $25.1 million of Term Loan proceeds to fund the redemption price for all of the 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds outstanding on that date, in each case for which OTP pays debt service. All such bonds had been called for redemption in full on March 1, 2013. Also on March 1, 2013, OTP utilized approximately $15.7 million of Term Loan proceeds to satisfy an intercompany note to the Company that had a balance and interest rate designed to equate to the balances and dividend rates of the Company’s cumulative preferred shares. Those cumulative preferred shares were redeemed on March 1, 2013 for $15.7 million, including $0.2 million in call premiums charged to equity and included with preferred dividends paid and as part of our preferred dividend requirement for the nine-month period ending September 30, 2013.

The Loan Agreement contains a number of restrictions on the business of OTP similar to the OTP Credit Agreement, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Loan Agreement also contains affirmative covenants and events of default, as well as a financial covenant under which OTP may not permit the ratio of its Interest bearing Debt to Total Capitalization (as defined in the Loan Agreement) to be greater than 0.60 to 1.00. The Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the Loan Agreement are not guaranteed by any other party. OTP may prepay borrowings without premium or penalty upon notice to JPMorgan as provided in the Loan Agreement. In the event of certain “Senior Indebtedness Prepayment Events” as defined in the Loan Agreement, OTP must offer to prepay a ratable portion of the Term Loan.

On August 14, 2013, OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the 2029 Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the 2044 Notes and, together with the 2029 Notes, the Notes). The Notes are expected to be issued on February 27, 2014, subject to the satisfaction of certain customary conditions to closing.

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (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, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states the Company must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP that will be effective on issuance of the Notes. These include restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants.  Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2013 Note Purchase Agreement) to exceed 60% of Total Capitalization (as defined in the 2013 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the 2013 Note Purchase Agreement) to exceed 20% of Total Capitalization, also determined as of the end of each fiscal quarter. The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings.  The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement.  The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

OTP intends to use a portion of the proceeds of the Notes to retire early the Term Loan, due January 15, 2015. The remaining proceeds of the Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the Notes and for other general corporate purposes, including planned construction program expenditures.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	40,335	$	--	$	--	$	40,335
Long-Term Debt:
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	$	40,900					$	40,900
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
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
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 September 30, 2013		--				1,594		1,594
Total	$	335,900			$	101,594	$	437,494
Less: Current Maturities		--				185		185
Unamortized Debt Discount		--				3		3
Total Long-Term Debt	$	335,900			$	101,406	$	437,306
Total Short-Term and Long-Term Debt (with current maturities)	$	376,235	$	--	$	101,591	$	477,826

December 31, 2012 (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		5,065						5,065
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		20,070						20,070
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, 2012						1,725		1,725
Total	$	320,135			$	101,725	$	421,860
Less: Current Maturities		--				176		176
Unamortized Debt Discount		--				4		4
Total Long-Term Debt	$	320,135			$	101,545	$	421,680
Total Short-Term and Long-Term Debt (with current maturities)	$	320,135	$	--	$	101,721	$	421,856

XML

Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2013		Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	$ 17,754		$ 25,499
Regulatory Liability - Current	734		559
Net Regulatory Assets Position - Current	17,020		24,940
Regulatory Assets - Long-Term	131,921		134,755
Regulatory Liability - Long-Term	70,446		68,835
Net Regulatory Assets Position - Long-Term	61,475		65,920
Regulatory Assets - Total	149,675		160,254
Regulatory Liabilities - Total	71,180		69,394
Net Regulatory Asset Position - Total	78,495		90,860
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	8,410	[1]	8,411	[1]
Regulatory Assets - Long-Term	103,232	[1]	109,538	[1]
Regulatory Assets - Total	111,642	[1]	117,949	[1]
Regulatory Assets - Remaining Recovery/Refund Period	see note	[1]	see note	[1]
Deferred Marked-to-Market Losses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	4,363	[1]	7,949	[1]
Regulatory Assets - Long-Term	8,344	[1]	10,050	[1]
Regulatory Assets - Total	12,707	[1]	17,999	[1]
Regulatory Assets - Remaining Recovery/Refund Period	63 months	[1]	72 months	[1]
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,821	[2]	3,707	[2]
Regulatory Assets - Long-Term	4,332	[2]	2,560	[2]
Regulatory Assets - Total	6,153	[2]	6,267	[2]
Regulatory Assets - Remaining Recovery/Refund Period	21 months	[2]	18 months	[2]
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	550	[1]	526	[1]
Regulatory Assets - Long-Term	4,075	[1]	1,618	[1]
Regulatory Assets - Total	4,625	[1]	2,144	[1]
Regulatory Assets - Remaining Recovery/Refund Period	84 months	[1]	45 months	[1]
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Assets - Long-Term	4,515	[1]	4,137	[1]
Regulatory Assets - Total	4,515	[1]	4,137	[1]
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	351	[1]	268	[1]
Regulatory Assets - Long-Term	2,329	[1]	1,978	[1]
Regulatory Assets - Total	2,680	[1]	2,246	[1]
Regulatory Assets - Remaining Recovery/Refund Period	228 months	[1]	237 months	[1]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,014	[1]		[1]
Regulatory Assets - Long-Term	1,473	[1]	1,352	[1]
Regulatory Assets - Total	2,487	[1]	1,352	[1]
Regulatory Assets - Remaining Recovery/Refund Period			see note	[1]
Regulatory Assets - Remaining Recovery/Refund Period	27 months	[1]
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	1,820	[1]	1,691	[1]
Regulatory Liability - Long-Term	2,248		2,553
Regulatory Assets - Total	1,820	[1]	1,691	[1]
Regulatory Liabilities - Total	2,248		2,553
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
Big Stone II Unrecovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	763	[1]	908	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	763	[1]	908	[1]
Regulatory Assets - Remaining Recovery/Refund Period	6 months	[1]	7 months	[1]
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	100	[2]	100	[2]
Regulatory Assets - Long-Term	869	[2]	711	[2]
Regulatory Assets - Total	969	[2]	811	[2]
Regulatory Assets - Remaining Recovery/Refund Period	116 months	[2]	97 months	[2]
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	313	[2]	532	[2]
Regulatory Assets - Long-Term	864	[2]	1,087	[2]
Regulatory Assets - Total	1,177	[2]	1,619	[2]
Regulatory Assets - Remaining Recovery/Refund Period	18 months	[2]	15 months	[2]
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]	915	[2]
Regulatory Assets - Long-Term	68	[2]		[2]
Regulatory Assets - Total	68	[2]	915	[2]
Regulatory Assets - Remaining Recovery/Refund Period	see note	[2]
Regulatory Assets - Remaining Recovery/Refund Period			5 months	[2]
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			1,737	[1]
Regulatory Assets - Long-Term				[1]
Regulatory Assets - Total			1,737	[1]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[1]
Deferred Holding Company Formation Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	41	[1]	55	[1]
Regulatory Assets - Long-Term		[1]	27	[1]
Regulatory Assets - Total	41	[1]	82	[1]
Regulatory Assets - Remaining Recovery/Refund Period	9 months	[1]	18 months	[1]
General Rate Case Recoverable Expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			279	[1]
Regulatory Assets - Long-Term			6	[1]
Regulatory Assets - Total			285	[1]
Regulatory Assets - Remaining Recovery/Refund Period			13 months	[1]
North Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			110	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			110	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liability - Long-Term	67,610		65,960
Regulatory Liabilities - Total	67,610		65,960
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
Deferred Marked-to-Market Gains
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			8
Regulatory Liability - Long-Term	316		210
Regulatory Liabilities - Total	316		218
Regulatory Liabilities - Remaining Recovery/Refund Period	59 months		68 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	6		6
Regulatory Liability - Long-Term	107		112
Regulatory Liabilities - Total	113		118
Regulatory Liabilities - Remaining Recovery/Refund Period	243 months		252 months
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	44		56
Regulatory Liability - Long-Term
Regulatory Liabilities - Total	44		56
Regulatory Liabilities - Remaining Recovery/Refund Period	3 months		12 months
South Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	4	[2]	2	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	4	[2]	2	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	12 months	[2]
Minnesota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	54		489
Regulatory Liability - Long-Term
Regulatory Liabilities - Total	54		489
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
Revenue for Rate Case expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liability - Long-Term	165
Regulatory Liabilities - Total	165
Regulatory Liabilities - Remaining Recovery/Refund Period	see note
Refundable Fuel Clause Adjustment Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	555
Regulatory Liability - Long-Term
Regulatory Liabilities - Total	555
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
General Rate Case Recoverable Expenses - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	24	[1]
Regulatory Assets - Long-Term		[1]
Regulatory Assets - Total	24	[1]
Regulatory Assets - Remaining Recovery/Refund Period	4 months	[1]
North Dakota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	75
Regulatory Liability - Long-Term
Regulatory Liabilities - Total	$ 75
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months

[1] Costs subject to recovery without a rate of return.

[2] Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

XML

Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues
Electric	$ 86,275	$ 88,550	$ 270,089	$ 257,458
Nonelectric	143,493	126,766	390,022	389,149
Total Operating Revenues	229,768	215,316	660,111	646,607
Operating Expenses
Production Fuel - Electric	18,785	20,622	52,341	48,501
Purchased Power - Electric System Use	8,691	8,138	36,575	34,624
Electric Operation and Maintenance Expenses	30,626	28,717	98,878	91,137
Asset Impairment Charge - Electric				432
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)	115,475	103,152	311,474	321,874
Other Nonelectric Expenses	12,857	12,424	38,811	39,305
Depreciation and Amortization	15,039	15,057	44,794	44,740
Property Taxes - Electric	3,163	2,833	9,088	8,120
Total Operating Expenses	204,636	190,943	591,961	588,733
Operating Income	25,132	24,373	68,150	57,874
Interest Charges	6,574	7,904	20,431	24,970
Loss on Early Retirement of Debt		13,106		13,106
Other Income	1,401	653	2,958	2,279
Income from Continuing Operations Before Income Taxes	19,959	4,016	50,677	22,077
Income Tax Expense (Benefit) - Continuing Operations	5,133	(785)	13,113	200
Net Income from Continuing Operations	14,826	4,801	37,564	21,877
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $39, ($75), ($35) and $3,431 for the respective periods	312	(2,928)	428	886
Impairment Loss - net of Income Tax (Benefit) of $0, $0, $0 and ($18,114) for the respective periods				(27,459)
Gain (Loss) on Disposition - net of Income Tax Expense (Benefit) of $0, $0, $6, and ($169) for the respective periods			210	(3,544)
Net Income (Loss) from Discontinued Operations	312	(2,928)	638	(30,117)
Net Income (Loss)	15,138	1,873	38,202	(8,240)
Preferred Dividend Requirements and Other Adjustments		183	513	551
Earnings (Loss) Available for Common Shares	$ 15,138	$ 1,690	$ 37,689	$ (8,791)
Average Number of Common Shares Outstanding-Basic	36,179,507	36,061,002	36,141,664	36,043,276
Average Number of Common Shares Outstanding-Diluted	36,381,900	36,252,765	36,344,063	36,235,039
Basic Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$ 0.41	$ 0.13	$ 1.02	$ 0.59
Discontinued Operations	$ 0.01	$ (0.08)	$ 0.02	$ (0.83)
Earnings Per Share, Basic, Total	$ 0.42	$ 0.05	$ 1.04	$ (0.24)
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$ 0.41	$ 0.13	$ 1.02	$ 0.59
Discontinued Operations	$ 0.01	$ (0.08)	$ 0.02	$ (0.83)
Earnings Per Share, Diluted, Total	$ 0.42	$ 0.05	$ 1.04	$ (0.24)
Dividends Declared Per Common Share	$ 0.2975	$ 0.2975	$ 0.8925	$ 0.8925

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Rate and Regulatory Matters

9 Months Ended

Sep. 30, 2013

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

3. Rate and Regulatory Matters

Minnesota

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: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, a new standard established by the 2013 legislature requires 1.5% of total electric sales to be supplied by solar energy by the year 2020. OTP is currently evaluating the new legislation and potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the Minnesota Public Utilities Commission (MPUC) may modify or delay implementation of the standards. 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 recovery of Minnesota Renewable Resource Adjustment (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. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by a revised filing on July 25, 2012. Because the request to extend the period of the new rate for 18 months was still under review, a supplemental filing was submitted on February 15, 2013, requesting that the current rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the February 15, 2013 request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. As of May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs. OTP has a regulatory asset of $0.1 million for renewable resource costs and returns eligible for recovery from Minnesota customers that had not been billed to Minnesota customers as of September 30, 2013 that will remain until OTP’s next general rate case.

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 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 exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The 2013 legislature passed legislation that also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case, unless a different return is determined to be in the public interest. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s initial request for approval of a TCR rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010.

In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs then 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. On March 26, 2012 the MPUC approved OTP’s request for an update to the TCR rider, effective April 1, 2012.

In the April 2012 TCR rider update, the MPUC 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. On March 26, 2012 the MPUC approved an all-in method for MISO regional cost allocations 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 for projects included in the TCR.

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. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery. A determination of eligibility for inclusion of the remaining nine projects is still pending. OTP filed its annual update to the TCR on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. The Minnesota Department of Commerce (MNDOC) filed comments on May 24, 2013 recommending removal of capitalized internal labor costs and costs in excess of planning estimates used in prior CON proceedings. OTP filed reply comments on June 27, 2013 disagreeing with the MNDOC’s recommendations. Both parties have filed additional comments supportive of their positions. OTP had a regulatory liability of $0.1 million as of September 30, 2013 for amounts billed to Minnesota customers that are subject to refund through the Minnesota TCR rider.

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, transitioned from a conservation spending goal to a conservation energy savings goal.

The 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 Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

On January 11, 2012 the MPUC approved the recovery of $3.5 million for 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 recognized an additional $0.4 million of incentive related to 2011 and submitted its annual 2011 financial incentive filing request for $2.6 million. In December 2012, the MPUC approved the recovery of $2.6 million in financial incentives for 2011 and also ordered a change in the MNCIP cost recovery methodology used by OTP from a percentage of a customer’s bill to an amount per kilowatt-hour (kwh) consumed. On January 1, 2013 OTP’s MNCIP surcharge decreased from 3.8% of the customer’s bill to $0.00142 per kwh, which equates to approximately 1.9% of a customer’s bill. OTP recognized $2.6 million of MNCIP financial incentives in 2012 and an additional $0.1 million in 2013 relating to 2012 program results. On October 10, 2013 the MPUC approved OTP’s 2012 financial incentive request for $2.7 million as well as its request for an updated surcharge rate to be implemented on November 1, 2013.

OTP has a regulatory asset of $6.1 million for allowable costs and financial incentives that are eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of September 30, 2013. OTP recognized MNCIP-related revenues totaling $1.5 million in each of the three month periods ended September 30, 2013 and September 30, 2012, and $4.8 million in each of the nine month periods ended September 30, 2013 and September 30, 2012.

North Dakota

Renewable Resource Cost Recovery Rider— On May 21, 2008 the North Dakota Public Service Commission (NDPSC) approved OTP’s request for a North Dakota Renewable Resource Cost Recovery Rider Adjustment (NDRRA) to enable OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed. In its 2009 annual request to the NDPSC to increase the amount of the NDRRA, OTP included investment costs and expenses related to its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008. An NDRRA of $0.0051 per kwh was approved by the NDPSC on January 14, 2009 and went into effect beginning with billing statements sent on February 1, 2009. Terms of the approved settlement provide for the recovery of accrued costs and returns on investments in renewable energy facilities under the NDRRA over a period of 48 months beginning in January 2010.

The 2010 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, which was approved by the NDPSC on March 21, 2012. The 2011 NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. OTP submitted its annual update to the NDRRA on December 28, 2012 with a proposed April 1, 2013 effective date. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the rate implemented on April 1, 2013. OTP has a regulatory asset of $1.2 million for amounts eligible for recovery through the NDRRA rider that had not been billed to North Dakota customers as of September 30, 2013.

