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 March 31, 2014

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:

April 30, 2014 – 36,471,911 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements
	Consolidated Balance Sheets – March 31, 2014 and December 31, 2013 (not audited)	2 & 3
	Consolidated Statements of Income - Three Months Ended March 31, 2014 and 2013 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2014 and 2013 (not audited)	5
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2014 and 2013 (not audited)	6
	Notes to Condensed Consolidated Financial Statements (not audited)	7-34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35-47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48-49
Item 4.	Controls and Procedures	50
Part II. Other Information
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	51
Signatures		51

1

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands)	March 31, 2014		December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	6,613	$	1,150
Accounts Receivable:
Trade—Net		99,892		83,572
Other		11,523		9,790
Inventories		81,875		72,681
Deferred Income Taxes		39,352		35,452
Unbilled Revenues		16,902		18,157
Costs and Estimated Earnings in Excess of Billings		3,719		4,063
Regulatory Assets		20,199		17,940
Other		11,336		7,747
Assets of Discontinued Operations		38		38
Total Current Assets		291,449		250,590
Investments		8,753		9,362
Other Assets		29,605		28,834
Goodwill		38,808		38,971
Other Intangibles—Net		13,084		13,328
Deferred Debits
Unamortized Debt Expense		4,498		4,188
Regulatory Assets		78,839		83,730
Total Deferred Debits		83,337		87,918
Plant
Electric Plant in Service		1,473,685		1,460,884
Nonelectric Operations		196,500		194,872
Construction Work in Progress		207,442		187,461
Total Gross Plant		1,877,627		1,843,217
Less Accumulated Depreciation and Amortization		686,460		676,201
Net Plant		1,191,167		1,167,016
Total Assets	$	1,656,203	$	1,596,019
See accompanying notes to condensed consolidated financial statements.

2

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands, except share data)	March 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt	$	11,899		$	51,195
Current Maturities of Long-Term Debt		191			188
Accounts Payable		104,486			113,457
Accrued Salaries and Wages		13,556			19,903
Billings In Excess Of Costs and Estimated Earnings		10,077			13,707
Accrued Taxes		14,057			12,491
Derivative Liabilities		8,252			11,782
Other Accrued Liabilities		8,272			6,532
Liabilities of Discontinued Operations		3,442			3,637
Total Current Liabilities		174,232			232,892
Pensions Benefit Liability		50,129			69,743
Other Postretirement Benefits Liability		45,547			45,221
Other Noncurrent Liabilities		21,367			25,209
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		212,682			195,603
Deferred Tax Credits		27,834			28,288
Regulatory Liabilities		75,365			73,926
Other		733			718
Total Deferred Credits		316,614			298,535
Capitalization
Long-Term Debt, Net of Current Maturities		498,640			389,589
Cumulative Preferred Shares– Authorized 1,500,000 Shares Without Par Value; Outstanding - None		--			--
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, 2014—36,412,491 Shares; 2013—36,271,696 Shares		182,062			181,358
Premium on Common Shares		259,454			255,759
Retained Earnings		109,878			99,441
Accumulated Other Comprehensive Loss		(1,720	)		(1,728	)
Total Common Equity		549,674			534,830
Total Capitalization		1,048,314			924,419
Total Liabilities and Equity	$	1,656,203		$	1,596,019
See accompanying notes to condensed consolidated financial statements.

3

Otter Tail Corporation
Consolidated Statements of Income
(not audited)
	Three Months Ended March 31,
(in thousands, except share and per-share amounts)	2014		2013
Operating Revenues
Electric	$	119,048	$	100,976
Product Sales		95,918		90,561
Construction Services		25,506		26,417
Total Operating Revenues		240,472		217,954
Operating Expenses
Production Fuel - Electric		22,030		17,953
Purchased Power - Electric System Use		21,785		16,639
Electric Operation and Maintenance Expenses		34,622		32,447
Cost of Products Sold (depreciation included below)		73,939		67,787
Cost of Construction Revenues Earned (depreciation included below)		22,362		24,275
Other Nonelectric Expenses		13,561		13,778
Depreciation and Amortization		14,780		14,920
Property Taxes - Electric		2,971		2,916
Total Operating Expenses		206,050		190,715
Operating Income		34,422		27,239
Interest Charges		6,595		6,980
Other Income		1,823		861
Income Before Income Taxes from Continuing Operations		29,650		21,120
Income Tax Expense – Continuing Operations		8,288		5,886
Net Income from Continuing Operations		21,362		15,234
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $49 and ($205) for the respective periods		68		(81	)
Gain on Disposition - net of Income Tax Expense of $6 for the three months ended March 31, 2013		--		210
Net Income from Discontinued Operations		68		129
Net Income		21,430		15,363
Preferred Dividend Requirements and Other Adjustments		--		513
Earnings Available for Common Shares	$	21,430	$	14,850
Average Number of Common Shares Outstanding—Basic		36,240,350		36,075,131
Average Number of Common Shares Outstanding—Diluted		36,431,915		36,259,115
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$	0.59	$	0.41
Discontinued Operations		--		--
	$	0.59	$	0.41
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$	0.59	$	0.41
Discontinued Operations		--		--
	$	0.59	$	0.41
Dividends Declared Per Common Share	$	0.3025	$	0.2975
See accompanying notes to condensed consolidated financial statements.

4

Otter Tail Corporation
Consolidated Statements of Comprehensive Income
(not audited)
	Three Months Ended March 31,
(in thousands)	2014			2013
Net Income	$	21,430		$	15,363
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		(17	)		(25	)
(Losses) Arising During Period		(17	)		(5	)
Income Tax Benefit		12			11
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		(22	)		(19	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 12)		50			145
Income Tax (Expense)		(20	)		(58	)
Pension and Postretirement Benefit Plans – net-of-tax		30			87
Total Other Comprehensive Income		8			68
Total Comprehensive Income	$	21,438		$	15,431
See accompanying notes to condensed consolidated financial statements.

5

Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)
	Three Months Ended March 31,
(in thousands)	2014			2013
Cash Flows from Operating Activities
Net Income	$	21,430		$	15,363
Adjustments to Reconcile Net Income to Net Cash (Used in) Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		--			(210	)
Net (Income) Loss from Discontinued Operations		(68	)		81
Depreciation and Amortization		14,780			14,920
Deferred Tax Credits		(454	)		(483	)
Deferred Income Taxes		12,872			6,139
Change in Deferred Debits and Other Assets		(888	)		4,800
Discretionary Contribution to Pension Plan		(20,000	)		(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		(2,408	)		1,975
Allowance for Equity/Other Funds Used During Construction		(340	)		(293	)
Change in Derivatives Net of Regulatory Deferral		118			378
Stock Compensation Expense—Equity Awards		358			392
Other—Net		(255	)		25
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(17,884	)		(13,423	)
Change in Inventories		(9,234	)		(4,062	)
Change in Other Current Assets		(1,599	)		(3,025	)
Change in Payables and Other Current Liabilities		(16,363	)		(3,440	)
Change in Interest and Income Taxes Receivable/Payable		1,013			1,076
Net Cash (Used in) Provided by Continuing Operations		(18,922	)		10,213
Net Cash Used in Discontinued Operations		(135	)		(2,400	)
Net Cash (Used in) Provided by Operating Activities		(19,057	)		7,813
Cash Flows from Investing Activities
Capital Expenditures		(37,690	)		(23,327	)
Net Proceeds from Disposal of Noncurrent Assets		1,505			729
Net Increase in Other Investments		(989	)		(923	)
Net Cash Used in Investing Activities - Continuing Operations		(37,174	)		(23,521	)
Net Proceeds from Sale of Discontinued Operations		--			10,465
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations		7			(208	)
Net Cash Used in Investing Activities		(37,167	)		(13,264	)
Cash Flows from Financing Activities
Net Short-Term (Repayments) Borrowings		(39,296	)		1,335
Proceeds from Issuance of Common Stock		3,666			1,156
Payments for Retirement of Capital Stock		(242	)		(15,500	)
Proceeds from Issuance of Long-Term Debt		150,000			40,900
Short-Term and Long-Term Debt Issuance Expenses		(502	)		(7	)
Payments for Retirement of Long-Term Debt		(40,946	)		(25,178	)
Dividends Paid and Other Distributions		(10,993	)		(11,307	)
Net Cash Provided by (Used in) Financing Activities		61,687			(8,601	)
Net Change in Cash and Cash Equivalents - Discontinued Operations		--			(778	)
Net Change in Cash and Cash Equivalents		5,463			(14,830	)
Cash and Cash Equivalents at Beginning of Period		1,150			52,362
Cash and Cash Equivalents at End of Period	$	6,613		$	37,532
See accompanying notes to condensed consolidated financial statements.