Transmission Cost Recovery Rider—OTP’s initial North Dakota TCR rider went into effect May 1, 2012. On August 31, 2012 OTP filed its annual update to the North Dakota TCR rider rate to reflect updated cost information associated with projects currently in the rider. In addition, OTP proposed to include costs associated with ten additional projects for recovery within the rider. The NDPSC approved OTP’s annual update on December 12, 2012 to go into effect January 1, 2013. OTP filed its annual update to the North Dakota TCR rider rate on August 30, 2013 with a proposed implementation date of January 1, 2014. OTP had a regulatory liability of $0.1 million as of September 30, 2013 for amounts billed to North Dakota customers that are subject to refund through the North Dakota TCR rider.

South Dakota

Transmission Cost Recovery Rider—OTP submitted a request for an initial South Dakota TCR rider to the South Dakota Public Utilities Commission (SDPUC) on November 5, 2010. The South Dakota TCR was approved by the SDPUC and implemented on December 1, 2011. OTP billed $0.6 million to South Dakota customers under the TCR rider from December 1, 2011 through December 31, 2012. On September 4, 2012, OTP filed its annual update to the South Dakota TCR rider rate. Updated rates were approved on April 23, 2013 and went into effect on May 1, 2013. OTP filed its annual update to the South Dakota TCR rider rate on August 30, 2013 with a proposed implementation date of January 1, 2014.

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, which has 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 in OTP’s formula rate: (1) 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 Capacity Expansion 2020 (CapX2020) transmission projects in which OTP is an investor, discussed in more detail below.

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 June 7, 2013, in response to a challenge to the MVP cost allocation heard before the United States Court of Appeals, Seventh Circuit, the Court ruled in favor of MISO and MISO transmission owners, issuing an order affirming the FERC’s approval of the MVP cost allocation.On October 7, 2013 certain parties submitted a Writ of Certiorari to the U.S. Supreme Court appealing the Seventh Circuit decision.

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

The Big Stone South – Brookings MVP—This transmission line is planned at 345 kiloVolt (kV) and will extend 70 miles between a proposed substation near Big Stone City, South Dakota and the new Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy are joint owners of this project and Xcel Energy is the development manager. 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, expected to be in service in 2017, will use previously obtained Big Stone II transmission route permits and easements. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. OTP petitioned the SDPUC on December 19, 2012 to certify a portion of the line route that was originally approved as part of the Big Stone II transmission development. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. OTP and Xcel Energy jointly submitted an application to the SDPUC for a route permit for the southern portion of the Big Stone South to Brookings line on June 3, 2013.

The Big Stone South – Ellendale MVP—This transmission line is a proposed 345 kV line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. 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. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for the ten miles of the proposed line to be built in North Dakota. A joint route permit application was filed by OTP and MDU on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor and Compatibility along with an application for a route permit with the NDPSC on October 18, 2013. If the proposed project receives all the necessary approvals, OTP anticipates the line will be placed in service in 2019.

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 initially 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. In addition, the Big Stone South – Brookings Multi-Value Project is also designated as a CapX2020 project. Recovery of OTP’s CapX2020 transmission investments will be through the MISO Tariff and the Minnesota, North Dakota and South Dakota TCR riders.

The Fargo Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Fargo Project. The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. Construction is underway for the remaining portions of the project, with completion scheduled for May 2015.

The Brookings Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Brookings Project. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. This project is anticipated to be completed in February 2015.

The Bemidji Project—The Bemidji-Grand Rapids transmission line was fully energized and put into service on September 17, 2012.

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 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 the 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 effective on May 29, 2012.

On January 14, 2011 OTP filed a petition asking the MPUC for an Advanced Determination of Prudence (ADP) for anticipated costs associated with 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). On May 24, 2013 legislation was enacted in Minnesota which allows OTP to file for an emission-reduction rider for recovery of the revenue requirements of the AQCS. The legislation authorizes the rider to allow a current return on investment (including CWIP) at the level approved in the utility’s last general rate case, unless a different return is determined by the MPUC to be in the public interest. OTP filed a petition requesting rider recovery on July 31, 2013, with comments received by the Minnesota Chamber of Commerce and the MNDOC on September 26, 2013 and September 30, 2013. OTP filed reply comments agreeing with the MNDOC and Minnesota Chamber of Commerce recommendations and supplying additional detail requested by the MNDOC on October 10, 2013. The MNDOC filed a response to OTP’s reply comments on October 21, 2013 supporting the filing and requesting approval.

On May 9, 2012 the NDPSC approved OTP’s application for an ADP for anticipated AQCS costs attributable to serving OTP’s North Dakota customers. On February 8, 2013, OTP filed a request with the NDPSC for an environmental rider to recover the revenue requirements of the AQCS project beginning January 1, 2013 while under construction, as well as after completion of the project until placed into base rates through the filing of a rate case. The NDPSC suspended the rate without approval on March 1, 2013 pending review of the request. An update of the estimated costs in the request for a rider was filed on May 8, 2013. The NDPSC held a hearing on September 16, 2013 to review OTP’s filing request for an environmental rider.

On March 30, 2012 OTP requested approval from the SDPUC for an environmental rider to recover costs associated with the AQCS. The proposed rider was designed to recover the revenue requirements plus carrying charges of the 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. On April 17, 2013 OTP filed a request to either suspend or withdraw this filing. The SDPUC approved withdrawing this filing on April 23, 2013. Instead of receiving rider recovery on the portion of AQCS construction costs assignable to OTP’s South Dakota customers while the project is under construction, OTP will accrue an Allowance for Funds Used During Construction (AFUDC) on these costs and request recovery of, and a return on, the accumulated costs, including AFUDC, in a future rate filing in South Dakota.

Big Stone II Project

On June 30, 2005 OTP and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. On September 11, 2009 OTP announced its withdrawal—both as a participating utility and as the project’s lead developer—from Big Stone II. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project.

Minnesota—OTP requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers at that time was $3.2 million.

On December 30, 2010 OTP filed a request for an extension of the Minnesota Route Permit for the Big Stone II transmission facilities. The April 25, 2011 MPUC order in OTP’s general rate case, instructed OTP to transfer the $3.2 million Minnesota share of Big Stone II transmission costs to CWIP and to create a tracker account through which any over or under recoveries could be accumulated for refund or recovery determination in future rate cases as a regulatory liability or asset. If determined eligible for recovery under the FERC-approved MISO regional transmission tariff, the Minnesota portion of Big Stone II transmission costs and accumulated AFUDC will receive rate base treatment and recovery through the FERC-approved MISO regional transmission rates. Any amounts over or under collected through MISO rates or from other sources are included in the tracker account. The Minnesota Route Permit for these transmission facilities expired and subsequently OTP determined it was appropriate to treat the transmission projects as cancelled projects includable in the tracker account in the second quarter of 2013.

Approximately $0.4 million of the total Minnesota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP in the first quarter of 2013. The remaining transmission costs could not be used by other active transmission projects. Therefore, these costs, along with accumulated AFUDC, were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota long-term regulatory asset account in May 2013, based on recovery granted in the April 25, 2011 order. Because OTP will not earn a return on these deferred costs over their anticipated recovery period, the recoverable amount of approximately $3.5 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate. In May 2013, OTP recorded a charge of $0.7 million related to the discount in accordance with ASC Topic 980 - Regulated Operations (ASC 980), accounting requirements. The amount of the discount is expected to be recovered, along with the remaining balance of the Big Stone II Unrecovered Project Costs – Minnesota regulatory asset, over an anticipated 89-month recovery period beginning in May 2013 and ending in September 2020.

North Dakota—In an order issued June 25, 2010, the NDPSC authorized recovery of Big Stone II development costs from North Dakota ratepayers, pursuant to a final settlement agreement filed June 23, 2010, between the NDPSC advocacy staff, OTP and the North Dakota Large Industrial Energy Group Interveners. The terms of the settlement agreement indicate that OTP’s discontinuation of participation in the project was prudent and OTP should be authorized to recover the portion of costs it incurred related to the Big Stone II generation project. The North Dakota jurisdictional share of Big Stone II generation costs incurred by OTP and subject to recovery from North Dakota ratepayers was determined to be $4.1 million. The North Dakota portion of Big Stone II generation costs is being recovered over a 36-month period which began on August 1, 2010.

The North Dakota jurisdictional share of Big Stone II costs incurred by OTP related to transmission was $1.1 million. OTP transferred the North Dakota share of Big Stone II transmission costs to CWIP, with such costs subject to AFUDC continuing from September 2009. According to the settlement agreement approved for recovery of the Big Stone II generation costs, if construction of all or a portion of the transmission facilities commences within three years of the NDPSC order approving the settlement agreement, the North Dakota portion of Big Stone II transmission costs and accumulated AFUDC shall be included in the rate base investment for these future transmission facilities. If construction is not commenced on any of the transmission facilities within three years of the NDPSC order approving the settlement agreement, OTP may petition the NDPSC to either continue accounting for these costs as CWIP or to commence recovery of such costs. Approximately $0.3 million of the total North Dakota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP during the first quarter of 2013. The remaining transmission costs have been determined not to be useable by other active transmission projects.

On March 29, 2013, OTP filed a request with the NDPSC for a six month extension of the Big Stone II Cost Recovery Rider. This extension would allow for the recovery of the remaining transmission related costs which have been determined to not be useable with other transmission projects. In the second quarter of 2013, OTP transferred the remaining North Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $1.0 million from CWIP to the Big Stone II Unrecovered Project Costs – North Dakota current regulatory asset account. OTP filed a supplement to the NDPSC request on May 7, 2013 adding AFUDC costs, thus increasing the amount to be collected and the duration of the regulatory asset to be extended eight months. The May 7, 2013 supplemental request was approved by the NDPSC on July 30, 2013, which allows OTP to keep the existing Big Stone II rates in place to recover the remaining transmission costs plus accumulated AFUDC over an eight month period ending March 31, 2014.

South Dakota—OTP requested recovery of the South Dakota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in South Dakota on August 20, 2010. In the first quarter of 2011, the SDPUC approved recovery of the South Dakota portion of Big Stone II generation development costs totaling approximately $1.0 million from South Dakota ratepayers over a ten-year period beginning in February 2011 with the implementation of interim rates. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates. A portion of the Big Stone II transmission costs were transferred out of CWIP in February 2013 to be included within the Big Stone South - Brookings MVP. On March 28, 2013, OTP filed a petition with the SDPUC requesting deferred accounting for the remaining unrecovered Big Stone II Transmission costs until OTP’s next South Dakota general rate case. The petition was approved by the SDPUC on April 23, 2013 and in May 2013 OTP transferred the remaining South Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $0.2 million from CWIP to the Big Stone II Unrecovered Project Costs – South Dakota long-term regulatory asset account.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Schedule of percent of consolidated sales revenue by country

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
United States of America		97.7	%		97.7	%		97.7	%		97.7	%
Mexico		1.5	%		1.1	%		1.3	%		1.0	%
Canada		0.7	%		1.1	%		0.9	%		1.2	%
All Other Countries (none greater than 0.08%)		0.1	%		0.1	%		0.1	%		0.1	%

Schedule of total assets by business segment

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	86,283		$	88,564		$	270,155		$	257,530
Manufacturing		49,323			46,618			152,282			159,091
Construction		47,509			37,931			108,928			111,482
Plastics		46,659			42,217			128,820			118,582
Intersegment Eliminations		(6	)		(14	)		(74	)		(78	)
Total	$	229,768		$	215,316		$	660,111		$	646,607

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Electric	$	3,960	$	4,880	$	13,032	$	14,493
Manufacturing		816		891		2,447		2,723
Construction		128		305		345		868
Plastics		249		342		753		1,034
Corporate and Intersegment Eliminations		1,421		1,486		3,854		5,852
Total	$	6,574	$	7,904	$	20,431	$	24,970

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	2,565		$	2,995		$	5,830		$	3,817
Manufacturing		1,124			1,288			4,715			5,286
Construction		1,193			(879	)		490			(4,819	)
Plastics		2,278			2,216			7,508			7,113
Corporate		(2,027	)		(6,405	)		(5,430	)		(11,197	)
Total	$	5,133		$	(785	)	$	13,113		$	200

Earnings (Loss) Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	8,787		$	10,206		$	24,301		$	26,413
Manufacturing		2,970			1,914			8,333			7,880
Construction		1,784			(1,325	)		716			(7,252	)
Plastics		3,403			3,309			11,215			10,629
Corporate		(2,118	)		(9,486	)		(7,514	)		(16,344	)
Discontinued Operations		312			(2,928	)		638			(30,117	)
Total	$	15,138		$	1,690		$	37,689		$	(8,791	)

Identifiable Assets

	September 30,		December 31,
(in thousands)	2013		2012
Electric	$	1,280,682	$	1,226,145
Manufacturing		122,942		114,933
Construction		59,904		50,696
Plastics		83,254		78,855
Corporate		111,060		112,616
Discontinued Operations		432		19,092
Total	$	1,658,274	$	1,602,337

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Share-Based Payments - Stock Incentive Awards (Details) (USD $)	0 Months Ended
	Apr. 08, 2013
Restricted Stock | Nonemployee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	16,000
Grant-Date Fair Value per Award	$ 31.03
Vesting Percentage	25.00%
Vesting Date	April 8, 2017
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	17,000
Grant-Date Fair Value per Award	$ 31.03
Vesting Percentage	25.00%
Vesting Date	April 8, 2017
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	50,200
Grant-Date Fair Value per Award	$ 37.51
Vesting Date	December 31, 2015
Restricted Stock Units (Rsus) | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	15,150
Grant-Date Fair Value per Award	$ 25.3
Vesting Percentage	100.00%
Vesting Date	April 8, 2017

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Forward Contracts Classified as Derivatives - Change in consolidated balance sheet location and fair values of forward contracts for purchase and sale of electricity (Details 1) (Forward Electricity Contracts, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$ 49	$ 894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods	(49)	(781)
Changes in Fair Value of Contracts Entered into in Prior Periods		(33)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		80
Changes in Fair Value of Contracts Entered into in Current Period		(121)
Cumulative Fair Value Adjustments Included in Earnings - End of Period		$ (41)

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Pension Plan and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2013

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 September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	1,359		$	1,271		$	4,195		$	3,813
Interest Cost on Projected Benefit Obligation		3,021			3,116			9,093			9,349
Expected Return on Assets		(3,627	)		(3,608	)		(10,891	)		(10,823	)
Amortization of Prior-Service Cost:
From Regulatory Asset		84			100			250			299
From Other Comprehensive Income1		3			3			7			8
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,624			1,229			4,950			3,683
From Other Comprehensive Income1		42			31			132			97
Net Periodic Pension Cost	$	2,506		$	2,142		$	7,736		$	6,426
1Corporate cost included in Other Nonelectric Expenses.

Cash flows—The Company made a discretionary plan contribution of $10,000,000 in January 2013. The Company currently is not required and does not expect to make an additional contribution to the plan in 2013. The Company also made a discretionary plan contribution of $10,000,000 in January 2012.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2013		2012		2013		2012
Service Cost—Benefit Earned During the Period	$	12	$	11	$	38	$	34
Interest Cost on Projected Benefit Obligation		352		370		1,056		1,109
Amortization of Prior-Service Cost:
From Regulatory Asset		6		5		16		16
From Other Comprehensive Income1		13		13		39		39
Amortization of Net Actuarial Loss:
From Regulatory Asset		52		39		156		116
From Other Comprehensive Income2		79		43		235		129
Net Periodic Pension Cost	$	514	$	481	$	1,540	$	1,443
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5	$	5	$	15	$	15
Other Nonelectric Expenses		8		8		24		24
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	49	$	36	$	145	$	108
Other Nonelectric Expenses		30		7		90		21

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of the Medicare Part D Subsidy:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	184		$	386		$	1,066		$	1,158
Interest Cost on Projected Benefit Obligation		318			644			1,538			1,931
Amortization of Transition Obligation:
From Regulatory Asset		--			182			--			546
From Other Comprehensive Income1		--			5			--			15
Amortization of Prior-Service Cost:
From Regulatory Asset		52			51			154			154
From Other Comprehensive Income1		2			2			4			4
Amortization of Net Actuarial Loss:
From Regulatory Asset		(478	)		160			18			481
From Other Comprehensive Income1		(12	)		4			--			13
Net Periodic Postretirement Benefit Cost	$	66		$	1,434		$	2,780		$	4,302
Effect of Medicare Part D Subsidy	$	(227	)	$	(509	)	$	(1,355	)	$	(1,529	)
1Corporate cost included in Other Nonelectric Expenses.