6

OTTER TAIL CORPORATION

NOTES TO CONDENSED 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, 2013. Because of seasonal and other factors, the earnings for the three months ended March 31, 2014 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, 2013.

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) 815, Derivatives and Hedging. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

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 March 31,
	2014			2013
Percentage-of-Completion Revenues		9.1	%		12.1	%

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs Incurred on Uncompleted Contracts	$	364,005		$	361,487
Less Billings to Date		(377,991	)		(377,608	)
Plus Estimated Earnings Recognized		7,628			6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,719		$	4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(10,077	)		(13,707	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

7

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.

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The warranty reserve balance as of December 31, 2013 and March 31, 2014 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies and is included in liabilities of discontinued operations. See note 17 to condensed 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:

	March 31,		December 31,
(in thousands)	2014		2013
Accounts Receivable Retained by Customers	$	6,352	$	7,125	1
1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

Fair Value Measurements

The Company follows Accounting Standards Codification (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.

8

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 March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	1,609
Forward Gasoline Purchase Contracts				20
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,438
U.S. Government Debt Securities – Held by Captive Insurance Company				964
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		745
Total Assets	$	865	$	8,422	$	1,609
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	8,252
Total Liabilities	$	--	$	--	$	8,252

December 31, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	338
Forward Gasoline Purchase Contracts				62
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,671
U.S. Government Debt Securities – Held by Captive Insurance Company				1,271
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		866
Total Assets	$	976	$	9,004	$	338
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	103	$	11,679
Total Liabilities	$	--	$	103	$	11,679

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 March 31, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. 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 March 31, 2014 Level 3 forward electric price inputs ranged from $1.52 to $7.00 per megawatt-hour underthe active trading hub price. The weighted average price was $36.77 per megawatt-hour.

9

In the table above, $1,569,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $8,252,000 of the fair value of the Level 3 forward energy contracts in a derivative liability position as of March 31, 2014 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 month periods ended March 31, 2014 or 2013.

The remaining $40,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position as of March 31, 2014 are related to financial contracts that will not be settled by physical delivery of electricity but will be settled financially by the counterparty to the contract paying or receiving the difference between the contract price and the market price at the hour of scheduled delivery. The related forward energy sales contracts are not offset by forward energy purchase contracts. Therefore, the $40,000 in derivative gains related to these contracts as of March 31, 2014 are subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in April and May of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the fair value of the contracts.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Forward Energy Contracts - Fair Values Beginning of Period	$	(11,341	)	$	(17,782	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		1,160			2,195
Changes in Fair Value of Contracts Entered into in Prior Periods		3,498			3,320
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(6,683	)		(12,267	)
Net Gain Recognized as Regulatory Assets on contract entered into in Period		40			32
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(6,643	)	$	(12,235	)

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2014		2013
Finished Goods	$	25,611	$	20,649
Work in Process		9,654		9,942
Raw Material, Fuel and Supplies		46,610		42,090
Total Inventories	$	81,875	$	72,681

10

Goodwill and Other Intangible Assets

In the first quarter of 2014, Aevenia, Inc. (Aevenia) recorded a $289,000 gain on the sale of its data communication installation and services business which, over the years of its existence, did not provide a materially significant impact to Aevenia’s operating results. In connection with this sale, Aevenia disposed of $163,000 in goodwill associated with the purchase of this business in May 2004.

The following table summarizes changes to goodwill by business segment during 2014:

(in thousands)	Gross Balance December 31, 2013		Accumulated Impairments		Balance (net of impairments) December 31, 2013		Adjustments to Goodwill in 2014		Balance (net of impairments) March 31, 2014
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Construction		7,483		--		7,483		163		7,320
Total	$	38,971	$	--	$	38,971	$	163	$	38,808

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. The following table summarizes the components of the Company’s intangible assets at March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,147	$	11,664	15 – 25 years
Other Intangible Assets Including Contracts		825		505		320	5 – 30 years
Total	$	17,636	$	5,652	$	11,984
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2013(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,935	$	11,876	15 – 25 years
Other Intangible Assets Including Contracts		825		473		352	5 – 30 years
Total	$	17,636	$	5,408	$	12,228
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2014		2015		2016		2017		2018
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	945	$	849	$	849

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Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2014		2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	22,244	$	8,901
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	3,434	$	--
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, has 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 and 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 March 31, 2014 is $10.9 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 as of March 31, 2014 could be as high as $10.9 million.

Revisions to Presentation

Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the three months ended March 31, 2013 have been revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for the three months ended March 31, 2014. The change in presentation of 2013 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for the three month period ended March 31, 2013.

New Accounting Standards

Accounting Standards Update (ASU) 2013-11

In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis. The Company’s long-term deferred income tax reported on its March 31, 2014 consolidated balance sheet include $4.3 million of unrecognized tax benefits.

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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, Plastics and Construction.

 

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.

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.

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.

Construction consists of businesses involved in commercial and industrial electric contracting and construction of fiber optic, electric distribution, water, wastewater and HVAC systems primarily in the central United States.

OTP is a wholly owned subsidiary 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 2013. 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 March 31,
	2014			2013
United States of America		97.5	%		97.9	%
Mexico		1.9	%		1.2	%
Canada		0.5	%		0.9	%
All Other Countries (none individually greater than 0.05%)		0.1	%		--

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The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2014 and 2013 and total assets by business segment as of March 31, 2014 and December 31, 2013 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	119,088		$	101,010
Manufacturing		55,435			53,166
Plastics		40,483			37,400
Construction		25,506			26,425
Intersegment Eliminations		(40	)		(47	)
Total	$	240,472		$	217,954

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Electric	$	5,079	$	4,808
Manufacturing		808		815
Plastics		247		248
Construction		100		107
Corporate and Intersegment Eliminations		361		1,002
Total	$	6,595	$	6,980

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	5,750		$	4,082
Manufacturing		1,671			2,218
Plastics		2,133			2,603
Construction		(409	)		(723	)
Corporate		(857	)		(2,294	)
Total	$	8,288		$	5,886

Earnings Available for Common Shares

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	16,653		$	11,931
Manufacturing		2,896			3,318
Plastics		3,460			3,887
Construction		(620	)		(1,092	)
Corporate		(1,027	)		(3,323	)
Discontinued Operations		68			129
Total	$	21,430		$	14,850

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Identifiable Assets

	March 31,		December 31,
(in thousands)	2014		2013
Electric	$	1,334,155	$	1,290,416
Manufacturing		125,800		119,302
Plastics		95,779		76,853
Construction		46,800		49,440
Corporate		53,631		59,970
Discontinued Operations		38		38
Total	$	1,656,203	$	1,596,019

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2014 and 2013.

Major Capital Expenditure Projects

Multi-Value Transmission Projects—On December 16, 2010, FERC approved the cost allocation for a new classification of projects in the MISO region 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 areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. Effective January 1, 2012, the FERC authorized OTP to recover 100% of prudently incurred Construction Work in Progress (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. Abandoned Plant recovery provides a basis for OTP to request recovery of prudently incurred costs in the event a project is cancelled for reasons beyond OTP’s control. On February 24, 2014 the U.S. Supreme Court denied petitions for a writ of certiorari of the United States Court of Appeals, Seventh Circuit decision upholding the FERC’s MVP orders. The petitioners did not seek rehearing. The following projects have been approved by MISO as MVPs under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff).

The Big Stone South – Brookings Project—This is a planned 345 kiloVolt (kV) transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. This line is expected to be in service in 2017. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. The SDPUC granted OTP and Xcel Energy approval of a route permit for the southern portion of the Big Stone South - Brookings line on February 18, 2014.

The Big Stone South – Ellendale Project—This is a proposed 345 kV transmission 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 on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor Compatibility along with an application for a route permit with the NDPSC on October 18, 2013.

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Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kV Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji–Grand Rapids 230 kV Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project. Recovery of OTP’s CapX2020 transmission investments is through the MISO Tariff (the Brookings Project as an MVP) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (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. The St. Cloud to Alexandria portion of the Fargo Project was placed into service April 23, 2014. Construction is underway for the remaining portions of the project.

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 also granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011.The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized on April 29, 2014.

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

Big Stone Plant Air Quality Control System (AQCS)—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 the EPA agreed on non-substantive rule revisions, which were adopted by the South Dakota 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 AQCS 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.

OTP is currently in the process of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through March 31, 2014 is $113 million.

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. OTP requested jurisdictional recovery in Minnesota, North Dakota and South Dakota of amounts it had invested in the Big Stone II Project at the time of its withdrawal, which are discussed below.

Minnesota

2010 General Rate Case—OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (MNCIP) costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota Fuel Clause Adjustment.

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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 potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

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

The costs for three major wind farms previously approved by the MPUC for recovery through OTP’s Minnesota Renewable Resource Adjustment (MNRRA) were 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. Effective May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs.

Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal.

The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

In December 2012, the MPUC 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. 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 recognized $3.9 million in MNCIP financial incentives in 2013 related to the results of its conservation improvement programs in Minnesota in 2013. On April 1, 2014 OTP submitted its annual 2013 financial incentive filing request for $4.0 million along with a request for an updated surcharge rate with a proposed implementation date of July 1, 2014.

OTP had a regulatory asset of $8.1 million for allowable costs and financial incentives eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of March 31, 2014. OTP recognized revenue for Minnesota conservation costs and incentives earned totaling $1.5 million in the three month period ended March 31, 2014, compared with $1.6 million in the three month period ended March 31, 2013.

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Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or 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. 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.

MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers. On March 26, 2012 the MPUC approved an update to OTP’s Minnesota TCR rider along with an all-in method for MISO regional cost allocations in which OTP’s retail customers would be responsible for the entire investment OTP made in transmission facilities that qualify for regional cost allocation under the MISO Tariff, with an offsetting credit for revenues received from other MISO utilities under the MISO Tariff for projects included in the TCR. OTP’s updated Minnesota TCR rider went into effect April 1, 2012.

On May 24, 2012 OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery through the TCR rider. OTP filed its annual update to the TCR rider on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of CON estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC approval of OTP’s annual TCR update, OTP submitted compliance filings in April 2014 seeking no rate change. OTP filed its 2014 annual update on May 1, 2014 with a proposed implementation date of July 1, 2014.

OTP had a regulatory asset of $1.2 million as of March 31, 2014 for amounts eligible for recovery through the Minnesota TCR rider that had not been billed to Minnesota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota TCR rider of $2.3 million in the three month period ended March 31, 2014, compared with $1.0 million in the three month period ended March 31, 2013.

Environmental Cost Recovery (ECR) Rider—In a written order issued on January 23, 2012 the MPUC granted OTP’s petition for Advance Determination of Prudence (ADP) for costs associated with the design, construction and operation of the BART-compliant AQCS at Big Stone Plant attributable to serving OTP’s Minnesota customers. On May 24, 2013 legislation was enacted in Minnesota which allowed OTP to file 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 OTP’s most recent general rate case, unless a different return is determined by the MPUC to be in the public interest. On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. The rate will be updated in an annual filing with the MPUC until the costs are rolled into base rates at an undetermined future date.

OTP had a regulatory liability of $0.1 million as of March 31, 2014 for amounts billed to Minnesota customers that were subject to refund through the Minnesota ECR rider. OTP recognized revenue for amounts eligible for recovery through the Minnesota ECR rider of $1.8 million in the three month period ended March 31, 2014.

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Big Stone II Cost Recovery—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 as part of the rates established in that proceeding was $3.2 million. Because OTP will not earn a return on these deferred costs over the 60-month recovery period, the recoverable amount of $3.2 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate, in accordance with ASC Topic 980, Regulated Operations (ASC 980), accounting requirements.Transmission-related project costs of $3.2 million remained in CWIP as active project costs.

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, along with accumulated AFUDC, were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota 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 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 which began in May 2013.

North Dakota

General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009.

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables 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. On March 21, 2012 the NDPSC approved an update to OTP’s NDRRA effective April 1, 2012. The updated NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. 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 updated rates implemented on April 1, 2013. The NDPSC approved OTP’s most recent annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014. The update approved on March 12, 2014 resulted in a 13.5% reduction in the NDRRA rate.

OTP had a net regulatory liability of $1.3 million as of March 31, 2014 for amounts billed to North Dakota customers that were subject to refund through the NDRRA rider. OTP recognized revenue for amounts eligible for recovery through the NDRRA rider of $1.4 million in the three month period ended March 31, 2014, compared with $2.3 million in the three month period ended March 31, 2013.

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014.

OTP had a regulatory liability of less than $0.1 million as of March 31, 2014 for amounts billed to North Dakota customers that were subject to refund through the North Dakota TCR rider. OTP recognized revenue for amounts eligible for recovery through the North Dakota TCR rider of $1.5 million in the three month period ended March 31, 2014, compared with $0.8 million in the three month period ended March 31, 2013.

Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate with a proposed implementation date of July 1, 2014. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The ECR rider rate will continue to be updated at least annually in a filing with the NDPSC until the project costs are rolled into base rates at an undetermined future date.

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OTP had a regulatory asset of $2.1 million as of March 31, 2014 for amounts eligible for recovery through the North Dakota ECR rider that had not been billed to North Dakota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota ECR rider of $1.5 million in the three month period ended March 31, 2014, compared with $0.7 million in the three month period ended March 31, 2013.

Big Stone II Cost Recovery—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 total amount of Big Stone II generation costs incurred by OTP (which excluded $2.6 million of project transmission-related costs) was determined to be $10.1 million, of which $4.1 million represents North Dakota’s jurisdictional share.

OTP is including in its total recovery amount a carrying charge of approximately $0.3 million on the North Dakota share of Big Stone II generation costs for the period from September 1, 2009 through the date the recovery of costs begins based on OTP’s average 2009 AFUDC rate of 7.65%. Because OTP will not earn a return on these deferred costs over the 36-month recovery period, the recoverable amount of $4.3 million was discounted to its then present value of $3.9 million using OTP’s incremental borrowing rate, in accordance with ASC 980 accounting requirements. The North Dakota portion of Big Stone II generation costs was 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. 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. On July 30, 2013 the NDPSC approved OTP’s request to continue the Big Stone II cost recovery rates for an additional eight months through March 31, 2014 to recover the remaining North Dakota share of Big Stone II transmission-related costs plus accrued AFUDC totaling $1.0 million. As of April 1, 2014 North Dakota customer’s bills no longer include a charge for North Dakota share of Big Stone II costs. OTP had a regulatory liability of $0.1 million as of March 31, 2014 for amounts billed to North Dakota customers that will be subject to refund through the North Dakota TCR rider.

South Dakota

2010 General Rate Case—On April 21, 2011 the SDPUC issued a written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50% for the interim rates and final rates for OTP in South Dakota. Final rates were effective with bills rendered on and after June 1, 2011.

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP submitted a request for an initial South Dakota TCR rider to the SDPUC on November 5, 2010. The South Dakota TCR was approved by the SDPUC and implemented on December 1, 2011. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s most recent annual update to its South Dakota TCR on February 18, 2014 with an effective date of March 1, 2014.