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Discontinued Operations - Results of discontinued operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Income (Loss) from Operations			$ 428	$ (26,573)
Income Tax Expense (Benefit) on Disposition	0	0	6	(169)
Net Gain (Loss) on Disposition			210	(3,544)
Net Income (Loss)	312	(2,928)	638	(30,117)
Disposal groups held for sale or disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		61,827	2,016	208,186
Operating Expenses	(452)	64,866	2,094	203,961
Asset Impairment Charge				45,573
Operating Income (Loss)	452	(3,039)	(78)	(41,348)
Interest Charges				174
Other (Deductions) Income	(101)	36	471	266
Income Tax Expense (Benefit)	39	(75)	(35)	(14,683)
Net Income (Loss) from Operations	312	(2,928)	428	(26,573)
Gain (Loss) on Disposition Before Taxes			216	(3,713)
Income Tax Expense (Benefit) on Disposition			6	(169)
Net Gain (Loss) on Disposition			210	(3,544)
Net Income (Loss)	$ 312	$ (2,928)	$ 638	$ (30,117)

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Summary of Significant Accounting Policies (Detail Textuals 2) (Coyote Creek Mining Company, L.L.C. (CCMC), Lignite Sales Agreement, Otter Tail Power Company, USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company
Variable Interest Entity [Line Items]
Amortization period	52 months
Percentage of development period costs, development fees and capital charge incurred by CCMC	35.00%
Maximum exposure to loss as a result of involvement with CCMC	$ 9.8
Amount of development period costs, development fees and capital charges incurred by CCMC	$ 9.8

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Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan, USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	$ 13	[1]	$ 13	[1]	$ 39	[1]	$ 39	[1]
Amortization of Net Actuarial Loss - From Other Comprehensive Income	79	[2]	43	[2]	235	[2]	129	[2]
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	8		8		24		24
Amortization of Net Actuarial Loss - From Other Comprehensive Income	30		7		90		21
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	5		5		15		15
Amortization of Net Actuarial Loss - From Other Comprehensive Income	$ 49		$ 36		$ 145		$ 108

[1] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 5 $ 5 $ 15 $ 15 Other Nonelectric Expenses 8 8 24 24.

[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 49 $ 36 $ 145 $ 108 Other Nonelectric Expenses 30 7 90 21.

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Forward Contracts Classified as Derivatives - Realized and unrealized net (losses)/gains on forward energy contracts included in electric operating revenues (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Gains (Losses) on Forward Electric Energy Contracts	$ 1	$ (274)	$ 255	$ (130)

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Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details 4) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Level 1
Assets:
Total Assets	$ 962	$ 2,092
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Liabilities:
Derivative Liabilities:
Level 1 | Money Market Fund
Assets:
Other Current Assets - Escrow Account IPH Sale		1,500
Level 1 | Money Market and Mutual Funds
Assets:
Other Current Assets - Nonqualified Retirement Savings Plan	110	110
Other Assets - Nonqualified Retirement Savings Plan	722	357
Level 1 | Equity Securities
Assets:
Other Assets - Nonqualified Retirement Savings Plan	130	125
Level 2
Assets:
Total Assets	8,952	9,353
Liabilities:
Total Liabilities		242
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets		292
Liabilities:
Derivative Liabilities:		242
Level 2 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets	66	136
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	7,608	7,620
Level 2 | U.S. Government Debt Securities
Assets:
Investments - Held by Captive Insurance Company	1,278	1,305
Level 3
Assets:
Total Assets	316	210
Liabilities:
Total Liabilities	12,707	17,992
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	316	210
Liabilities:
Derivative Liabilities:	$ 12,707	$ 17,992

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

Stockholders Equity and Earnings Per Share [Abstract]

Schedule of reconciliation of common shareholders' equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2012	$	180,842		$	253,296		$	92,221		$	(4,385	)	$	521,974
Common Stock Issuances, Net of Expenses		551			1,848									2,399
Common Stock Retirements and Forfeitures		(46	)		(177	)								(223	)
Net Income								38,202						38,202
Other Comprehensive Income											202			202
Tax Benefit – Stock Compensation					59									59
Employee Stock Incentive Plan Expense					313									313
Premium on Purchase of Stock for Employee Purchase Plan					(258	)								(258	)
Cumulative Preferred Dividends								(427	)					(427	)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares					86			(86	)					--
Common Dividends								(32,341	)					(32,341	)
Balance, September 30, 2013	$	181,347		$	255,167		$	97,569		$	(4,183	)	$	529,900

Schedule of common shares outstanding

Common Shares Outstanding, December 31, 2012	36,168,368
Issuances:
Stock Options Exercised	55,109
Vesting of Restricted Stock Units	17,535
Restricted Stock Issued to Employees	17,000
Restricted Stock Issued to Directors	16,000
Director’s Compensation	4,535
Retirements:
Shares Withheld for Individual Income Tax Requirements	(7,184	)
Forfeiture of Unvested Restricted Stock	(2,000	)
Common Shares Outstanding, September 30, 2013	36,269,363

Schedule of diluted earnings per share are the following outstanding stock options

	Options Outstanding	Range of Exercise Prices
Three Months Ended September 30, 2013	--	--
Three Months Ended September 30, 2012	92,497	$24.93 – $27.245
Nine Months Ended September 30, 2013	--	--
Nine Months Ended September 30, 2012	92,497	$24.93 – $27.245

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Forward Contracts Classified as Derivatives (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of marking to market forward contracts for the purchase and sale of electricity

(in thousands)	September 30, 2013			December 31, 2012
Current Asset – Marked-to-Market Gain	$	316		$	502
Regulatory Asset – Current Deferred Marked-to-Market Loss		4,363			7,949
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		8,344			10,050
Total Assets		13,023			18,501
Current Liability – Marked-to-Market Loss		(12,707	)		(18,234	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(8	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(316	)		(210	)
Total Liabilities		(13,023	)		(18,452	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	49

Schedule of change in consolidated balance sheet location and Fair values of forward contracts for purchase and sale of electricity

(in thousands)	Year-to-Date September 30, 2013			Year-to-Date September 30, 2012
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	49		$	894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(49	)		(781	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--			(33	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			80
Changes in Fair Value of Contracts Entered into in Current Period		--			(121	)
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	(41	)

Schedule of realized and unrealized net gains on forward energy contracts

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013		2012			2013		2012
Net Gains (Losses) on Forward Electric Energy Contracts	$	1	$	(274	)	$	255	$	(130	)

Schedule of OTP's credit risk exposure on delivered and marked-to-market forward contracts

	September 30, 2013				December 31, 2012
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	335		2	$	580		6
Net Credit Risk to Single Largest Counterparty	$	321			$	285

Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements

(in thousands)	September 30, 2013			December 31, 2012
Derivative assets subject to legally enforceable netting arrangements	$	382		$	638
Derivative liabilities subject to legally enforceable netting arrangements		(12,707	)		(18,234	)
Net balance subject to legally enforceable netting arrangements	$	(12,325	)	$	(17,596	)

Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2013			December 31, 2012
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	2,176
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		12,707			16,058
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	12,707		$	18,234
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	$	12,707		$	16,058
Offsetting Gains with Counterparties under Master Netting Agreements		(316	)		(416	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	12,391		$	15,642

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Summary of Significant Accounting Policies (Detail Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
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
Foley Company
Significant Accounting Policies [Line Items]
Estimated costs on certain projects in excess of previous period estimates, Pretax charge	$ 0.1	$ 1.7	$ 0.6	$ 10.4

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Summary of Significant Accounting Policies - Percentages of companys consolidated revenues recorded under percentage-of-completion method (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Percentage-of-Completion Revenues	20.60%	17.10%	16.40%	16.80%

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Summary of Significant Accounting Policies - Inventories (Details 6) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Finished Goods	$ 19,682	$ 21,893
Work in Process	10,636	8,800
Raw Material, Fuel and Supplies	42,340	38,643
Total Inventories	$ 72,658	$ 69,336

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Segment Information - Percent of sales revenue by country (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	97.70%	97.70%	97.70%	97.70%
Mexico
Segment Reporting Information [Line Items]
Percentage of sales revenue	1.50%	1.10%	1.30%	1.00%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.70%	1.10%	0.90%	1.20%
All Other Countries (none greater than 0.07%)
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.10%	0.10%	0.10%	0.10%

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Schedule of long-term debt including current maturities

	September 30, 2013						December 31, 2012
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	59,117		$	59,117		$	52,362		$	52,362
Short-Term Debt		(40,335	)		(40,335	)		--			--
Long-Term Debt including Current Maturities		(437,491	)		(486,719	)		(421,856	)		(491,244	)

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details)	9 Months Ended
	Sep. 30, 2013
Stockholders Equity and Earnings Per Share [Abstract]
Balance (shares)	36,168,368
Issuances:
Stock Options Exercised	55,109
Vesting of Restricted Stock Units	17,535
Restricted Stock Issued to Employees	17,000
Restricted Stock Issued to Directors	16,000
Director's Compensation	4,535
Retirements:
Shares Withheld for Individual Income Tax Requirements	(7,184)
Forfeiture of Unvested Restricted Stock	(2,000)
Common Shares Outstanding, September 30, 2013	36,269,363

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Retained Earnings Restriction (Detail Textuals) (USD $) In Thousands, unless otherwise specified			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Otter Tail Power Company	Sep. 30, 2013 Otter Tail Power Company Minimum	Sep. 30, 2013 Otter Tail Power Company Maximum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment				44.80%	54.80%
Equity to total capitalization ratio			49.50%
Total Capitalization	$ 967,206	$ 959,154			$ 874,000

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance			$ 521,974
Common Stock Issuances, Net of Expenses			2,399
Common Stock Retirements and Forfeitures			(223)
Net Income (Loss)	15,138	1,873	38,202	(8,240)
Other Comprehensive Income			202
Tax Benefit - Stock Compensation			59
Employee Stock Incentive Plan Expense			313
Premium on Purchase of Stock for Employee Purchase Plan			(258)
Cumulative Preferred Dividends			(427)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares
Common Dividends			(32,341)
Balance	529,900		529,900
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance			180,842
Common Stock Issuances, Net of Expenses			551
Common Stock Retirements and Forfeitures			(46)
Balance	181,347		181,347
Premium On Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance			253,296
Common Stock Issuances, Net of Expenses			1,848
Common Stock Retirements and Forfeitures			(177)
Tax Benefit - Stock Compensation			59
Employee Stock Incentive Plan Expense			313
Premium on Purchase of Stock for Employee Purchase Plan			(258)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares			86
Balance	255,167		255,167
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance			92,221
Net Income (Loss)			38,202
Cumulative Preferred Dividends			(427)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares			(86)
Common Dividends			(32,341)
Balance	97,569		97,569
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance			(4,385)
Other Comprehensive Income			202
Balance	$ (4,183)		$ (4,183)

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Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 9) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 245	$ 244	$ 733	$ 737

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Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details) (Employee Stock Purchase Plan)	9 Months Ended
	Sep. 30, 2013
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense, discount rate	15.00%

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Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of amount of regulatory assets and liabilities

	September 30, 2013						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,410	$	103,232	$	111,642	see note
Deferred Marked-to-Market Losses1		4,363		8,344		12,707	63 months
Conservation Improvement Program Costs and Incentives2		1,821		4,332		6,153	21 months
Big Stone II Unrecovered Project Costs – Minnesota1		550		4,075		4,625	84 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,515		4,515	asset lives
Debt Reacquisition Premiums1		351		2,329		2,680	228 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,014		1,473		2,487	27 months
Deferred Income Taxes1		--		1,820		1,820	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		313		864		1,177	18 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		869		969	116 months
Big Stone II Unrecovered Project Costs – North Dakota1		763		--		763	6 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		41		--		41	9 months
General Rate Case Recoverable Expenses – South Dakota1		24		--		24	4 months
South Dakota Transmission Rider Accrued Revenues2		4		--		4	12 months
Total Regulatory Assets	$	17,754	$	131,921	$	149,675
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	67,610	$	67,610	asset lives
Deferred Income Taxes		--		2,248		2,248	asset lives
Refundable Fuel Clause Adjustment Revenues		555		--		555	12 months
Deferred Marked-to-Market Gains		--		316		316	59 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		165		165	see note
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		107		113	243 months
North Dakota Transmission Rider Accrued Refund		75		--		75	12 months
Minnesota Transmission Rider Accrued Refund		54		--		54	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		44		--		44	3 months
Total Regulatory Liabilities	$	734	$	70,446	$	71,180
Net Regulatory Asset Position	$	17,020	$	61,475	$	78,495
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

	December 31, 2012						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,411	$	109,538	$	117,949	see note
Deferred Marked-to-Market Losses1		7,949		10,050		17,999	72 months
Conservation Improvement Program Costs and Incentives2		3,707		2,560		6,267	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,137		4,137	asset lives
Debt Reacquisition Premiums1		268		1,978		2,246	237 months
Big Stone II Unrecovered Project Costs – Minnesota1		526		1,618		2,144	45 months
Recoverable Fuel and Purchased Power Costs1		1,737		--		1,737	12 months
Deferred Income Taxes1		--		1,691		1,691	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		532		1,087		1,619	15 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		--		1,352		1,352	see note
Minnesota Renewable Resource Rider Accrued Revenues2		915		--		915	5 months
Big Stone II Unrecovered Project Costs – North Dakota1		908		--		908	7 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		711		811	97 months
General Rate Case Recoverable Expenses1		279		6		285	13 months
North Dakota Transmission Rider Accrued Revenues2		110		--		110	12 months
Deferred Holding Company Formation Costs1		55		27		82	18 months
South Dakota Transmission Rider Accrued Revenue2		2		--		2	12 months
Total Regulatory Assets	$	25,499	$	134,755	$	160,254
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,960	$	65,960	asset lives
Deferred Income Taxes		--		2,553		2,553	asset lives
Minnesota Transmission Rider Accrued Refund		489		--		489	12 months
Deferred Marked-to-Market Gains		8		210		218	68 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		112		118	252 months
South Dakota – Nonasset-Based Margin Sharing Excess		56		--		56	12 months
Total Regulatory Liabilities	$	559	$	68,835	$	69,394
Net Regulatory Asset Position	$	24,940	$	65,920	$	90,860
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement Of Income and Comprehensive Income [Abstract]
Net Income (Loss)	$ 15,138	$ 1,873	$ 38,202	$ (8,240)
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale ofInvestments and Included in Other Income During Period			(25)
Gains (Losses) Arising During Period	19	72	(66)	180
Income Tax (Expense) Benefit	(7)	(29)	32	(72)
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	12	43	(59)	108
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 12)	145	101	436	305
Income Tax Expense	(58)	(41)	(175)	(122)
Pension and Postretirement Benefit Plans - net-of-tax	87	60	261	183
Total Other Comprehensive Income	99	103	202	291
Total Comprehensive Income (Loss)	$ 15,237	$ 1,976	$ 38,404	$ (7,949)

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

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 (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging (ASC 815). 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.