OTP had a regulatory asset of $0.1 million as of March 31, 2014 for amounts eligible for recovery through the South Dakota TCR rider that had not been billed to South Dakota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the South Dakota TCR rider of $0.3 million in the three month period ended March 31, 2014, compared with $0.1 million in the three month period ended March 31, 2013.

Environmental Cost Recovery Rider—On March 30, 2012 OTP requested approval from the SDPUC for an ECR rider to recover costs associated with the Big Stone Plant AQCS. 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.

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Big Stone Cost Recovery—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 is allowed to earn a return on the amount subject to recovery over the ten-year recovery period. Therefore, the South Dakota settlement amount is not discounted. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP.

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.

Federal

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

Effective January 1, 2010 the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Tariff. OTP was also authorized by the FERC to recover in its formula rate: (1) 100% of prudently incurred CWIP in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects in which OTP is invested.

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint at the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. The complaint is pending at the FERC.

Environmental Protection Agency (EPA) Cross-State Air Pollution Rule (CSPAR)

On April 29, 2014 the U.S. Supreme Court issued its opinion in litigation concerning EPA’s CSAPR, reversing the August 21, 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated CSAPR. The Supreme Court’s opinion does not remove or otherwise address the D.C. Circuit’s December 30, 2011 order staying CSAPR. CSAPR will now be remanded to the D.C. Circuit for further proceedings; however, CSAPR will continue to be stayed until the D.C. Circuit in the future lifts or modifies the stay. Therefore, at this time implementation and compliance dates for the rule are unknown.

The CSAPR rule that was vacated in 2012 would have applied to OTP’s Solway gas peaking plant and the Hoot Lake coal-fired plant in Minnesota. The primary impact of the rule would have been for Hoot Lake Plant to acquire sulfur dioxide (SO2) allowances to continue operating at historical levels. Based on Hoot Lake’s historical generation and EPA’s predicted allowance costs at the time of the 2012 rule, CSAPR would have resulted in annual SO2 allowance purchase costs of approximately $1.0 million.

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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:

	March 31, 2014						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	4,043	$	54,038	$	58,081	see note
Deferred Marked-to-Market Losses1		3,258		4,994		8,252	57 months
Conservation Improvement Program Costs and Incentives2		3,533		4,580		8,113	15 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,779		4,779	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		566		3,857		4,423	78 months
Recoverable Fuel and Purchased Power Costs1		3,540		--		3,540	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,452		1,419		2,871	21 months
Debt Reacquisition Premiums1		361		2,154		2,515	222 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,071		--		2,071	15 months
Deferred Income Taxes1		--		2,013		2,013	asset lives
Minnesota Transmission Rider Accrued Revenues2		1,153		--		1,153	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		101		818		919	110 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		119		119	24 months
South Dakota Transmission Rider Accrued Revenues2		107		--		107	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		14		--		14	3 months
Total Regulatory Assets	$	20,199	$	78,839	$	99,038
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,943	$	71,943	asset lives
Deferred Income Taxes		--		1,869		1,869	asset lives
Deferred Marked-to-Market Gains		533		1,037		1,570	53 months
North Dakota Renewable Resource Rider Accrued Refund		1,436		--		1,436	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		412		412	see note
Big Stone II Over Recovered Project Costs – North Dakota		144		--		144	6 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		104		110	237 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		56		--		56	12 months
North Dakota Transmission Rider Accrued Refund		32		--		32	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		21		--		21	12 months
Total Regulatory Liabilities	$	2,228	$	75,365	$	77,593
Net Regulatory Asset Position	$	17,971	$	3,474	$	21,445
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, 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	$	4,095	$	55,012	$	59,107	see note
Deferred Marked-to-Market Losses1		3,008		8,674		11,682	60 months
Conservation Improvement Program Costs and Incentives2		4,945		3,959		8,904	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,646		4,646	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		558		3,967		4,525	81 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,351		1,753		3,104	24 months
Debt Reacquisition Premiums1		351		2,241		2,592	225 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,331		--		2,331	12 months
Deferred Income Taxes1		--		1,805		1,805	asset lives
Big Stone II Unrecovered Project Costs – South Dakota2		101		843		944	113 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		762		762	15 months
Recoverable Fuel and Purchased Power Costs1		760		--		760	12 months
Big Stone II Unrecovered Project Costs – North Dakota1		375		--		375	3 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
South Dakota Transmission Rider Accrued Revenues2		32		--		32	12 months
Deferred Holding Company Formation Costs1		27		--		27	6 months
General Rate Case Recoverable Expenses – South Dakota1		6		--		6	1 month
Total Regulatory Assets	$	17,940	$	83,730	$	101,670
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,454	$	71,454	asset lives
Deferred Income Taxes		--		1,960		1,960	asset lives
Minnesota Transmission Rider Accrued Refund		670		--		670	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		289		289	see note
North Dakota Renewable Resource Rider Accrued Refund		261		--		261	12 months
North Dakota Transmission Rider Accrued Refund		215		--		215	12 months
Deferred Marked-to-Market Gains		6		117		123	56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		5		106		111	240 months
South Dakota – Nonasset-Based Margin Sharing Excess		38		--		38	12 months
Total Regulatory Liabilities	$	1,195	$	73,926	$	75,121
Net Regulatory Asset Position	$	16,745	$	9,804	$	26,549
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 March 31, 2014 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.

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

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

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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 March 31, 2014 balance is being amortized on a straight-line basis over two consecutive 12-month periods that began in January 2014.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 222 months.

North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.

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

Minnesota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers net of transmission revenues that have not been billed to Minnesota customers as of March 31, 2014.

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.

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2014 and that are not scheduled to be recovered prior to March 31, 2015.

South Dakota Transmission Rider Accrued Revenues relate to revenues earned 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 March 31, 2014.

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. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

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

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2014.

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.

Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of 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. The March 31, 2014 liability will be refunded to North Dakota customers through an adjustment to revenue requirements under the North Dakota TCR rider.

The Minnesota Environmental Cost Recovery Rider Accrued refund relates to amounts billed under the Minnesota ECR rider in excess of an allowed return granted on the Minnesota share of amounts invested in the construction of the Big Stone Plant AQCS project.

The North Dakota Transmission Rider Accrued Refund relates to amounts collected for 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 March 31, 2014.

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.

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If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases.

5. Forward Contracts Classified as Derivatives

Electricity Contracts

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

As of March 31, 2014 OTP had recognized, on a pretax basis, $39,000 in net unrealized gains on open forward contracts for the 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 March 31, 2014 and December 31, 2013, and the change in the Company’s consolidated balance sheet position from December 31, 2013 to March 31, 2014 and December 31, 2012 to March 31, 2013:

(in thousands)	March 31, 2014			December 31, 2013
Current Asset – Marked-to-Market Gain	$	1,609		$	338
Regulatory Asset – Current Deferred Marked-to-Market Loss		3,258			3,008
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		4,994			8,674
Total Assets		9,861			12,020
Current Liability – Marked-to-Market Loss		(8,252	)		(11,782	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(533	)		(6	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(1,037	)		(117	)
Total Liabilities		(9,822	)		(11,905	)
Net Fair Value of Marked-to-Market Energy Contracts	$	39		$	115

(in thousands)	Year-to-Date March 31, 2014			Year-to-Date March 31, 2013
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	115		$	49
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
Changes in Fair Value of Contracts Entered into in Current Period		39			81
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	39		$	81

The $39,000 in recognized but unrealized gains on the forward energy sales contracts marked to market on March 31, 2014 are expected to be realized on settlement as scheduled in April and May of 2014.

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

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Net (Loss) Gain on Forward Electric Energy Contracts	$	(4	)	$	226

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 March 31, 2014 and December 31, 2013:

	March 31, 2014				December 31, 2013
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	128		3	$	856		3
Net Credit Risk to Single Largest Counterparty	$	83			$	530

OTP had a net credit risk exposure to three counterparties with investment grade credit ratings. OTP had no exposure at March 31, 2014 or December 31, 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 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 March 31, 2014. 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 amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of March 31, 2014 and December 31, 2013 are indicated in the following table:

(in thousands)	March 31, 2014			December 31, 2013
Derivative assets subject to legally enforceable netting arrangements	$	1,629		$	400
Derivative liabilities subject to legally enforceable netting arrangements		(8,252	)		(11,782	)
Net balance subject to legally enforceable netting arrangements	$	(6,623	)	$	(11,382	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of March 31, 2014 and December 31, 2013:

Current Liability – Marked-to-Market Loss (in thousands)	March 31, 2014			December 31, 2013
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	--
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		8,252			11,679
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			103
Total Current Liability – Marked-to-Market Loss	$	8,252		$	11,782
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	$	8,252		$	11,679
Offsetting Gains with Counterparties under Master Netting Agreements		(1,569	)		(117	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	6,683		$	11,562

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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, 2013	$	181,358		$	255,759		$	99,441		$	(1,728	)	$	534,830
Common Stock Issuances, Net of Expenses		748			3,504									4,252
Common Stock Retirements		(44	)		(198	)								(242	)
Net Income								21,430						21,430
Other Comprehensive Income											8			8
Tax Benefit – Stock Compensation					31									31
Employee Stock Incentive Plans Expense					358									358
Common Dividends								(10,993	)					(10,993	)
Balance, March 31, 2014	$	182,062		$	259,454		$	109,878		$	(1,720	)	$	549,674

Common Shares

In 2014, the Company began issuing shares to meet the requirements of its dividend reinvestment, employee stock ownership, and employee stock purchase plans and shareholder stock purchase program, rather than purchasing shares in the open market. Following is a reconciliation of the Company’s common shares outstanding from December 31, 2013 through March 31, 2014:

Common Shares Outstanding, December 31, 2013	36,271,696
Issuances:
Dividend Reinvestments	49,402
Employee Stock Ownership Plan	22,650
Executive Stock Performance Awards (2011-2013 shares earned)	22,630
Employee Stock Purchase Plan	19,661
Shareholder Stock Purchase Program	18,681
Stock Options Exercised	16,650
Retirements:
Shares Withheld for Individual Income Tax Requirements	(8,879	)
Common Shares Outstanding, March 31, 2014	36,412,491

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 month periods ended March 31, 2014 and 2013. 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. Adjustments to the denominator used to calculate diluted earnings per share of 191,565 shares and 183,984 shares for the three month periods ended March 31, 2014 and 2013, respectively, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either quarter.

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7. Share-Based Payments

The Company has five share-based payment programs. No new stock awards were granted under these programs in the first quarter of 2014. As of March 31, 2014 the remaining unrecognized compensation expense related to stock-based compensation was approximately $3.6 million (before income taxes) which will be amortized over a weighted-average period of 1.8 years.

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three month periods ended March 31, 2014 and 2013 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2014		2013
Employee Stock Purchase Plan (15% discount)	$	42	$	17
Restricted Stock Granted to Directors		123		207
Restricted Stock Granted to Employees		135		92
Restricted Stock Units Granted to Employees		58		75
Stock Performance Awards Granted to Executive Officers		526		1,098
Totals	$	884	$	1,489

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 March 31, 2014 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, 2013 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 47.2% as of March 31, 2014. Total capitalization for OTP cannot currently exceed $874 million.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2013 OTP had commitments under contracts in connection with construction programs aggregating approximately $108.2 million. At March 31, 2014 OTP had commitments under contracts in connection with construction programs aggregating approximately $103.2 million. The decrease in construction commitments from December 31, 2013 to March 31, 2014 is mainly for OTP’s share of commitments related to the construction of the Big Stone Plant AQCS pertaining to materials and services ordered or under contract as of December 31, 2013 that were received in the first quarter of 2014.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending through 2038. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. 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, 2015, 2016 and 2040. OTP entered into no additional agreements for the purchase of capacity or to meet energy requirements or for the purchase of coal to meet its remaining coal requirements in the first quarter of 2014.

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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 March 31, 2014 will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of March 31, 2014 and December 31, 2013:

(in thousands)	Line Limit		In Use on March 31, 2014		Restricted due to Outstanding Letters of Credit		Available on March 31, 2014		Available on December 31, 2013
Otter Tail Corporation Credit Agreement	$	150,000	$	11,899	$	659	$	137,442	$	149,341
OTP Credit Agreement		170,000		--		3,830		166,170		116,975
Total	$	320,000	$	11,899	$	4,489	$	303,612	$	266,316

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 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 Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes.

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 Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B 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 OTP 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 became 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.

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On February 27, 2014 OTP used a portion of the proceeds of the Notes to retire OTP’s $40.9 million unsecured term loan under a Credit Agreement with JPMorgan Chase Bank, N.A., and to repay $82.5 million of short-term debt then outstanding under OTP’s Second Amended and Restated Credit Agreement (the OTP Credit Agreement). Remaining proceeds of the Notes will be used to fund OTP 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 March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	11,899	$	11,899
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
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 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
Other Obligations - Various up to 3.95% at March 31, 2014		--		1,502		1,502
Total	$	445,000	$	53,832	$	498,832
Less: Current Maturities		--		191		191
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,640	$	498,640
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	65,730	$	510,730

December 31, 2013 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	51,195	$	--	$	51,195
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			$	52,330		52,330
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 December 31, 2013		--		1,548		1,548
Total	$	335,900	$	53,878	$	389,778
Less: Current Maturities		--		188		188
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	335,900	$	53,689	$	389,589
Total Short-Term and Long-Term Debt (with current maturities)	$	387,095	$	53,877	$	440,972

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12. Pension Plan and Other Postretirement Benefits

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	1,175		$	1,418
Interest Cost on Projected Benefit Obligation		3,285			3,036
Expected Return on Assets		(4,187	)		(3,632	)
Amortization of Prior-Service Cost:
From Regulatory Asset		64			83
From Other Comprehensive Income1		2			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		868			1,663
From Other Comprehensive Income1		23			45
Net Periodic Pension Cost	$	1,230		$	2,615
1Corporate cost included in other nonelectric expenses.

Cash flows—The Company made discretionary plan contributions totaling $20,000,000 in January 2014. The Company currently is not required and does not expect to make an additional contribution to the plan in 2014. The Company also made a discretionary plan contribution of $10,000,000 in January 2013.

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	13		$	13
Interest Cost on Projected Benefit Obligation		380			352
Amortization of Prior-Service Cost:
From Regulatory Asset		5			5
From Other Comprehensive Income1		13			13
Amortization of Net Actuarial Loss:
From Regulatory Asset		35			52
From Other Comprehensive Income2		12			78
Net Periodic Pension Cost	$	458		$	513
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5		$	5
Other Nonelectric Expenses		8			8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	33		$	48
Other Nonelectric Expenses		(21	)		30

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	315		$	441
Interest Cost on Projected Benefit Obligation		558			610
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		--			248
From Other Comprehensive Income1		--			6
Net Periodic Postretirement Benefit Cost	$	925		$	1,357
Effect of Medicare Part D Subsidy	$	(308	)	$	(564	)
1 Corporate 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 obligations are short-term and the balances outstanding as of March 31, 2014 related to the Otter Tail Corporation Credit Agreement and December 31, 2013 related to the OTP Credit Agreement were subject to a variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.

Long-Term Debt including Current Maturities—The fair value of the Company’s and OTP’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, Fair Value Measurement.

	March 31, 2014						December 31, 2013
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	6,613		$	6,613		$	1,150		$	1,150
Short-Term Debt	$	(11,899	)	$	(11,899	)		(51,195	)		(51,195	)
Long-Term Debt including Current Maturities	$	(498,831	)	$	(546,269	)		(389,777	)		(427,796	)

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 periods ended March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands)	2014			2013
Income Before Income Taxes – Continuing Operations	$	29,650		$	21,120
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		11,563			8,237
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(2,252	)		(1,589	)
Section 199 Domestic Production Activities Deduction		(358	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(223	)
Employee Stock Ownership Plan Dividend Deduction		(189	)		(190	)
AFUDC Equity		(133	)		(115	)
Corporate Owned Life Insurance		(112	)		(302	)
Other Items – Net		(19	)		68
Income Tax Expense – Continuing Operations	$	8,288		$	5,886
Effective Income Tax Rate – Continuing Operations		28.0	%		27.9	%

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

(in thousands)	2014		2013
Balance on January 1	$	4,239	$	4,436
Increases Related to Tax Positions for Prior Years		137		--
Uncertain Positions Adjusted During Year		--		--
Balance on March 31	$	4,376	$	4,436

The balance of unrecognized tax benefits as of March 31, 2014 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2014 is not expected to change significantly within the next twelve 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 March 31, 2014.