The companies in the Construction segment 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 costs incurred to total estimated costs on construction projects. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Percentage-of-Completion Revenues	20.6	%	17.1	%	16.4	%	16.8	%

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

	September 30,			December 31,
(in thousands)	2013			2012
Costs Incurred on Uncompleted Contracts	$	341,649		$	307,085
Less Billings to Date		(358,026	)		(321,388	)
Plus Estimated Earnings Recognized		5,033			1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

The following amounts are included in the Company’s consolidated balance sheets:

	September 30,			December 31,
(in thousands)	2013			2012
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	4,858		$	3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(16,202	)		(16,204	)
NetBillings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

The Company has a standard quarterly estimate at completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.

In 2012, Foley Company (Foley) experienced cost overruns in excess of estimated costs on several large projects. All of these projects were substantially completed as of December 31, 2012. Estimated costs on certain projects in excess of previous period estimates resulted in pretax charges of $0.1 million in the three months ended September 30, 2013 and $1.7 million in the three months ended September 30, 2012, and $0.6 million in the nine months ended September 30, 2013 and $10.4 million in the nine months ended September 30, 2012.

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 products sold by the Company 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. The warranty reserve balance as of December 31, 2012 and September 30, 2013 relates entirely to products that were produced by the Company’s manufacturers of wind towers and waterfront equipment prior to the Company selling the assets of these companies and is included in liabilities of discontinued operations. See note 17 to consolidated financial statements.

Retainage

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

	September 30,		December 31,
(in thousands)	2013		2012
Accounts Receivable Retained by Customers	$	6,989	$	12,227

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), 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 (NYMEX).

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 the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	316
Forward Gasoline Purchase Contracts				66
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,608
U.S. Government Debt Securities – Held by Captive Insurance Company				1,278
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		722
Equity Securities - Nonqualified Retirement Savings Plan		130
Total Assets	$	962	$	8,952	$	316
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	12,707
Total Liabilities	$	--	$	--	$	12,707

December 31, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	292	$	210
Forward Gasoline Purchase Contracts				136
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				7,620
U.S. Government Debt Securities – Held by Captive Insurance Company				1,305
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		357
Equity Securities - Nonqualified Retirement Savings Plan		125
Total Assets	$	2,092	$	9,353	$	210
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	242	$	17,992
Total Liabilities	$	--	$	242	$	17,992

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of September 30, 2013 and December 31, 2012, are based on prices indexed to observable prices at an active trading hub. The Level 3 forward electric price inputs ranged from $6.95 per megawatt-hour underthe active trading hub price to $2.45 per megawatt-hour over the active trading hub price. The weighted average price was $36.55 per megawatt-hour.

In the table above, the fair values for the Level 3 forward energy contracts as of September 30, 2013 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three or nine month periods ended September 30, 2013 and 2012.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the nine-month periods ended September 30, 2013 and 2012:

	Nine Months Ended
	September 30,
(in thousands)	2013			2012
Forward Energy Contracts  - Fair Values Beginning of Period	$	(17,782	)	$	--
Transfers into Level 3 from Level 2		--			(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		5,066			3,771
Changes in Fair Value of Contracts Entered into in Prior Periods		325			(4,517	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(12,391	)		(16,630	)
Net Increase in Value of Open Contracts Entered into in Current Period		--			22
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(12,391	)	$	(16,608	)

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2013		2012
Finished Goods	$	19,682	$	21,893
Work in Process		10,636		8,800
Raw Material, Fuel and Supplies		42,340		38,643
Total Inventories	$	72,658	$	69,336

Goodwill

The following table summarizes changes to goodwill by business segment during 2013:

(in thousands)	Gross Balance December 31, 2012		Accumulated Impairments		Balance (net of impairments) December 31, 2012		Adjustments to Goodwill in 2013		Balance (net of impairments) September 30, 2013
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Construction		7,483		--		7,483		--		7,483
Plastics		19,302		--		19,302		--		19,302
Total	$	38,971	$	--	$	38,971	$	--	$	38,971

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,722	$	12,089		15 – 25 years
Other Intangible Assets Including Contracts		825		442		383		5 – 30 years
Total	$	17,636	$	5,164	$	12,472
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2012(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,085	$	12,726		15 – 25 years
Other Intangible Assets Including Contracts		1,092		613		479		5 – 30 years
Total	$	17,903	$	4,698	$	13,205
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Amortization Expense – Intangible Assets	$	245	$	244	$	733	$	737

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

(in thousands)	2013		2014		2015		2016		2017
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	977	$	945	$	849

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2013		2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	25,133	$	5,979
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	5,172	$	--
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. 2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

Coyote Station Lignite Supply Agreement – Variable Interest Entity

In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, have the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE. Therefore, CCMC is not required to be consolidated in the Company’s consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through September 30, 2013 is $9.8 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC could be as high as $9.8 million as of September 30, 2013.

Reclassifications and Changes to Presentation

The Company’s consolidated income statement and consolidated statement of cash flows for the three and nine month periods ended September 30, 2012 reflect the reclassifications of the operating results and cash flows of discontinued operations as a result of the completion of the sale of the assets of the Company’s wind tower manufacturer and discontinuance of wind tower production activities in November 2012 and the sale of the assets of the Company’s waterfront equipment manufacturer on February 8, 2013. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or nine months ended September 30, 2012.

New Accounting Standards

Accounting Standards Update (ASU) 2011-11 and 2013-01

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2011-13), to clarify which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The amendments in ASU 2013-01 apply to derivatives accounted for in accordance with ASC 815 and clarify that only derivatives accounted for in accordance with ASC 815 are within the scope of the disclosure requirements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.

The Company implemented the disclosure guidance January 1, 2013. While, certain of the Company’s offsetting derivative asset and liability positions related to forward energy contracts with the same counterparty are subject to legally enforceable netting arrangements, the Company does not present its derivative assets and liabilities subject to legally enforceable netting arrangements, or any related payables or receivables, on a net basis on the face of its consolidated balance sheet. The Company has added disclosures and a table in note 5 to the consolidated financial statements indicating the amounts of its derivative forward energy contracts presented at fair value in accordance with ASC 815 that are subject to legally enforceable netting arrangements. 

ASU 2013-02

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, which requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under accounting principles generally accepted in the United States of America (U.S. GAAP) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail on these amounts. This ASU is effective for reporting periods beginning after December 15, 2012. Additional information required by this update is included on the face of the Company’s consolidated statement of comprehensive income for the period ending September 30, 2013. The amounts of accumulated other comprehensive losses associated with the Company’s pension and other post-retirement benefit programs that are being amortized and recognized as operating expenses and the income statement line item affected by the expense are disclosed in note 12 to the consolidated financial statements.

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2013

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. 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. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	September 30, 2013						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,410	$	103,232	$	111,642	see note
Deferred Marked-to-Market Losses1		4,363		8,344		12,707	63 months
Conservation Improvement Program Costs and Incentives2		1,821		4,332		6,153	21 months
Big Stone II Unrecovered Project Costs – Minnesota1		550		4,075		4,625	84 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,515		4,515	asset lives
Debt Reacquisition Premiums1		351		2,329		2,680	228 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,014		1,473		2,487	27 months
Deferred Income Taxes1		--		1,820		1,820	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		313		864		1,177	18 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		869		969	116 months
Big Stone II Unrecovered Project Costs – North Dakota1		763		--		763	6 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		41		--		41	9 months
General Rate Case Recoverable Expenses – South Dakota1		24		--		24	4 months
South Dakota Transmission Rider Accrued Revenues2		4		--		4	12 months
Total Regulatory Assets	$	17,754	$	131,921	$	149,675
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	67,610	$	67,610	asset lives
Deferred Income Taxes		--		2,248		2,248	asset lives
Refundable Fuel Clause Adjustment Revenues		555		--		555	12 months
Deferred Marked-to-Market Gains		--		316		316	59 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		165		165	see note
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		107		113	243 months
North Dakota Transmission Rider Accrued Refund		75		--		75	12 months
Minnesota Transmission Rider Accrued Refund		54		--		54	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		44		--		44	3 months
Total Regulatory Liabilities	$	734	$	70,446	$	71,180
Net Regulatory Asset Position	$	17,020	$	61,475	$	78,495
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

	December 31, 2012						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	8,411	$	109,538	$	117,949	see note
Deferred Marked-to-Market Losses1		7,949		10,050		17,999	72 months
Conservation Improvement Program Costs and Incentives2		3,707		2,560		6,267	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,137		4,137	asset lives
Debt Reacquisition Premiums1		268		1,978		2,246	237 months
Big Stone II Unrecovered Project Costs – Minnesota1		526		1,618		2,144	45 months
Recoverable Fuel and Purchased Power Costs1		1,737		--		1,737	12 months
Deferred Income Taxes1		--		1,691		1,691	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		532		1,087		1,619	15 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		--		1,352		1,352	see note
Minnesota Renewable Resource Rider Accrued Revenues2		915		--		915	5 months
Big Stone II Unrecovered Project Costs – North Dakota1		908		--		908	7 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		711		811	97 months
General Rate Case Recoverable Expenses1		279		6		285	13 months
North Dakota Transmission Rider Accrued Revenues2		110		--		110	12 months
Deferred Holding Company Formation Costs1		55		27		82	18 months
South Dakota Transmission Rider Accrued Revenue2		2		--		2	12 months
Total Regulatory Assets	$	25,499	$	134,755	$	160,254
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	65,960	$	65,960	asset lives
Deferred Income Taxes		--		2,553		2,553	asset lives
Minnesota Transmission Rider Accrued Refund		489		--		489	12 months
Deferred Marked-to-Market Gains		8		210		218	68 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		112		118	252 months
South Dakota – Nonasset-Based Margin Sharing Excess		56		--		56	12 months
Total Regulatory Liabilities	$	559	$	68,835	$	69,394
Net Regulatory Asset Position	$	24,940	$	65,920	$	90,860
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset related to 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 Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

All Deferred Marked-to-Market Gains and Losses recorded as of September 30, 2013 are related to forward purchases of energy scheduled for delivery through December 2018.

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

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

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

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 228 months.

MISO Schedule 26/26A Transmission Cost Recovery Rider True-up relates to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-up also includes the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule. The September 30, 2013 balance will be amortized on a straight-line basis over two consecutive 12-month periods beginning in January 2014.

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

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2013.

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

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

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of September 30, 2013. A supplemental filing was submitted to the MPUC on February 15, 2013, requesting that the then current MNRRA rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

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

The South Dakota Transmission Rider Accrued Revenues relate to revenues billed for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers net of transmission revenues that have not been billed to South Dakota customers as of September 30, 2013.

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

Revenue for Rate Case Expenses Subject to Refund - Minnesota relate to revenues collected under general rates to recover   costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.

The North Dakota Transmission Rider Accrued Refund relates to revenues earned on qualifying transmission system facilities and operating costs incurred to serve North Dakota customers net of transmission revenues that are refundable to North Dakota customers as of September 30, 2013.

The Minnesota Transmission Rider Accrued Refund relates to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers net of transmission revenues that are refundable to Minnesota customers as of September 30, 2013.

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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Commitments and Contingencies (Detail Textuals) (USD $) In Millions, unless otherwise specified		9 Months Ended			12 Months Ended	3 Months Ended
	Sep. 30, 2013	Sep. 30, 2013 Otter Tail Power Company Great River Energy Capacity and energy purchase agreements MW	Sep. 30, 2013 Otter Tail Power Company Great River Energy Capacity and energy purchase agreements Ashtabula Wind Energy Center	Sep. 30, 2013 Otter Tail Power Company Construction and Other Purchase Commitments	Dec. 31, 2012 Otter Tail Power Company Construction and Other Purchase Commitments	Jun. 30, 2013 Otter Tail Power Company Capacity and Energy Requirements Property	Dec. 31, 2012 Otter Tail Power Company Capacity and Energy Requirements	Sep. 30, 2013 Otter Tail Power Company Coal Purchase Commitments	Dec. 31, 2012 Otter Tail Power Company Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Amount				$ 127.5	$ 79.4
Additional coal purchase commitments for 2013								3.9
Additional coal purchase commitments for 2014								3.2
Additional coal purchase commitments for 2015								4.2
Amount for purchase commitments							170.1		797.0
Term of agreement						25 years
Number of wind turbines						39
Purchase of energy capacity from June 1, 2017 through May 31, 2019		25
Purchase of energy capacity from June 1, 2019 through May 31, 2021		50
Increased estimated commitment			193.4
Loss contingency, range of possible loss, maximum	$ 2.0

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

2. Segment Information

The Company’s businesses have been classified into four 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 four segments are: Electric, Manufacturing, Construction and Plastics.

The chart below indicates the companies included in each segment.

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 Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Additionally, the electric segment included Otter Tail Energy Services Company (OTESCO), which provided technical and engineering services. OTESCO ceased operations in July 2013. OTESCO has not recorded any operating revenues, expenses or net income in 2013.

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping and fabrication, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Illinois and Minnesota and sell products primarily in the United States.

Construction consists of businesses involved in 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 at plants in North Dakota and Arizona. The PVC pipe is sold primarily 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.

No single customer accounted for over 10% of the Company’s consolidated revenues in 2012. All of the Company’s long-lived assets are within the United States.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
United States of America		97.7	%		97.7	%		97.7	%		97.7	%
Mexico		1.5	%		1.1	%		1.3	%		1.0	%
Canada		0.7	%		1.1	%		0.9	%		1.2	%
All Other Countries (none greater than 0.08%)		0.1	%		0.1	%		0.1	%		0.1	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three and nine months ended September 30, 2013 and 2012 and total assets by business segment as of September 30, 2013 and December 31, 2012 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	86,283		$	88,564		$	270,155		$	257,530
Manufacturing		49,323			46,618			152,282			159,091
Construction		47,509			37,931			108,928			111,482
Plastics		46,659			42,217			128,820			118,582
Intersegment Eliminations		(6	)		(14	)		(74	)		(78	)
Total	$	229,768		$	215,316		$	660,111		$	646,607

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Electric	$	3,960	$	4,880	$	13,032	$	14,493
Manufacturing		816		891		2,447		2,723
Construction		128		305		345		868
Plastics		249		342		753		1,034
Corporate and Intersegment Eliminations		1,421		1,486		3,854		5,852
Total	$	6,574	$	7,904	$	20,431	$	24,970

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	2,565		$	2,995		$	5,830		$	3,817
Manufacturing		1,124			1,288			4,715			5,286
Construction		1,193			(879	)		490			(4,819	)
Plastics		2,278			2,216			7,508			7,113
Corporate		(2,027	)		(6,405	)		(5,430	)		(11,197	)
Total	$	5,133		$	(785	)	$	13,113		$	200

Earnings (Loss) Available for Common Shares

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Electric	$	8,787		$	10,206		$	24,301		$	26,413
Manufacturing		2,970			1,914			8,333			7,880
Construction		1,784			(1,325	)		716			(7,252	)
Plastics		3,403			3,309			11,215			10,629
Corporate		(2,118	)		(9,486	)		(7,514	)		(16,344	)
Discontinued Operations		312			(2,928	)		638			(30,117	)
Total	$	15,138		$	1,690		$	37,689		$	(8,791	)

Identifiable Assets

	September 30,		December 31,
(in thousands)	2013		2012
Electric	$	1,280,682	$	1,226,145
Manufacturing		122,942		114,933
Construction		59,904		50,696
Plastics		83,254		78,855
Corporate		111,060		112,616
Discontinued Operations		432		19,092
Total	$	1,658,274	$	1,602,337

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Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 7) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Goodwill [Line Items]
Gross Balance December 31, 2012	$ 38,971
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2012	38,971
Adjustments to Goodwill in 2013
Balance (net of impairments) September 30, 2013	38,971
Manufacturing
Goodwill [Line Items]
Gross Balance December 31, 2012	12,186
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2012	12,186
Adjustments to Goodwill in 2013
Balance (net of impairments) September 30, 2013	12,186
Construction
Goodwill [Line Items]
Gross Balance December 31, 2012	7,483
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2012	7,483
Adjustments to Goodwill in 2013
Balance (net of impairments) September 30, 2013	7,483
Plastics
Goodwill [Line Items]
Gross Balance December 31, 2012	19,302
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2012	19,302
Adjustments to Goodwill in 2013
Balance (net of impairments) September 30, 2013	$ 19,302

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Share-Based Payments (Tables)

9 Months Ended

Sep. 30, 2013

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Schedule of Stock Incentive Awards granted to non-employee directors, executive officers and key employees

Award	Shares/Units Granted	Grant-Date Fair Value per Award	Vesting
Restricted Stock Granted to Nonemployee Directors	16,000	$31.03	25% per year through April 8, 2017
Restricted Stock Granted to Executive Officers	17,000	$31.03	25% per year through April 8, 2017
Stock Performance Awards Granted to Executive Officers	50,200	$37.51	December 31, 2015
Restricted Stock Units Granted to Employees	15,150	$25.30	100% on April 8, 2017

Schedule of compensation expense under stock-based payment programs

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Employee Stock Purchase Plan (15% discount)	$	39	$	31	$	98	$	119
Restricted Stock Granted to Directors		119		139		488		413
Restricted Stock Granted to Employees		111		87		315		232
Restricted Stock Units Granted to Employees		61		60		215		165
Stock Performance Awards Granted to Executive Officers		347		146		2,148		439
Totals	$	677	$	463	$	3,264	$	1,368

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Income Tax Expense - Continuing Operations (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Schedule of income from continuing operations before income taxes and income tax expense

	Three Months Ended  September 30,						Nine Months Ended  September 30,
(in thousands)	2013			2012			2013			2012
Income Before Income Taxes – Continuing Operations	$	19,959		$	4,016		$	50,677		$	22,077
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,784			1,566			19,764			8,610
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,162	)		(1,239	)		(4,592	)		(5,057	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			--			(676	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(297	)		(651	)		(668	)
Corporate Owned Life Insurance		(227	)		(118	)		(621	)		(503	)
Medicare Part D Subsidy		--			(196	)		--			(587	)
Employee Stock Ownership Plan Dividend Deduction		(190	)		(190	)		(568	)		(571	)
Research and Development Tax Credits from 2012		(520	)		--			(520	)		--
Deferred Tax Asset reduction – North Dakota, due to Tax Rate Decrease		--			--			365			--
Other Items - Net		(340	)		(311	)		(64	)		(348	)
Income Tax Expense (Benefit) – Continuing Operations	$	5,133		$	(785	)	$	13,113		$	200
Effective Income Tax Rate – Continuing Operations		25.7	%		(19.5	)%		25.9	%		0.9	%

Schedule of activity related to unrecognized tax benefits

(in thousands)	2013
Balance on January 1	$	4,436
Increases Related to Tax Positions for Prior Years		97
Uncertain Positions Adjusted During Year		(288	)
Balance on September 30	$	4,245

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Share-Based Payments (Detail Textuals 1) (USD $)	0 Months Ended
	Apr. 08, 2013
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum aggregate common shares award	100,400
Shares/Units Granted	50,200
Average projected payout percentage	118.70%
Number of payout shares	57,587
Fair value of payout shares	$ 1,883,000
Issue price of payout shares	$ 32.70
Grant date fair value per share	$ 37.51
Stock Performance Awards | Executive Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	200.00%
Stock Performance Awards | Executive Officers | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	0.00%
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for restricted stock units (in years)	4 years

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Summary of Significant Accounting Policies - Accounts receivable retained by customers pending project completion (Details 3) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Accounts Receivable Retained by Customers	$ 6,989	$ 12,227

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Share-Based Payments (Detail Textuals) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013 Program
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Number of share-based payment programs	5
Unrecognized compensation expense related to stock-based compensation	$ 5.5
Weighted-average period of amortization	2 years 1 month 6 days

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Forward Contracts Classified as Derivatives - Effect of marking to market forward contracts for purchase and sale of electricity and location and fair value amounts of related derivatives (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$ 17,754	$ 25,499
Regulatory Assets - Long-Term	131,921	134,755
Current Liability - Marked-to-Market Loss	(12,707)	(18,234)
Regulatory Liability - Current	734	559
Regulatory Liability - Long-Term	70,446	68,835
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Current Asset - Marked-to-Market Gain	316	502
Total Assets	13,023	18,501
Current Liability - Marked-to-Market Loss	(12,707)	(18,234)
Total Liabilities	(13,023)	(18,452)
Net Fair Value of Marked-to-Market Energy Contracts		49	(41)	894
Forward Electricity Contracts | Deferred Marked-to-Market Losses
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	4,363	7,949
Regulatory Assets - Long-Term	8,344	10,050
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current		(8)
Regulatory Liability - Long-Term	$ (316)	$ (210)

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Segment Information - Information on continuing operations for business segments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating Revenue	$ 229,768	$ 215,316	$ 660,111	$ 646,607
Interest Charges	6,574	7,904	20,431	24,970
Income Taxes	5,133	(785)	13,113	200
Earnings (Loss) Available for Common Shares	15,138	1,690	37,689	(8,791)
Identifiable Assets	1,658,274		1,658,274		1,602,337
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(6)	(14)	(74)	(78)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	1,421	1,486	3,854	5,852
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(2,027)	(6,405)	(5,430)	(11,197)
Earnings (Loss) Available for Common Shares	(2,118)	(9,486)	(7,514)	(16,344)
Identifiable Assets	111,060		111,060		112,616
Discontinued Operations
Segment Reporting Information [Line Items]
Earnings (Loss) Available for Common Shares	312	(2,928)	638	(30,117)
Identifiable Assets	432		432		19,092
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	86,283	88,564	270,155	257,530
Interest Charges	3,960	4,880	13,032	14,493
Income Taxes	2,565	2,995	5,830	3,817
Earnings (Loss) Available for Common Shares	8,787	10,206	24,301	26,413
Identifiable Assets	1,280,682		1,280,682		1,226,145
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	49,323	46,618	152,282	159,091
Interest Charges	816	891	2,447	2,723
Income Taxes	1,124	1,288	4,715	5,286
Earnings (Loss) Available for Common Shares	2,970	1,914	8,333	7,880
Identifiable Assets	122,942		122,942		114,933
Construction | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	47,509	37,931	108,928	111,482
Interest Charges	128	305	345	868
Income Taxes	1,193	(879)	490	(4,819)
Earnings (Loss) Available for Common Shares	1,784	(1,325)	716	(7,252)
Identifiable Assets	59,904		59,904		50,696
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	46,659	42,217	128,820	118,582
Interest Charges	249	342	753	1,034
Income Taxes	2,278	2,216	7,508	7,113
Earnings (Loss) Available for Common Shares	3,403	3,309	11,215	10,629
Identifiable Assets	$ 83,254		$ 83,254		$ 78,855

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Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 11) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$ 25,133	[1]	$ 5,979	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$ 5,172	[2]		[2]

[1] Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.

[2] Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

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Consolidated Balance Sheets (Parentheticals) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Common Shares, Par Value	$ 5	$ 5
Common Shares, Authorized	50,000,000	50,000,000
Common Shares, Outstanding	36,269,363	36,168,368
Cumulative Preferred Shares
Cumulative Shares, Authorized	1,500,000	1,500,000
Cumulative Shares, Without Par Value
Cumulative Shares, Outstanding		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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Share-Based Payments

9 Months Ended

Sep. 30, 2013

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 8, 2013 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 (the Stock Incentive Plan):

Award	Shares/Units Granted	Grant-Date Fair Value per Award	Vesting
Restricted Stock Granted to Nonemployee Directors	16,000	$31.03	25% per year through April 8, 2017
Restricted Stock Granted to Executive Officers	17,000	$31.03	25% per year through April 8, 2017
Stock Performance Awards Granted to Executive Officers	50,200	$37.51	December 31, 2015
Restricted Stock Units Granted to Employees	15,150	$25.30	100% on April 8, 2017

The restricted shares granted to the Company’s nonemployee directors and executive officers are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement. 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 100,400 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, 2013 through December 31, 2015. The aggregate target share award is 50,200 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 average projected payout percentage rendered by the simulation was 118.7% of target, which would result in a payout of 57,587 shares with a current fair value of $1,883,000 or $32.70 per share, which equates to $37.51 per targeted share award. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC Topic 718,Compensation—Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

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

As of September 30, 2013 the remaining unrecognized compensation expense related to stock-based compensation was approximately $5.5 million (before income taxes) which will be amortized over a weighted-average period of 2.1 years.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Employee Stock Purchase Plan (15% discount)	$	39	$	31	$	98	$	119
Restricted Stock Granted to Directors		119		139		488		413
Restricted Stock Granted to Employees		111		87		315		232
Restricted Stock Units Granted to Employees		61		60		215		165
Stock Performance Awards Granted to Executive Officers		347		146		2,148		439
Totals	$	677	$	463	$	3,264	$	1,368

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Consolidated Statements of Income (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]
Income tax expense (benefit) on Income (Loss) from discontinued operation	$ 39	$ (75)	$ (35)	$ 3,431
Income tax (benefit) on impairment loss on discontinued operations	0	0	0	(18,114)
Income Tax (Benefit) Expense on Disposition	$ 0	$ 0	$ 6	$ (169)

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Forward Contracts Classified as Derivatives - Information on OTP's credit risk exposure on delivered and marked-to-market forward contracts (Details 3) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013 Counterparty	Dec. 31, 2012 Counterparty
Net Credit Risk on Forward Energy Contracts
Derivative [Line Items]
Exposure	$ 335	$ 580
Counterparties	2	6
Net Credit Risk to Single Largest Counterparty
Derivative [Line Items]
Exposure	$ 321	$ 285

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets
Cash and Cash Equivalents	$ 59,117	$ 52,362
Accounts Receivable:
Trade - Net	98,164	91,170
Other	15,215	7,684
Inventories	72,658	69,336
Deferred Income Taxes	19,696	30,964
Unbilled Revenues	12,304	15,701
Costs and Estimated Earnings in Excess of Billings	4,858	3,663
Regulatory Assets	17,754	25,499
Other	10,167	8,161
Assets of Discontinued Operations	432	19,092
Total Current Assets	310,365	323,632
Investments	9,325	9,471
Other Assets	27,696	26,222
Goodwill	38,971	38,971
Other Intangibles - Net	13,572	14,305
Deferred Debits
Unamortized Debt Expense	4,341	5,529
Regulatory Assets	131,921	134,755
Total Deferred Debits	136,262	140,284
Plant
Electric Plant in Service	1,438,543	1,423,303
Nonelectric Operations	194,636	186,094
Construction Work in Progress	159,202	77,890
Total Gross Plant	1,792,381	1,687,287
Less Accumulated Depreciation and Amortization	670,298	637,835
Net Plant	1,122,083	1,049,452
Total Assets	1,658,274	1,602,337
Current Liabilities
Short-Term Debt	40,335
Current Maturities of Long-Term Debt	185	176
Accounts Payable	109,604	88,406
Accrued Salaries and Wages	18,122	20,571
Billings In Excess Of Costs and Estimated Earnings	16,202	16,204
Accrued Taxes	10,609	12,047
Derivative Liabilities	12,707	18,234
Other Accrued Liabilities	7,734	6,334
Liabilities of Discontinued Operations	4,080	11,156
Total Current Liabilities	219,578	173,128
Pensions Benefit Liability	109,139	116,541
Other Postretirement Benefits Liability	59,477	58,883
Other Noncurrent Liabilities	25,746	22,244
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	177,248	171,787
Deferred Tax Credits	28,791	31,299
Regulatory Liabilities	70,446	68,835
Other	643	466
Total Deferred Credits	277,128	272,387
Capitalization
Long-Term Debt, Net of Current Maturities	437,306	421,680
Common Shares, Par Value $5 Per Share-Authorized, 50,000,000 Shares; Outstanding, 2013-36,269,363 Shares; 2012- 36,168,368 Shares	181,347	180,842
Premium on Common Shares	255,167	253,296
Retained Earnings	97,569	92,221
Accumulated Other Comprehensive Loss	(4,183)	(4,385)
Total Common Equity	529,900	521,974
Total Capitalization	967,206	959,154
Total Liabilities and Equity	1,658,274	1,602,337
Cumulative Preferred Shares
Capitalization
Cumulative Shares		15,500
Cumulative Preference Shares
Capitalization
Cumulative Shares

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Segment Information (Detail Textuals)	9 Months Ended
	Sep. 30, 2013 Segment
Segment Reporting [Abstract]
Number of reportable segments	4

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Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	$ 1,359		$ 1,271		$ 4,195		$ 3,813
Interest Cost on Projected Benefit Obligation	3,021		3,116		9,093		9,349
Expected Return on Assets	(3,627)		(3,608)		(10,891)		(10,823)
Amortization of Prior-Service Cost:
From Regulatory Asset	84		100		250		299
From Other Comprehensive Income	3	[1]	3	[1]	7	[1]	8	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	1,624		1,229		4,950		3,683
From Other Comprehensive Income	42	[1]	31	[1]	132	[1]	97	[1]
Net Periodic Pension Cost	2,506		2,142		7,736		6,426
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	12		11		38		34
Interest Cost on Projected Benefit Obligation	352		370		1,056		1,109
Amortization of Prior-Service Cost:
From Regulatory Asset	6		5		16		16
From Other Comprehensive Income	13	[2]	13	[2]	39	[2]	39	[2]
Amortization of Net Actuarial Loss:
From Regulatory Asset	52		39		156		116
From Other Comprehensive Income	79	[3]	43	[3]	235	[3]	129	[3]
Net Periodic Pension Cost	514		481		1,540		1,443
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	184		386		1,066		1,158
Interest Cost on Projected Benefit Obligation	318		644		1,538		1,931
Amortization of Transition Obligation:
From Regulatory Asset			182				546
From Other Comprehensive Income		[1]	5	[1]		[1]	15	[1]
Amortization of Prior-Service Cost:
From Regulatory Asset	52		51		154		154
From Other Comprehensive Income	2	[1]	2	[1]	4	[1]	4	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	(478)		160		18		481
From Other Comprehensive Income	(12)	[1]	4	[1]		[1]	13	[1]
Net Periodic Pension Cost	66		1,434		2,780		4,302
Effect of Medicare Part D Subsidy	$ (227)		$ (509)		$ (1,355)		$ (1,529)

[1] Corporate cost included in Other Nonelectric Expenses.

[2] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 5 $ 5 $ 15 $ 15 Other Nonelectric Expenses 8 8 24 24.

[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 49 $ 36 $ 145 $ 108 Other Nonelectric Expenses 30 7 90 21.