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The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of March 31, 2014, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2010. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at March 31, 2014 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014.

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 former wind tower manufacturing company and on February 29, 2012 the Company completed the sale of DMS Health Technologies, Inc. (DMS) and recorded an additional $0.2 million gain on the sale in the first quarter of 2013 related to a working capital true up. Following are summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2014 and 2013, which mainly includes residual revenues and expenses from the Company’s former wind tower and waterfront equipment manufacturers and the additional $0.2 million gain on the sale of DMS in the first quarter of 2013:

	For the Three Months Ended March 31,
(in thousands)	2014			2013
Operating Revenues	$	--		$	2,009
Operating Expenses		(117	)		2,707
Operating Income (Loss)		117			(698	)
Other Income		--			412
Income Tax Benefit		(49	)		(205	)
Net Income (Loss) from Operations		68			(81	)
Gain on Disposition Before Taxes		--			216
Income Tax Expense on Disposition		--			6
Net Gain on Disposition		--			210
Net Income	$	68		$	129

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2014 and December 31, 2013:

(in thousands)	March 31, 2014		December 31, 2013
Current Assets	$	38	$	38
Assets of Discontinued Operations	$	38	$	38
Current Liabilities	$	3,442	$	3,637
Liabilities of Discontinued Operations	$	3,442	$	3,637

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

(in thousands)	2014			2013
Warranty Reserve Balance, January 1	$	3,087		$	5,027
Provision for Warranties Used During the Year		--			120
Less Settlements Made During the Year		--			(583	)
Decrease in Warranty Estimates for Prior Years		(100	)		(63	)
Warranty Reserve Balance, March 31	$	2,987		$	4,501

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The warranty reserve balances as of March 31, 2014 and December 31, 2013 relate 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.

18. Subsequent Events

2014 Stock Incentive Plan

On April 14, 2014 the Company’s shareholders approved the Company’s 2014 Stock Incentive Plan. The Company’s 2014 Stock Incentive Plan allows the Company to provide compensation through various stock-based arrangements. The material terms of the 2014 Stock Incentive Plan are disclosed in the Company’s Proxy Statement for its 2014 Annual Meeting of Shareholders filed with the Securities and Exchange Commission (SEC) on March 3, 2014. The 2014 Stock Incentive Plan was filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-8 filed with the SEC on April 17, 2014.

Stock Incentive Awards

On April 14, 2014 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 2014 Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Restricted Stock Granted to Nonemployee Directors		16,800	$	29.41	25% per year through April 8, 2018
Restricted Stock Granted to Executive Officers		26,700	$	29.41	25% per year through April 8, 2018
Stock Performance Awards Granted to Executive Officers		115,200	$	22.94	December 31, 2016
Restricted Stock Units Granted to Employees		11,800	$	24.95	100% on April 8, 2018

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 150,400 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, 2014 through December 31, 2016. The aggregate target share award is 115,200 shares. Actual payment may range from zero to 150% 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 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, Stock Compensation (ASC 718), and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

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

Under the terms of the award agreements, all outstanding (unvested) shares or units held by a retiring grantee vest immediately on normal retirement. When the Company is made aware of a retirement or pending retirement, the Company accelerates recognition of compensation expense related to the unvested awards to correspond with the remaining service period of the grantee, in accordance with the requirements of ASC 718.

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

RESULTS OF OPERATIONS

Following is an analysis of the operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three months ended March 31, 2014 and 2013, followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2014 and our business outlook for the remainder of 2014.

Comparison of the Three Months Ended March 31, 2014 and 2013

Consolidated operating revenues were $240.5 million for the three months ended March 31, 2014 compared with

$218.0 million for the three months ended March 31, 2013. Operating income was $34.4 million for the three months ended March 31, 2014 compared with $27.2 million for the three months ended March 31, 2013. The Company recorded diluted earnings per share from continuing operations and total diluted earnings per share of $0.59 for the three months ended March 31, 2014 compared to $0.41 for the three months ended March 31, 2013.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and construction revenues earned and other nonelectric operating expenses for the three month periods ended March 31, 2014 and 2013 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	March 31, 2014		March 31, 2013
Operating Revenues:
Electric	$	40	$	34
Nonelectric		--		13
Cost of Products Sold		2		12
Cost of Construction Revenues Earned		--		1
Other Nonelectric Expenses		38		34

Electric

	Three Months Ended
	March 31,								%
(in thousands)	2014			2013		Change			Change
Retail Sales Revenues	$	105,504		$	92,323	$	13,181			14.3
Wholesale Revenues – Company Generation		4,900			1,633		3,267			200.1
Net Revenue – Energy Trading Activity		(269	)		345		(614	)		(178.0	)
Other Revenues		8,953			6,709		2,244			33.4
Total Operating Revenues	$	119,088		$	101,010	$	18,078			17.9
Production Fuel		22,030			17,953		4,077			22.7
Purchased Power – System Use		21,785			16,639		5,146			30.9
Other Operation and Maintenance Expenses		34,622			32,447		2,175			6.7
Depreciation and Amortization		10,763			10,631		132			1.2
Property Taxes		2,971			2,916		55			1.9
Operating Income	$	26,917		$	20,424	$	6,493			31.8
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,397,891			1,310,312		87,579			6.7
Wholesale kwh Sales – Company Generation		73,305			64,345		8,960			13.9
Wholesale kwh Sales – Purchased Power Resold		1,611			13,789		(12,178	)		(88.3	)
Heating Degree Days		4,089			3,671		418			11.4

Retail sales revenue increased $13.2 million as a result of:

● a $5.7 million increases in fuel clause adjustment revenues and fuel and purchased power costs recovered in base rates, driven by an 8.2% increase in fuel costs per kwh generated at Otter Tail Power Company’s (OTP) fuel fired generating units and a 43.2% increase in prices for power purchased to serve retail customers as a result of higher demand due to colder weather in the first quarter of 2014 compared to the first quarter of 2013,

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● a $3.4 million increase in revenues related to the 6.7% increase in retail kwh sales, of which: $1.8 million is attributed to colder weather in 2014, $0.8 million is related to increased sales to a pipeline customerand approximately $0.8 million is from increased sales to residential and commercial customers due, in part, to improved economic conditions and customer growth in OTP’s service territory,

● a $2.6 million increase in Environmental Cost Recovery rider revenues related to earning a return in Minnesota and North Dakota on increasing amounts invested in the Air Quality Control System (AQCS) under construction at Big Stone Plant, and

● a $2.3 million increase in Transmission Cost Recovery rider revenues resulting from increased investment in transmission lines,

offset by:

● a $0.9 million decrease in Renewable Resource Adjustment (RRA) rider revenues in North Dakota as a result of: (1) declining book values of renewable assets due to depreciation and (2) reduced RRA revenue requirements related to earning more federal Production Tax Credits (PTCs) as a result of a 33.0% increase in kwhs generated by OTP’s wind turbines eligible for PTCs.

Net revenue from energy trading activities, including net mark-to-market gains and losses on forward energy contracts, decreased $0.6 million mainly as a result of decreased trading activity and the incurrence of losses on contracts entered into and settled in the first quarter of 2014.

Wholesale electric revenues from company-owned generation increased $3.3 million as a result of a 163% increase in revenue per wholesale kwh sold and a 13.9% increase in wholesale kwhs sold. The increase in wholesale kwh sales and prices was driven by increased wholesale market demand resulting from colder weather in the first quarter of 2014. OTP was able to serve the higher demand of both wholesale and retail customers as a result of improved availability of Coyote Station, which was shut down for generator repairs during the first seven weeks of 2013, and as a result of the 30.9% increase in kwhs generated from OTP’s wind turbines.