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Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Short-term borrowings	$ 40,335
Long-Term Debt	437,494	421,860
Less: Current Maturities	185	176
Unamortized Debt Discount	3	4
Total Long-Term Debt	437,306	421,680
Total Short-Term and Long-Term Debt (with current maturities)	477,826	421,856
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015
Debt Instrument [Line Items]
Long-Term Debt	40,900
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
Senior Unsecured Notes 4.63%, 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
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	1,594	1,725
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
Debt Instrument [Line Items]
Long-Term Debt		5,065
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
Debt Instrument [Line Items]
Long-Term Debt		20,070
Otter Tail Power Company
Debt Instrument [Line Items]
Short-term borrowings	40,335
Long-Term Debt	335,900	320,135
Less: Current Maturities
Unamortized Debt Discount
Total Long-Term Debt	335,900	320,135
Total Short-Term and Long-Term Debt (with current maturities)	376,235	320,135
Otter Tail Power Company | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015
Debt Instrument [Line Items]
Long-Term Debt	40,900
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 | Senior Unsecured Notes 4.63%, 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 | 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
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		5,065
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		20,070
Otter Tail Corporation
Debt Instrument [Line Items]
Short-term borrowings
Long-Term Debt	101,594	101,725
Less: Current Maturities	185	176
Unamortized Debt Discount	3	4
Total Long-Term Debt	101,406	101,545
Total Short-Term and Long-Term Debt (with current maturities)	101,591	101,721
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	100,000	100,000
Otter Tail Corporation | Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt	$ 1,594	$ 1,725

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Short-Term and Long-Term Borrowings (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Schedule of lines of credit

(in thousands)	Line Limit		In Use on September 30, 2013		Restricted due to Outstanding Letters of Credit		Available on September 30, 2013		Available on December 31, 2012
Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	680	$	149,320	$	149,267
OTP Credit Agreement		170,000		40,335		1,189		128,476		166,811
Total	$	320,000	$	40,335	$	1,869	$	277,796	$	316,078

Schedule of short-term and long-term debt outstanding

September 30, 2013 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	40,335	$	--	$	--	$	40,335
Long-Term Debt:
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	$	40,900					$	40,900
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
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
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 September 30, 2013		--				1,594		1,594
Total	$	335,900			$	101,594	$	437,494
Less: Current Maturities		--				185		185
Unamortized Debt Discount		--				3		3
Total Long-Term Debt	$	335,900			$	101,406	$	437,306
Total Short-Term and Long-Term Debt (with current maturities)	$	376,235	$	--	$	101,591	$	477,826

December 31, 2012 (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		5,065						5,065
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		20,070						20,070
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, 2012						1,725		1,725
Total	$	320,135			$	101,725	$	421,860
Less: Current Maturities		--				176		176
Unamortized Debt Discount		--				4		4
Total Long-Term Debt	$	320,135			$	101,545	$	421,680
Total Short-Term and Long-Term Debt (with current maturities)	$	320,135	$	--	$	101,721	$	421,856

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Schedule of revenues recorded under the percentage-of-completion method

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Percentage-of-Completion Revenues	20.6	%	17.1	%	16.4	%	16.8	%

Schedule of costs incurred and billings and estimated earnings

	September 30,			December 31,
(in thousands)	2013			2012
Costs Incurred on Uncompleted Contracts	$	341,649		$	307,085
Less Billings to Date		(358,026	)		(321,388	)
Plus Estimated Earnings Recognized		5,033			1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

Schedule of percentage-of-completion balance sheet amounts

	September 30,			December 31,
(in thousands)	2013			2012
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	4,858		$	3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(16,202	)		(16,204	)
NetBillings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

Schedule of receivables from customers being retained pending project completion

	September 30,		December 31,
(in thousands)	2013		2012
Accounts Receivable Retained by Customers	$	6,989	$	12,227

Schedule of assets and liabilities that are measured at fair value on a recurring basis

September 30, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	316
Forward Gasoline Purchase Contracts				66
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,608
U.S. Government Debt Securities – Held by Captive Insurance Company				1,278
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		722
Equity Securities - Nonqualified Retirement Savings Plan		130
Total Assets	$	962	$	8,952	$	316
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	12,707
Total Liabilities	$	--	$	--	$	12,707

December 31, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	292	$	210
Forward Gasoline Purchase Contracts				136
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				7,620
U.S. Government Debt Securities – Held by Captive Insurance Company				1,305
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		357
Equity Securities - Nonqualified Retirement Savings Plan		125
Total Assets	$	2,092	$	9,353	$	210
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	242	$	17,992
Total Liabilities	$	--	$	242	$	17,992

Schedule of derivative asset and liability fair valuations

	Nine Months Ended
	September 30,
(in thousands)	2013			2012
Forward Energy Contracts  - Fair Values Beginning of Period	$	(17,782	)	$	--
Transfers into Level 3 from Level 2		--			(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		5,066			3,771
Changes in Fair Value of Contracts Entered into in Prior Periods		325			(4,517	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(12,391	)		(16,630	)
Net Increase in Value of Open Contracts Entered into in Current Period		--			22
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(12,391	)	$	(16,608	)

Schedule of inventories

	September 30,		December 31,
(in thousands)	2013		2012
Finished Goods	$	19,682	$	21,893
Work in Process		10,636		8,800
Raw Material, Fuel and Supplies		42,340		38,643
Total Inventories	$	72,658	$	69,336

Schedule of changes to goodwill by business segment

(in thousands)	Gross Balance December 31, 2012		Accumulated Impairments		Balance (net of impairments) December 31, 2012		Adjustments to Goodwill in 2013		Balance (net of impairments) September 30, 2013
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Construction		7,483		--		7,483		--		7,483
Plastics		19,302		--		19,302		--		19,302
Total	$	38,971	$	--	$	38,971	$	--	$	38,971

Schedule of components of intangible assets

September 30, 2013 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,722	$	12,089		15 – 25 years
Other Intangible Assets Including Contracts		825		442		383		5 – 30 years
Total	$	17,636	$	5,164	$	12,472
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2012(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,085	$	12,726		15 – 25 years
Other Intangible Assets Including Contracts		1,092		613		479		5 – 30 years
Total	$	17,903	$	4,698	$	13,205
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

Schedule of amortization expense for intangible assets

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Amortization Expense – Intangible Assets	$	245	$	244	$	733	$	737

Schedule of estimated annual amortization expense for Intangible Assets

(in thousands)	2013		2014		2015		2016		2017
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	977	$	945	$	849

Schedule of supplemental disclosure of cash flow information

	As of September 30,
(in thousands)	2013		2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	25,133	$	5,979
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	5,172	$	--
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. 2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

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Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 10) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013
Accounting Policies [Abstract]
2013	$ 977
2014	977
2015	977
2016	945
2017	$ 849

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Short-Term and Long-Term Borrowings (Detail textuals) (USD $) In Millions, unless otherwise specified	9 Months Ended				0 Months Ended	1 Months Ended
	Sep. 30, 2013 Cumulative Preferred Shares	Mar. 01, 2013 Cumulative Preferred Shares	Sep. 30, 2013 Maximum	Sep. 30, 2013 Minimum	Mar. 01, 2013 Otter Tail Power Company J P Morgan Chase Bank Unsecured Term Loan	Mar. 31, 2013 Otter Tail Power Company J P Morgan Chase Bank Unsecured Term Loan	Mar. 31, 2013 Otter Tail Power Company J P Morgan Chase Bank Unsecured Term Loan 4.65 % Grant County, South Dakota and 4.85 % Mercer County, North Dakota Pollution Control Refunding Revenue Bonds	Mar. 31, 2013 Otter Tail Power Company J P Morgan Chase Bank Unsecured Term Loan Intercompany Note
Debt Instrument [Line Items]
Description of variable rate basis					LIBOR
Basis spread on variable rate					0.875%
Term loan borrowed for funding						$ 40.9	$ 25.1	$ 15.7
Redemption amount of preferred stock equal to proceeds from term loan		15.7
Preferred stock redemption, call premiums	$ 0.2
Ratio of interest bearing debt to total capitalization			1.00	0.60

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Regulatory Assets and Liabilities (Detail Textuals)	9 Months Ended
	Sep. 30, 2013
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Long Term, Remaining Recovery/Refund Period	228 months
Otter Tail Power Company | 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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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Outstanding stock options with exercise prices greater than average market price excluded from calculation of diluted earnings per share (Details 1) (Stock Options, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options Outstanding		92,497		92,497
Range of Exercise Prices, Lower Range		$ 24.93		$ 24.93
Range of Exercise Prices, Upper Range		$ 27.245		$ 27.245

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Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 5) (Forward Energy Contracts, Level 3, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Forward Energy Contracts | Level 3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Energy Contracts - Fair Values Beginning of Period	$ (17,782)
Transfers into Level 3 from Level 2		(15,884)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	5,066	3,771
Changes in Fair Value of Contracts Entered into in Prior Periods	325	(4,517)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	(12,391)	(16,630)
Net Increase in Value of Open Contracts Entered into in Current Period		22
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$ (12,391)	$ (16,608)

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Summary of Significant Accounting Policies - Summary of costs incurred and billings and estimated earnings recognized on uncompleted contracts (Details 1) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$ 341,649	$ 307,085
Less Billings to Date	(358,026)	(321,388)
Plus Estimated Earnings Recognized	5,033	1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (11,344)	$ (12,541)

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Summary of Significant Accounting Policies - Costs and estimated earnings in excess of billings that are included in consolidated balance sheets (Details 2) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$ 4,858	$ 3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(16,202)	(16,204)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (11,344)	$ (12,541)

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

9 Months Ended

Sep. 30, 2013

Stockholders Equity and Earnings Per Share [Abstract]

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

6. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share

Reconciliation of Common Shareholders’ Equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2012	$	180,842		$	253,296		$	92,221		$	(4,385	)	$	521,974
Common Stock Issuances, Net of Expenses		551			1,848									2,399
Common Stock Retirements and Forfeitures		(46	)		(177	)								(223	)
Net Income								38,202						38,202
Other Comprehensive Income											202			202
Tax Benefit – Stock Compensation					59									59
Employee Stock Incentive Plan Expense					313									313
Premium on Purchase of Stock for Employee Purchase Plan					(258	)								(258	)
Cumulative Preferred Dividends								(427	)					(427	)
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares					86			(86	)					--
Common Dividends								(32,341	)					(32,341	)
Balance, September 30, 2013	$	181,347		$	255,167		$	97,569		$	(4,183	)	$	529,900

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2012 through September 30, 2013:

Common Shares Outstanding, December 31, 2012	36,168,368
Issuances:
Stock Options Exercised	55,109
Vesting of Restricted Stock Units	17,535
Restricted Stock Issued to Employees	17,000
Restricted Stock Issued to Directors	16,000
Director’s Compensation	4,535
Retirements:
Shares Withheld for Individual Income Tax Requirements	(7,184	)
Forfeiture of Unvested Restricted Stock	(2,000	)
Common Shares Outstanding, September 30, 2013	36,269,363

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is earnings available for common shares with no adjustments for the three and nine month periods ended September 30, 2013 and 2012. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting outstanding shares for the following: (1) all potentially dilutive stock options, (2) underlying shares related to nonvested restricted stock units granted to employees, (3) nonvested restricted shares, (4) shares expected to be awarded for stock performance awards granted to executive officers, and (5) shares expected to be issued under the deferred compensation program for directors. The adjustments to the denominators used to calculate basic and diluted earnings per share resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in each of the three and nine month periods ended September 30, 2013 and 2012.

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the three and nine month periods ended September 30, 2013 and 2012:

	Options Outstanding	Range of Exercise Prices
Three Months Ended September 30, 2013	--	--
Three Months Ended September 30, 2012	92,497	$24.93 – $27.245
Nine Months Ended September 30, 2013	--	--
Nine Months Ended September 30, 2012	92,497	$24.93 – $27.245

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Forward Contracts Classified as Derivatives (Detail Textuals) (Otter Tail Power Company, Investment grade credit ratings)	Sep. 30, 2013 Counterparty
Otter Tail Power Company | Investment grade credit ratings
Derivative [Line Items]
Counterparties	2

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Discontinued Operations - Warranty Reserves (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Discontinued Operations and Disposal Groups [Abstract]
Warranty Reserve Balance, December 31, 2012	$ 5,027
Provision for Warranties Used During the Year	120
Less Settlements Made During the Year	(675)
Decrease in Warranty Estimates for Prior Years	(1,112)
Warranty Reserve Balance, September 30, 2013	$ 3,360

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Pension Plan and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Pension Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	1,359		$	1,271		$	4,195		$	3,813
Interest Cost on Projected Benefit Obligation		3,021			3,116			9,093			9,349
Expected Return on Assets		(3,627	)		(3,608	)		(10,891	)		(10,823	)
Amortization of Prior-Service Cost:
From Regulatory Asset		84			100			250			299
From Other Comprehensive Income1		3			3			7			8
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,624			1,229			4,950			3,683
From Other Comprehensive Income1		42			31			132			97
Net Periodic Pension Cost	$	2,506		$	2,142		$	7,736		$	6,426
1Corporate cost included in Other Nonelectric Expenses.

Executive Survivor and Supplemental Retirement Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2013		2012		2013		2012
Service Cost—Benefit Earned During the Period	$	12	$	11	$	38	$	34
Interest Cost on Projected Benefit Obligation		352		370		1,056		1,109
Amortization of Prior-Service Cost:
From Regulatory Asset		6		5		16		16
From Other Comprehensive Income1		13		13		39		39
Amortization of Net Actuarial Loss:
From Regulatory Asset		52		39		156		116
From Other Comprehensive Income2		79		43		235		129
Net Periodic Pension Cost	$	514	$	481	$	1,540	$	1,443
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5	$	5	$	15	$	15
Other Nonelectric Expenses		8		8		24		24
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	49	$	36	$	145	$	108
Other Nonelectric Expenses		30		7		90		21

Postretirement Benefits

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Service Cost—Benefit Earned During the Period	$	184		$	386		$	1,066		$	1,158
Interest Cost on Projected Benefit Obligation		318			644			1,538			1,931
Amortization of Transition Obligation:
From Regulatory Asset		--			182			--			546
From Other Comprehensive Income1		--			5			--			15
Amortization of Prior-Service Cost:
From Regulatory Asset		52			51			154			154
From Other Comprehensive Income1		2			2			4			4
Amortization of Net Actuarial Loss:
From Regulatory Asset		(478	)		160			18			481
From Other Comprehensive Income1		(12	)		4			--			13
Net Periodic Postretirement Benefit Cost	$	66		$	1,434		$	2,780		$	4,302
Effect of Medicare Part D Subsidy	$	(227	)	$	(509	)	$	(1,355	)	$	(1,529	)
1Corporate cost included in Other Nonelectric Expenses.

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Summary of Significant Accounting Policies - Components of intangible assets (Details 8) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Amortizable Intangible Assets:
Gross Carrying Amount	$ 17,636	$ 17,903
Accumulated Amortization	5,164	4,698
Net Carrying Amount	12,472	13,205
Trade Name
Indefinite-lived Intangible Assets:
Indefinite-lived Intangible Assets, Gross Carrying amount	1,100	1,100
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	4,722	4,085
Net Carrying Amount	12,089	12,726
Customer Relationships | Maximum
Amortizable Intangible Assets:
Amortization Periods	25 years	25 years
Customer Relationships | Minimum
Amortizable Intangible Assets:
Amortization Periods	15 years	15 years
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Gross Carrying Amount	825	1,092
Accumulated Amortization	442	613
Net Carrying Amount	$ 383	$ 479
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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2012 OTP had commitments under contracts in connection with construction programs aggregating approximately $79.4 million. At September 30, 2013 OTP had commitments under contracts in connection with construction programs aggregating approximately $127.5 million. The increase in construction commitments from December 31, 2012 to September 30, 2013 is mainly for OTP’s share of commitments related to the construction of a new air quality control system at Big Stone Plant.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

As of December 31, 2012 OTP had commitments for the purchase of capacity and energy requirements under agreements extending through 2032 totaling $170.1 million. In the second quarter of 2013, OTP entered into a 25-year power purchase agreement (PPA) with Ashtabula Wind III, LLC for the purchase of wind generated electricity from the LLC’s 39 wind turbines located in Barnes County, North Dakota. At its regular agenda meeting on August 22, 2013 the MPUC provided an affirmative determination that OTP’s execution of this agreement is reasonable, in the public interest, and that costs incurred under this agreement to serve OTP’s Minnesota customers will be recoverable. On October 1, 2013 OTP began accepting delivery of energy under the PPA. In September of 2013, OTP entered into an agreement with Great River Energy for the purchase of 25 megawatts (MW) of capacity from June 1, 2017 through May 31, 2019 and 50 MW of capacity from June 1, 2019 through May 31, 2021 to meet OTP’s future capacity requirements. OTP’s commitments under the Ashtabula Wind III, LLC PPA and the Great River Energy capacity purchase agreement have increased OTP’s total estimated commitments under capacity and energy purchase agreements by $193.4 million.

As of December 31, 2012 OTP had contracts providing for the purchase and delivery of a significant portion of its then current coal requirements totaling $797.0 million. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2014, 2016 and 2040. In February, May and September of 2013, OTP entered into agreements for the purchase of additional coal to meet a portion of Big Stone Plant’s remaining coal requirements for 2013 and 2014. In September of 2013, OTP entered into an agreement for the purchase of additional coal to meet a portion of Hoot Lake Plant’s coal requirements for the remainder of 2013 and 2015. OTP’s share of the additional commitments subsequent to September 30, 2013 total $3.9 million for 2013, $3.2 million for 2014 and $4.2 million for 2015.

Contingencies

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, environmental remediation, litigation matters and the resolution of matters related to open tax years. Should all of these known items result in liabilities being incurred, the loss could be as high as $2.0 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, such as possible warranty claims on products that are beyond their warranty period but where a customer may claim to have provided notice of a defect while the product was under warranty. If these claims were to occur, it could result in the Company incurring a significantly greater liability than it anticipates.

Other

The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2013 will not be material.

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Short-Term and Long-Term Borrowings - Status of lines of credit (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]
Line Limit	$ 320,000
In Use	40,335
Restricted due to Outstanding Letters of Credit	1,869
Available	277,796	316,078
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use
Restricted due to Outstanding Letters of Credit	680
Available	149,320	149,267
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	40,335
Restricted due to Outstanding Letters of Credit	1,189
Available	$ 128,476	$ 166,811

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Forward Contracts Classified as Derivatives

9 Months Ended

Sep. 30, 2013

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.

As of September 30, 2013 OTP had no unrealized mark-to-market gains or losses in its income statement related to forward contracts for the purchase and sale of electricity. 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 3 of the fair value hierarchy set forth in ASC 820.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of September 30, 2013 and December 31, 2012, and the change in the Company’s consolidated balance sheet position from December 31, 2012 to September 30, 2013 and December 31, 2011 to September 30, 2012:

(in thousands)	September 30, 2013			December 31, 2012
Current Asset – Marked-to-Market Gain	$	316		$	502
Regulatory Asset – Current Deferred Marked-to-Market Loss		4,363			7,949
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		8,344			10,050
Total Assets		13,023			18,501
Current Liability – Marked-to-Market Loss		(12,707	)		(18,234	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(8	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(316	)		(210	)
Total Liabilities		(13,023	)		(18,452	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	49

(in thousands)	Year-to-Date September 30, 2013			Year-to-Date September 30, 2012
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	49		$	894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(49	)		(781	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--			(33	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			80
Changes in Fair Value of Contracts Entered into in Current Period		--			(121	)
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	(41	)

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013		2012			2013		2012
Net Gains (Losses) on Forward Electric Energy Contracts	$	1	$	(274	)	$	255	$	(130	)

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 September 30, 2013 and December 31, 2012:

	September 30, 2013				December 31, 2012
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	335		2	$	580		6
Net Credit Risk to Single Largest Counterparty	$	321			$	285

OTP had a net credit risk exposure to two counterparties with investment grade credit ratings. OTP had no exposure at September 30, 2013 or December 31, 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 credit risk exposures include net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains on forward contracts for the purchase of gasoline scheduled for settlement subsequent to September 30, 2013. Individual counterparty exposures are offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amount of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of September 30, 2013 and December 31, 2012 are indicated in the following table:

(in thousands)	September 30, 2013			December 31, 2012
Derivative assets subject to legally enforceable netting arrangements	$	382		$	638
Derivative liabilities subject to legally enforceable netting arrangements		(12,707	)		(18,234	)
Net balance subject to legally enforceable netting arrangements	$	(12,325	)	$	(17,596	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2013 and December 31, 2012:

Current Liability – Marked-to-Market Loss  (in thousands)	September 30, 2013			December 31, 2012
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	2,176
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		12,707			16,058
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			--
Total Current Liability – Marked-to-Market Loss	$	12,707		$	18,234
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	$	12,707		$	16,058
Offsetting Gains with Counterparties under Master Netting Agreements		(316	)		(416	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	12,391		$	15,642

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flows from Operating Activities
Net Income (Loss)	$ 38,202	$ (8,240)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net (Gain) Loss from Sale of Discontinued Operations	(210)	3,544
Net (Income) Loss from Discontinued Operations	(428)	26,573
Depreciation and Amortization	44,794	44,740
Asset Impairment Charge		432
Premium Paid for Early Retirement of Long-Term Debt		12,500
Deferred Tax Credits	(1,422)	(1,568)
Deferred Income Taxes	15,215	8,320
Change in Deferred Debits and Other Assets	9,817	16,493
Discretionary Contribution to Pension Plan	(10,000)	(10,000)
Change in Noncurrent Liabilities and Deferred Credits	7,318	8,029
Allowance for Equity-Other Funds Used During Construction	(1,462)	(518)
Change in Derivatives Net of Regulatory Deferral	120	752
Stock Compensation Expense - Equity Awards	1,116	930
Other-Net	813	4,257
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(9,775)	(16,536)
Change in Inventories	(3,323)	864
Change in Other Current Assets	(252)	6,268
Change in Payables and Other Current Liabilities	4,170	15,021
Change in Interest and Income Taxes Receivable/Payable	1,156	(11,203)
Net Cash Provided by Continuing Operations	95,849	100,658
Net Cash (Used in) Provided by Discontinued Operations	(2,499)	48,724
Net Cash Provided by Operating Activities	93,350	149,382
Cash Flows from Investing Activities
Capital Expenditures	(109,690)	(93,653)
Net Proceeds from Disposal of Noncurrent Assets	2,615	2,380
Net Increase in Other Investments	(680)	(1,393)
Net Cash Used in Investing Activities - Continuing Operations	(107,755)	(92,666)
Net Proceeds from Sale of Discontinued Operations	12,842	24,278
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations	505	(11,494)
Net Cash Used in Investing Activities	(94,408)	(79,882)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		3,535
Net Short-Term Borrowings	40,335	12,417
Proceeds from Issuance of Common Stock	1,496
Common Stock Issuance Expenses		(181)
Payments for Retirement of Capital Stock	(15,723)	(110)
Proceeds from Issuance of Long-Term Debt	40,900
Short-Term and Long-Term Debt Issuance Expenses	(126)	(14)
Payments for Retirement of Long-Term Debt	(25,266)	(50,183)
Premium Paid for Early Retirement of Long-Term Debt		(12,500)
Dividends Paid and Other Distributions	(33,027)	(33,033)
Net Cash Provided by (Used in) Financing Activities - Continuing Operations	8,589	(80,069)
Net Cash Used in Financing Activities - Discontinued Operations		(3,410)
Net Cash Provided by (Used in) Financing Activities	8,589	(83,479)
Net Change in Cash and Cash Equivalents - Discontinued Operations	(776)	(2,015)
Net Change in Cash and Cash Equivalents	6,755	(15,994)
Cash and Cash Equivalents at Beginning of Period	52,362	15,994
Cash and Cash Equivalents at End of Period	$ 59,117

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Discontinued Operations (Detail Textuals) (USD $)	9 Months Ended		0 Months Ended	1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Feb. 08, 2013 Disposal groups held for sale or disposed of by sale Waterfront equipment manufacturing company	Jun. 30, 2013 Disposal groups held for sale or disposed of by sale Waterfront equipment manufacturing company
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations	$ 12,842,000	$ 24,278,000	$ 13,000,000
Amount of working capital true up received				$ 2,400,000

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Rate and Regulatory Matters (Detail Textuals) (USD $)			9 Months Ended			1 Months Ended	3 Months Ended	9 Months Ended				1 Months Ended		9 Months Ended	1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended			1 Months Ended					9 Months Ended			1 Months Ended		0 Months Ended	3 Months Ended	1 Months Ended		9 Months Ended	3 Months Ended	1 Months Ended			19 Months Ended	12 Months Ended	0 Months Ended	1 Months Ended		3 Months Ended	1 Months Ended		3 Months Ended	13 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended			9 Months Ended		1 Months Ended	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Minnesota Public Utilities Commission Conservation Improvement Program	Sep. 30, 2013 Otter Tail Power Company Capacity Expansion 2020 Project Investor	Sep. 30, 2013 Otter Tail Power Company Fargo Project Capacity Expansion 2020 kV	Jun. 30, 2005 Otter Tail Power Company Big Stone Project Electric_Provider	Mar. 31, 2013 Otter Tail Power Company Big Stone Project	Sep. 30, 2013 Otter Tail Power Company Big Stone Project	Sep. 30, 2013 Otter Tail Power Company Brookings Project Capacity Expansion 2020 kV	Sep. 30, 2013 Otter Tail Power Company Bemidji Project Capacity Expansion 2020 kV	Sep. 30, 2013 Otter Tail Power Company Twin Cities La Crosse Capacity Expansion 2020 kV	Feb. 20, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider Project	May 24, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider Project	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider Project	Jan. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Jan. 31, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Sep. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Sep. 30, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Dec. 31, 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	Jan. 11, 2012 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 Fiscal Year 2011	Dec. 31, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program Fiscal Year 2011	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program Fiscal Year 2012	Jan. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program Fiscal Year 2012	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2016	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2020	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2025	Jul. 25, 2012 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate	May 01, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate	Apr. 02, 2010 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case	Dec. 31, 2011 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case	May 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone Project	Apr. 25, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone Project	Sep. 30, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone Project	Mar. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone South - Brookings MVP	Aug. 31, 2012 Otter Tail Power Company North Dakota Public Service Commission Transmission Cost Recovery Rider Project	Sep. 30, 2013 Otter Tail Power Company North Dakota Public Service Commission Transmission Cost Recovery Rider	Sep. 30, 2013 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Mar. 31, 2012 Otter Tail Power Company North Dakota Public Service Commission 2010 Renewable Resource Cost Recovery Rider Adjustment	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission 2011 Renewable Resource Cost Recovery Rider Adjustment	May 07, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone Project	Mar. 29, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone Project	Jun. 25, 2010 Otter Tail Power Company North Dakota Public Service Commission Big Stone Project	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone Project	Jan. 31, 2010 Otter Tail Power Company North Dakota Public Service Commission Ashtabula Wind Energy Center Renewable Resource Cost Recovery Rider	Jan. 14, 2009 Otter Tail Power Company North Dakota Public Service Commission Ashtabula Wind Energy Center Renewable Resource Cost Recovery Rider Property	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone South - Brookings MVP	Dec. 31, 2012 Otter Tail Power Company South Dakota Public Utilities Commission Transmission Cost Recovery Rider	May 31, 2013 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone Project	Mar. 31, 2011 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone Project	Aug. 20, 2010 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone Project General Rate Case	Mar. 31, 2011 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone Project General Rate Case	Dec. 31, 2012 Otter Tail Power Company Federal Energy Regulatory Commission Project	Dec. 31, 2010 Otter Tail Power Company Federal Energy Regulatory Commission Project	Sep. 30, 2013 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Brookings MVP mi kV	Sep. 30, 2013 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP kV	Aug. 25, 2013 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP Montana Dakota Utilities Co. mi	Sep. 30, 2013 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP Maximum mi	Sep. 30, 2013 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP Minimum mi
Regulatory Matters [Line Items]
Big Stone II Investment cost incurred, recovery period																																		5 years	60 months												36 months								5 years	10 years
Percentage of qualifying renewable energy to be supplied in proportion to aggregate energy supplies in Minnesota																													17.00%	20.00%	25.00%
Percentage of total electric revenue to be supplied by solar energy as per 2013 legislature																														1.50%
Regulatory asset	$ 149,675,000	$ 160,254,000															$ 6,100,000		$ 6,100,000									$ 100,000														$ 1,200,000
Regulatory Liabilities	71,180,000	69,394,000												100,000																											100,000
Filing of reply and supplemental comments to find eligible projects, Description														OTP filed its annual update to the TCR on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects.
Number of additional transmission related projects													12																											10
Number of additional projects approved												3
Number of additional projects pending for approval														9
Extended period of new effective rate																																18 months
Expected cost recovery from customers																																											15,600,000	9,900,000								600,000		1,000,000
Percentage of operating revenue from service to be invested in energy conservation in Minnesota			1.50%
Financial incentive filing request																								2,600,000		2,700,000	100,000
Financial incentives recognized during period																					2,600,000			400,000
Financial incentives approved																							3,500,000		2,600,000
Percentage of conservation cost recovery adjustment																3.80%						3.00%
Conservation improvement programs surcharge															3.80%
Decrease to conservation improvement programs surcharge															0.00142
Decrease to percentage of customers bill															1.90%
Conservation costs recoverable and incentives earned																	1,500,000	1,500,000	4,800,000	4,800,000
Number of wind turbines																																																		32
Renewable resource adjustment rate																																	0																	0.0051
Previously not recovered accrued renewable resource recovery revenues recovery period																																																	48 months
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate																																																										100.00%
Percentage of prudently incurred costs of cancelled or abandoned transmission facilities, authorized for recovery by formula transmission rate																																																									100.00%	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																																																345	345
Extended distance of transmission line																																																											70		10	170	160
Recoverable amount of generation costs																																					3,200,000
Investment cost incurred, transferred to construction work in progress																																					3,200,000
Number of other electric providers entered in agreement for development of project						6
BART compliant air quality control system implementation period							5 years	5 years
Regulators jurisdictional share of transmission costs																																															1,100,000
Regulators jurisdictional share																																															4,100,000
Regulators jurisdictional share of Big Stone II transmission costs transferred																																							400,000												300,000
Recoverable amount of deferred costs																																				3,500,000
Request for extension period of cost recovery rider																																														6 months
Discounted present value of recoverable deferred costs																																				2,800,000
Duration of regulatory asset to be extended																																													8 months
Charge related to discount in accordance with ASC 980 - Regulated Operations																																				700,000
Anticipated recovery period for discount and remaining balance of unrecovered project costs																																						89 months
Jurisdictional portion of unrecovered transmission costs and AFUDC transferred																																																$ 1,000,000					$ 200,000

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Summary of Significant Accounting Policies (Detail Textuals 1) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Significant Accounting Policies [Line Items]
Electric inputs maximum deviation below active trading hub price per megawatt-hour	6.95
Electric inputs maximum deviation above active trading hub price per megawatt-hour	2.45
Electric inputs weighted average price per megawatt-hour	36.55
Forward Electricity Contracts | Power purchase contracts | Level 3
Significant Accounting Policies [Line Items]
Percentage of offset by regulatory liabilities and assets of fuel clause adjustment treatment of fuel costs	100.00%
Net impact of recorded fair valuation gains or losses related to derivative contract	$ 0
Net income impact of future fair valuation adjustments of contracts	$ 0

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Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 59,117	$ 52,362
Short-Term Debt	(40,335)
Long-Term Debt including Current Maturities	(437,491)	(421,856)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	59,117	52,362
Short-Term Debt	(40,335)
Long-Term Debt including Current Maturities	$ (486,719)	$ (491,244)

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Schedule of major components of assets and liabilities of discontinued operations

Following are summary presentations of the results of discontinued operations for the three and nine-month periods ended September 30, 2013 and 2012:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Operating Revenues	$	--		$	61,827		$	2,016		$	208,186
Operating Expenses		(452	)		64,866			2,094			203,961
Asset Impairment Charge		--			--			--			45,573
Operating Income (Loss)		452			(3,039	)		(78	)		(41,348	)
Interest Charges		--			--			--			174
Other (Deductions) Income		(101	)		36			471			266
Income Tax Expense (Benefit)		39			(75	)		(35	)		(14,683	)
Net Income (Loss) from Operations		312			(2,928	)		428			(26,573	)
Gain (Loss) on Disposition Before Taxes		--			--			216			(3,713	)
Income Tax Expense (Benefit) on Disposition		--			--			6			(169	)
Net Gain (Loss) on Disposition		--			--			210			(3,544	)
Net Income (Loss)	$	312		$	(2,928	)	$	638		$	(30,117	)

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2013 and December 31, 2012:

(in thousands)	September 30,  2013		December 31, 2012
Current Assets	$	432	$	18,487
Investments		--		85
Net Plant		--		520
Assets of Discontinued Operations	$	432	$	19,092
Current Liabilities	$	4,080	$	11,156
Liabilities of Discontinued Operations	$	4,080	$	11,156

Schedule of warranty reserves

(in thousands)
Warranty Reserve Balance, December 31, 2012	$	5,027
Provision for Warranties Used During the Year		120
Less Settlements Made During the Year		(675	)
Decrease in Warranty Estimates for Prior Years		(1,112	)
Warranty Reserve Balance, September 30, 2013	$	3,360

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Pension Plan and Other Postretirement Benefits (Detail Textuals) (Pension Plan, USD $)	1 Months Ended
	Jan. 31, 2013	Jan. 31, 2012
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Plan contributions	$ 10,000,000	$ 10,000,000

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Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets of Discontinued Operations	$ 432	$ 19,092
Liabilities of Discontinued Operations	4,080	11,156
Disposal groups held for sale or disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets	432	18,487
Investments		85
Net Plant		520
Assets of Discontinued Operations	432	19,092
Current Liabilities	4,080	11,156
Liabilities of Discontinued Operations	$ 4,080	$ 11,156

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stockholders Equity and Earnings Per Share [Abstract]
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations	$ 0.01	$ 0.01	$ 0.01	$ 0.01

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Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 4) (Legally enforceable netting arrangements, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Legally enforceable netting arrangements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative assets subject to legally enforceable netting arrangements	$ 382	$ 638
Derivative liabilities subject to legally enforceable netting arrangements	(12,707)	(18,234)
Net balance subject to legally enforceable netting arrangements	$ (12,325)	$ (17,596)

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Fair Value of Financial Instruments (Detail Textuals) (OTP Credit Agreement)	9 Months Ended
	Sep. 30, 2013
OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis	LIBOR
Basis spread on variable rate	1.25%

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2013

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

Short-Term Debt—The carrying amount approximates fair value because the debt obligation is short-term and the balance outstanding related to the OTP Credit Agreement is subject to a variable interest rate that approximates current market rates (LIBOR plus 1.25%).