Other electric operating revenues increased $2.2 million, reflecting:

● a $1.4 million increase in Midcontinent Independent System Operator, Inc. (MISO) tariff revenues resulting from increased investment in regional transmission lines and returns on and recovery of CapX2020 and MISO-designated Multi-Value Project (MVP) investment costs and operating expenses, and

● a $0.8 million increase in revenue from various other sources including a $0.3 million increase in transmission related revenue under an integrated transmission agreement and a $0.2 million increase in revenue from steam sales at Big Stone Plant.

Production fuel costs increased $4.1 million as a result of a 13.4% increase in kwhs generated from OTP’s steam-powered and combustion turbine generators in combination with an 8.2% increase in the cost of fuel per kwh generated. The increase in kwh generation was facilitated by the improved availability of Coyote Station.

The cost of purchased power to serve retail customers increased $5.1 million due to a 43.2% increase in costs per kwh purchased, partially offset by an 8.5% decrease in kwhs purchased. The increase in costs per kwh purchased was driven by increased wholesale market demand resulting from colder weather.

Electric operating and maintenance expenses increased $2.2 million as a result of:

● a $1.2 million increase in MISO transmission tariff charges related to increasing investments in regional CapX2020 projects and MISO-designated MVPs,

● a $1.2 million increase in labor costs due to increased wages and hours worked and accrued incentives related to OTP’s improved performance quarter over quarter, and

● increases of $0.1 million to $0.2 million in each of the following categories of expense: generating plant material and supplies, electric grid software maintenance, travel expenses, regulatory assessment charges and insurance premiums,

offset by:

● a $1.3 million decrease in labor loading charges as a result of a reduction in pension and postretirement benefit costs related to an increase in discount rates and pension fund contributions.

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Manufacturing

	Three Months Ended
	March 31,							%
(in thousands)	2014		2013		Change			Change
Operating Revenues	$	55,435	$	53,166	$	2,269			4.3
Cost of Products Sold		42,199		39,326		2,873			7.3
Operating Expenses		5,225		4,498		727			16.2
Depreciation and Amortization		2,620		2,993		(373	)		(12.5	)
Operating Income	$	5,391	$	6,349	$	(958	)		(15.1	)

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 $4.9 million mainly as a result of increased sales to manufacturers of recreational equipment.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $2.6 million, mainly due to a significant reduction in sales of a high volume product that a customer began producing on its own in 2014.

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

● Cost of products sold at BTD increased $4.9 million as a result of increased material costs related to an increase in sales volume and increases in support salaries, wages and product handling costs to support anticipated sales growth in 2014.

● Cost of products sold at T.O. Plastics decreased $2.0 million as a result of decreased material costs related to T.O. Plastics lower sales volume.

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

● Operating expenses at BTD increased $0.7 million due to increases in administrative and general expenses related to increased labor and benefit costs.

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

Depreciation expense decreased $0.3 million at BTD as a result of certain assets reaching the end of their depreciable lives.

Plastics

	Three Months Ended
	March 31,							%
(in thousands)	2014		2013		Change			Change
Operating Revenues	$	40,483	$	37,400	$	3,083			8.2
Cost of Products Sold		31,742		28,473		3,269			11.5
Operating Expenses		2,117		1,436		681			47.4
Depreciation and Amortization		853		774		79			10.2
Operating Income	$	5,771	$	6,717	$	(946	)		(14.1	)

The increase in Plastics segment revenue is the result of a 10.3% increase in pounds of polyvinyl chloride (PVC) pipe sold, partially offset by a 1.8% decrease in the price per pound of pipe sold. States with significant increases in sales were Colorado, California, Arizona, Nevada, Texas and Minnesota. Cost of products sold increased by $3.3 million, mostly due to the increase in sales volume, but also due to a 1.1% increase in the cost per pound of pipe sold related to higher PVC resin costs. A $0.7 million increase in operating expenses, mainly related to increased wage and benefit costs, in combination with the $0.2 million reduction in gross margins resulted in the $0.9 million decline in Plastics segment operating income between the quarters.

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Construction

	Three Months Ended
	March 31,									%
(in thousands)	2014			2013			Change			Change
Operating Revenues	$	25,506		$	26,425		$	(919	)		(3.5	)
Cost of Construction Revenues Earned		22,362			24,276			(1,914	)		(7.9	)
Operating Expenses		3,850			3,386			464			13.7
Depreciation and Amortization		512			462			50			10.8
Operating Loss	$	(1,218	)	$	(1,699	)	$	481			28.3

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

● Revenues at Foley Company (Foley), a mechanical and prime contractor on industrial projects, decreased $1.8 million mainly as a result of a reduction in work volume between the quarters, but Foley’s profitability and performance improved on jobs in progress in the first quarter of 2014.

● Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, increased $0.9 million between the quarters as a result of a higher volume of electrical transmission, distribution, substation and underground work in 2014, despite challenging weather conditions.

The decrease in cost of construction revenues earned in our Construction segment relates to the following:

● Cost of construction revenues earned at Foley decreased $2.8 million mainly as a result of the reduction in material costs and lower work volume.

● Cost of construction revenues earned at Aevenia increased $0.8 million between the quarters as a result of increased material and labor costs related to an increase in construction activity at Aevenia.

Foley’s operating expenses for wages and benefits increased $0.5 million between the quarters, due in part to bonuses and in part to severance payments related to workforce reductions.

Corporate

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

	Three Months Ended
	March 31,							%
(in thousands)	2014		2013		Change			Change
Operating Expenses	$	2,407	$	4,492	$	(2,085	)		(46.4	)
Depreciation and Amortization		32		60		(28	)		(46.7	)

Corporate operating expenses decreased $2.1 million reflecting:

● a $1.0 million reduction in benefit costs, mainly related to stock-based compensation costs which were higher in the first quarter of 2013 as a result of a 24% increase in the market value of the Company’s common stock in that quarter,

● a $0.9 million increase in corporate operating expenses allocated or directly charged to the corporation’s operating segments, and

● a $0.2 million decrease in general insurance and contracted services fees.

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Interest Charges

The $385,000 decrease in interest charges in the first three months of 2014 compared with the first three months of 2013, reflects:

● a $1,073,000 reduction in interest expense related to the early retirement of $47.7 million of our 9.0% unsecured notes due December 15, 2016, in November 2013,

offset by:

● a $644,000 increase in interest expense related to the February 27, 2014 issuance of $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044.

Other Income

The $1.0 million increase in other income in the three months ended March 31, 2014 compared with the three months ended March 31, 2013 includes a $0.8 million gain on the sale of an investment in tax-credit-qualified low income housing rental property, and a $0.3 million gain on the sale of Aevenia’s data communication installation and services business, both sold in the first quarter of 2014.

Income Taxes – Continuing Operations

Income taxes - continuing operations increased $2.4 million in the first quarter of 2014 compared with the first quarter of 2013.

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 March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands)	2014			2013
Income Before Income Taxes – Continuing Operations	$	29,650		$	21,120
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		11,563			8,237
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(2,252	)		(1,589	)
Section 199 Domestic Production Activities Deduction		(358	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(223	)
Employee Stock Ownership Plan Dividend Deduction		(189	)		(190	)
AFUDC Equity		(133	)		(115	)
Corporate Owned Life Insurance		(112	)		(302	)
Other Items – Net		(19	)		68
Income Tax Expense – Continuing Operations	$	8,288		$	5,886
Effective Income Tax Rate – Continuing Operations		28.0	%		27.9	%

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 33.0% in the three months ended March 31, 2014 compared with the three months ended March 31, 2013. 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.