Long-Term Debt including Current Maturities—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 Company’s long-term debt subject to variable interest rates approximates fair value. 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.

	September 30, 2013						December 31, 2012
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	59,117		$	59,117		$	52,362		$	52,362
Short-Term Debt		(40,335	)		(40,335	)		--			--
Long-Term Debt including Current Maturities		(437,491	)		(486,719	)		(421,856	)		(491,244	)

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Retained Earnings Restriction

9 Months Ended

Sep. 30, 2013

Retained Earnings Restrictions [Abstract]

Retained Earnings Restriction

8. Retained Earnings Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP’s credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2013 the Company was in compliance with the debt covenants. See note 10 to the Company’s financial statements on Form 10-K for the year ended December 31, 2012 for further information on the covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account.  What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 44.8% and 54.8%. OTP’s equity to total capitalization ratio including short-term debt was 49.5% as of September 30, 2013. Total capitalization for OTP cannot currently exceed $874 million.

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Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 677	$ 463	$ 3,264	$ 1,368
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	39	31	98	119
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	119	139	488	413
Restricted Stock | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	111	87	315	232
Restricted Stock Units (RSUs) | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	61	60	215	165
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 347	$ 146	$ 2,148	$ 439

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

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 (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging (ASC 815). 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.

The companies in the Construction segment 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 costs incurred to total estimated costs on construction projects. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Percentage-of-Completion Revenues	20.6	%	17.1	%	16.4	%	16.8	%

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

	September 30,			December 31,
(in thousands)	2013			2012
Costs Incurred on Uncompleted Contracts	$	341,649		$	307,085
Less Billings to Date		(358,026	)		(321,388	)
Plus Estimated Earnings Recognized		5,033			1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

The following amounts are included in the Company’s consolidated balance sheets:

	September 30,			December 31,
(in thousands)	2013			2012
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	4,858		$	3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(16,202	)		(16,204	)
NetBillings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(11,344	)	$	(12,541	)

The Company has a standard quarterly estimate at completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.

In 2012, Foley Company (Foley) experienced cost overruns in excess of estimated costs on several large projects. All of these projects were substantially completed as of December 31, 2012. Estimated costs on certain projects in excess of previous period estimates resulted in pretax charges of $0.1 million in the three months ended September 30, 2013 and $1.7 million in the three months ended September 30, 2012, and $0.6 million in the nine months ended September 30, 2013 and $10.4 million in the nine months ended September 30, 2012.

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 products sold by the Company 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. The warranty reserve balance as of December 31, 2012 and September 30, 2013 relates entirely to products that were produced by the Company’s manufacturers of wind towers and waterfront equipment prior to the Company selling the assets of these companies and is included in liabilities of discontinued operations. See note 17 to consolidated financial statements.

Retainage

Retainage

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

	September 30,		December 31,
(in thousands)	2013		2012
Accounts Receivable Retained by Customers	$	6,989	$	12,227

Fair Value Measurements

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), 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 (NYMEX).

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 the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	316
Forward Gasoline Purchase Contracts				66
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,608
U.S. Government Debt Securities – Held by Captive Insurance Company				1,278
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		722
Equity Securities - Nonqualified Retirement Savings Plan		130
Total Assets	$	962	$	8,952	$	316
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	12,707
Total Liabilities	$	--	$	--	$	12,707

December 31, 2012 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	292	$	210
Forward Gasoline Purchase Contracts				136
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				7,620
U.S. Government Debt Securities – Held by Captive Insurance Company				1,305
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		357
Equity Securities - Nonqualified Retirement Savings Plan		125
Total Assets	$	2,092	$	9,353	$	210
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	242	$	17,992
Total Liabilities	$	--	$	242	$	17,992

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of September 30, 2013 and December 31, 2012, are based on prices indexed to observable prices at an active trading hub. The Level 3 forward electric price inputs ranged from $6.95 per megawatt-hour underthe active trading hub price to $2.45 per megawatt-hour over the active trading hub price. The weighted average price was $36.55 per megawatt-hour.

In the table above, the fair values for the Level 3 forward energy contracts as of September 30, 2013 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three or nine month periods ended September 30, 2013 and 2012.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the nine-month periods ended September 30, 2013 and 2012:

	Nine Months Ended
	September 30,
(in thousands)	2013			2012
Forward Energy Contracts  - Fair Values Beginning of Period	$	(17,782	)	$	--
Transfers into Level 3 from Level 2		--			(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		5,066			3,771
Changes in Fair Value of Contracts Entered into in Prior Periods		325			(4,517	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(12,391	)		(16,630	)
Net Increase in Value of Open Contracts Entered into in Current Period		--			22
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(12,391	)	$	(16,608	)

Inventories

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2013		2012
Finished Goods	$	19,682	$	21,893
Work in Process		10,636		8,800
Raw Material, Fuel and Supplies		42,340		38,643
Total Inventories	$	72,658	$	69,336

Goodwill

Goodwill

The following table summarizes changes to goodwill by business segment during 2013:

(in thousands)	Gross Balance December 31, 2012		Accumulated Impairments		Balance (net of impairments) December 31, 2012		Adjustments to Goodwill in 2013		Balance (net of impairments) September 30, 2013
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Construction		7,483		--		7,483		--		7,483
Plastics		19,302		--		19,302		--		19,302
Total	$	38,971	$	--	$	38,971	$	--	$	38,971

Other Intangible Assets

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at September 30, 2013 and December 31, 2012:

September 30, 2013 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,722	$	12,089		15 – 25 years
Other Intangible Assets Including Contracts		825		442		383		5 – 30 years
Total	$	17,636	$	5,164	$	12,472
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2012(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,085	$	12,726		15 – 25 years
Other Intangible Assets Including Contracts		1,092		613		479		5 – 30 years
Total	$	17,903	$	4,698	$	13,205
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2013		2012		2013		2012
Amortization Expense – Intangible Assets	$	245	$	244	$	733	$	737

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

(in thousands)	2013		2014		2015		2016		2017
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	977	$	945	$	849

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2013		2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	25,133	$	5,979
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	5,172	$	--
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. 2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

Coyote Station Lignite Supply Agreement - Variable Interest Entity

Coyote Station Lignite Supply Agreement – Variable Interest Entity

In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, have the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE. Therefore, CCMC is not required to be consolidated in the Company’s consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through September 30, 2013 is $9.8 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC could be as high as $9.8 million as of September 30, 2013.

Reclassifications and Changes to Presentation

Reclassifications and Changes to Presentation

The Company’s consolidated income statement and consolidated statement of cash flows for the three and nine month periods ended September 30, 2012 reflect the reclassifications of the operating results and cash flows of discontinued operations as a result of the completion of the sale of the assets of the Company’s wind tower manufacturer and discontinuance of wind tower production activities in November 2012 and the sale of the assets of the Company’s waterfront equipment manufacturer on February 8, 2013. The reclassifications had no impact on the Company’s total consolidated net income or cash flows for the three or nine months ended September 30, 2012.

New Accounting Standards

New Accounting Standards

Accounting Standards Update (ASU) 2011-11 and 2013-01

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2011-13), to clarify which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The amendments in ASU 2013-01 apply to derivatives accounted for in accordance with ASC 815 and clarify that only derivatives accounted for in accordance with ASC 815 are within the scope of the disclosure requirements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.

The Company implemented the disclosure guidance January 1, 2013. While, certain of the Company’s offsetting derivative asset and liability positions related to forward energy contracts with the same counterparty are subject to legally enforceable netting arrangements, the Company does not present its derivative assets and liabilities subject to legally enforceable netting arrangements, or any related payables or receivables, on a net basis on the face of its consolidated balance sheet. The Company has added disclosures and a table in note 5 to the consolidated financial statements indicating the amounts of its derivative forward energy contracts presented at fair value in accordance with ASC 815 that are subject to legally enforceable netting arrangements.

ASU 2013-02

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, which requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under accounting principles generally accepted in the United States of America (U.S. GAAP) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail on these amounts. This ASU is effective for reporting periods beginning after December 15, 2012. Additional information required by this update is included on the face of the Company’s consolidated statement of comprehensive income for the period ending September 30, 2013. The amounts of accumulated other comprehensive losses associated with the Company’s pension and other post-retirement benefit programs that are being amortized and recognized as operating expenses and the income statement line item affected by the expense are disclosed in note 12 to the consolidated financial statements.

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Income Tax Expense Continuing Operations

9 Months Ended

Sep. 30, 2013

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 month and nine month periods ended September 30, 2013 and 2012:

	Three Months Ended  September 30,						Nine Months Ended  September 30,
(in thousands)	2013			2012			2013			2012
Income Before Income Taxes – Continuing Operations	$	19,959		$	4,016		$	50,677		$	22,077
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,784			1,566			19,764			8,610
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,162	)		(1,239	)		(4,592	)		(5,057	)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue		--			--			--			(676	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(297	)		(651	)		(668	)
Corporate Owned Life Insurance		(227	)		(118	)		(621	)		(503	)
Medicare Part D Subsidy		--			(196	)		--			(587	)
Employee Stock Ownership Plan Dividend Deduction		(190	)		(190	)		(568	)		(571	)
Research and Development Tax Credits from 2012		(520	)		--			(520	)		--
Deferred Tax Asset reduction – North Dakota, due to Tax Rate Decrease		--			--			365			--
Other Items - Net		(340	)		(311	)		(64	)		(348	)
Income Tax Expense (Benefit) – Continuing Operations	$	5,133		$	(785	)	$	13,113		$	200
Effective Income Tax Rate – Continuing Operations		25.7	%		(19.5	)%		25.9	%		0.9	%

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

(in thousands)	2013
Balance on January 1	$	4,436
Increases Related to Tax Positions for Prior Years		97
Uncertain Positions Adjusted During Year		(288	)
Balance on September 30	$	4,245

The balance of unrecognized tax benefits as of September 30, 2013 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2013 is not expected to change significantly within the next three 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 September 30, 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
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		36,270,696
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

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Income Tax Expense - Continuing operations effective income tax rate (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 19,959	$ 4,016	$ 50,677	$ 22,077
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	7,784	1,566	19,764	8,610
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)	(1,162)	(1,239)	(4,592)	(5,057)
Reversal of Accrued Interest on Removal of Cost Capitalization Audit Issue				(676)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(212)	(297)	(651)	(668)
Corporate Owned Life Insurance	(227)	(118)	(621)	(503)
Medicare Part D Subsidy		(196)		(587)
Employee Stock Ownership Plan Dividend Deduction	(190)	(190)	(568)	(571)
Research and Development Tax Credits from 2012	(520)		(520)
Deferred Tax Asset reduction - North Dakota, due to Tax Rate Decrease			365
Other Items - Net	(340)	(311)	(64)	(348)
Income Tax Expense (Benefit) - Continuing Operations	$ 5,133	$ (785)	$ 13,113	$ 200
Effective Income Tax Rate - Continuing Operations	25.70%	(19.50%)	25.90%	0.90%

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Discontinued Operations

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

17. Discontinued Operations

On February 8, 2013 the Company completed the sale of substantially all the assets of its waterfront equipment manufacturing company, formerly included in the Company’s Manufacturing segment, for approximately $13.0 million in cash and received a working capital true up of approximately $2.4 million in June 2013. On November 30, 2012 the Company completed the sale of the assets of its wind tower manufacturing company and on February 29, 2012 the Company completed the sale of DMS Health Technologies, Inc. Following are summary presentations of the results of discontinued operations for the three and nine-month periods ended September 30, 2013 and 2012:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Operating Revenues	$	--		$	61,827		$	2,016		$	208,186
Operating Expenses		(452	)		64,866			2,094			203,961
Asset Impairment Charge		--			--			--			45,573
Operating Income (Loss)		452			(3,039	)		(78	)		(41,348	)
Interest Charges		--			--			--			174
Other (Deductions) Income		(101	)		36			471			266
Income Tax Expense (Benefit)		39			(75	)		(35	)		(14,683	)
Net Income (Loss) from Operations		312			(2,928	)		428			(26,573	)
Gain (Loss) on Disposition Before Taxes		--			--			216			(3,713	)
Income Tax Expense (Benefit) on Disposition		--			--			6			(169	)
Net Gain (Loss) on Disposition		--			--			210			(3,544	)
Net Income (Loss)	$	312		$	(2,928	)	$	638		$	(30,117	)

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2013 and December 31, 2012:

(in thousands)	September 30,  2013		December 31, 2012
Current Assets	$	432	$	18,487
Investments		--		85
Net Plant		--		520
Assets of Discontinued Operations	$	432	$	19,092
Current Liabilities	$	4,080	$	11,156
Liabilities of Discontinued Operations	$	4,080	$	11,156

Included in current liabilities are warranty reserves. Details regarding the warranty reserves follow:

(in thousands)
Warranty Reserve Balance, December 31, 2012	$	5,027
Provision for Warranties Used During the Year		120
Less Settlements Made During the Year		(675	)
Decrease in Warranty Estimates for Prior Years		(1,112	)
Warranty Reserve Balance, September 30, 2013	$	3,360

The warranty reserve balance as of December 31, 2012 and September 30, 2013 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies. For wind towers, 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. For example, 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.

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Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parenthetical) (Details) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$ 12,707	[1]	$ 16,058	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	(316)		(416)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$ 12,391		$ 15,642

[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 $ 12,707 $ 16,058 Offsetting Gains with Counterparties under Master Netting Agreements (316) (416) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 12,391 $ 15,642.

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Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 5) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit			$ 2,176
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	12,707	[1]	16,058	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements
Total Current Liability - Marked-to-Market Loss	$ 12,707		$ 18,234

[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 $ 12,707 $ 16,058 Offsetting Gains with Counterparties under Master Netting Agreements (316) (416) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 12,391 $ 15,642.

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Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%	39.00%	39.00%