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Discontinued Operations

On February 8, 2013 we completed the sale of substantially all the assets of our former waterfront equipment manufacturing company, formerly included in our 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 we completed the sale of the assets of our former wind tower manufacturing company and on February 29, 2012 we completed the sale of DMS Health Technologies, Inc. (DMS) and recorded an additional $0.2 million gain on the sale in the first quarter of 2013 related to a working capital true up. Following are summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2014 and 2013, which mainly includes residual revenues and expenses from our former wind tower and waterfront equipment manufacturers and the additional $0.2 million gain on the sale of DMS in the first quarter of 2013:

	For the Three Months Ended March 31,
(in thousands)	2014			2013
Operating Revenues	$	--		$	2,009
Operating Expenses		(117	)		2,707
Operating Income (Loss)		117			(698	)
Other Income		--			412
Income Tax Benefit		(49	)		(205	)
Net Income (Loss) from Operations		68			(81	)
Gain on Disposition Before Taxes		--			216
Income Tax Expense on Disposition		--			6
Net Gain on Disposition		--			210
Net Income	$	68		$	129

FINANCIAL POSITION

The following table presents the status of our lines of credit as of March 31, 2014 and December 31, 2013:

(in thousands)	Line Limit		In Use on March 31, 2014		Restricted due to Outstanding Letters of Credit		Available on March 31, 2014		Available on December 31, 2013
Otter Tail Corporation Credit Agreement	$	150,000	$	11,899	$	659	$	137,442	$	149,341
OTP Credit Agreement		170,000		--		3,830		166,170		116,975
Total	$	320,000	$	11,899	$	4,489	$	303,612	$	266,316

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, which expires on May 10, 2015. On May 14, 2012, we entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million.

Equity or debt financing will be required in the period 2014 through 2018 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.

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Our common stock dividend payments have exceeded our net income (losses) in four 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, 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 that are allowed to be made by our subsidiaries. See note 8 to condensed consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the Board of Directors. On February 3, 2014 our Board of Directors increased the quarterly dividend from $0.2975 to $0.3025 per common share.

Cash used in operating activities of continuing operations was $18.9 million for the three months ended March 31, 2014 compared with cash provided by operating activities of continuing operations of $10.2 million for the three months ended March 31, 2013. Contributing to the $29.1 million shift in cash provided by operating activities in the first quarter of 2013 to cash used in operating activities in the first quarter of 2014 was a $21.2 million increase in cash used for working capital items from $22.9 million in the first quarter of 2013 to $44.1 million in the first quarter of 2014, and a $10.0 million increase in discretionary contributions to our pension plan between the quarters. Accounts receivable and inventories in the Plastics segment increased $19.3 million in the first quarter of 2014 compared with an increase of $9.2 million in the first quarter of 2013. The greater increase in receivables and inventories in the Plastic segment in 2014 corresponds with a 10.3% increase in sales volume, 8.2% increase in revenues and higher material and labor costs between the quarters. Foley’s accounts payable and billings in excess of costs decreased $9.2 million in the first quarter of 2014 compared with a $1.3 million increase in accounts payable and billings in excess of costs in the first quarter of 2013.

Net cash used in investing activities of continuing operations was $37.2 million for the three months ended March 31, 2014 compared to $23.5 million for the three months ended March 31, 2013 due to a $14.4 million increase in cash used for capital expenditures in the Electric segment between the quarters, as construction of the Big Stone Plant AQCS remains on pace and OTP continues to invest in major transmission grid upgrades and improvements. Net proceeds from the sale of discontinued operations of $10.5 million in the first quarter of 2013 reflect $12.2 million in net proceeds from the sale of the assets of our former waterfront equipment manufacturer net of a $1.7 million working capital settlement paid to the buyer of DMS, which we sold in the first quarter of 2012.

Net cash provided by financing activities in the three months ended March 31, 2014 of $61.7 million compares with net cash used in investing activities in the three months ended March 31, 2014 of $8.6 million. Net cash provided by financing activities in the first quarter of 2014 mainly reflects the issuance by OTP of $150 million in privately placed unsecured notes in two series on February 27, 2014, and the use of a portion of the proceeds of the notes to retire OTP’s $40.9 million unsecured term loan and to repay short-term debt outstanding under the OTP Credit Agreement which was being used to finance OTP’s construction activities. First quarter 2014 financing activities also reflect the payment of $11.0 million in common stock dividends, OTP’s repayment of $51.2 million in short-term debt outstanding under the OTP Credit Agreement on December 31, 2013 and the borrowing of $11.9 million under the Otter Tail Corporation Credit Agreement to fund the working capital needs of our manufacturing and infrastructure companies. First quarter 2014 financing cash flows also include $3.7 million in cash proceeds from the issuance of common stock. In the first quarter of 2014, we began issuing common shares to meet the requirements of our dividend reinvestment and share purchase plan, employee stock ownership plan, and employee stock purchase plan, rather than purchasing shares in the open market.

Net cash used in financing activities of continuing operations in the three months ended March 31, 2013 of $8.6 million reflects $2.5 million in proceeds from short-term borrowings and the issuance of common stock offset by $11.3 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 the Company that mirrored the Company’s $15.5 million in outstanding cumulative preferred shares, which were also redeemed on March 1, 2013.

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CAPITAL REQUIREMENTS

2014-2018 Capital Expenditures

The following table shows our 2013 capital expenditures and 2014 through 2018 anticipated capital expenditures and electric utility average rate base:

(in millions)	2013 Actual		2014		2015		2016		2017		2018
Capital Expenditures:
Electric Segment:
Transmission			$	53	$	46	$	97	$	52	$	56
Environmental				82		61		--		--		--
Other				37		38		44		45		46
Total Electric Segment	$	149	$	172	$	145	$	141	$	97	$	102
Manufacturing and Infrastructure Segments		15		23		19		26		20		24
Total Capital Expenditures	$	164	$	195	$	164	$	167	$	117	$	126
Total Electric Utility Average Rate Base			$	885	$	991	$	1,062	$	1,120	$	1,152

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 2014 through 2018 timeframe.

Ashtabula III Wind Farm

OTP has a purchased wind power agreement with the owner of the Ashtabula III wind farm. In connection with this agreement, OTP has the option to purchase the wind farm for approximately $50 million in the 2023 timeframe.

Contractual Obligations

Our contractual obligations reported in the table on page 53 of our Annual Report on Form 10-K for the year ended December 31, 2013 increased $340 million in the first quarter of 2014. Our long-term debt obligations increased $150 million for the years beyond 2018 and our interest obligations on long-term debt increased by $3.9 million for 2014, $15.5 million for 2015 and 2016, $15.5 million for 2017 and 2018 and $155 million for the years beyond 2018 as a result of OTP’s February 27, 2014 borrowings under OTP’s 2013 Note Purchase Agreement. Our purchase obligations did not increase and OTP entered into no new coal, capacity or energy purchase agreements in the first quarter of 2014.

CAPITAL RESOURCES

Short-Term Debt

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $150 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 29, 2013 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2017 to October 29, 2018. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of our subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our senior unsecured credit ratings. The interest rate being charged under the Second Amended and Restated Credit Agreement prior to the renewal was LIBOR plus 3.25%. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on us and the businesses of the Company’s wholly-owned subsidiary, Varistar Corporation, 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 Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our material subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

42

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 that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 29, 2013 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2017 to October 29, 2018. 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, and financial covenants as described below under the heading “Financial Covenants.” 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.

Long-Term Debt

2016 Notes

On December 4, 2009 we issued $100 million of our 9.000% notes due 2016 (the 2016 Notes) under the indenture (for unsecured debt securities) dated as of November 1, 1997, as amended by the First Supplemental Indenture dated as of July 1, 2009, between us and U.S. Bank National Association (formerly First Trust National Association), as trustee. The 2016 Notes are senior unsecured indebtedness and bear interest at 9.000% per year, payable semi-annually in arrears on June 15 and December 15 of each year. In November 2013 we purchased and retired, in two separate transactions, $12,933,000 and $34,737,000, respectively, of our outstanding 2016 Notes. The remaining $52,330,000 principal amount of the 2016 Notes outstanding, unless previously redeemed or otherwise repaid, will mature and become due and payable on December 15, 2016.

2013 Note Purchase Agreement

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 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 Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes.

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 Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B 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 OTP 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, including 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 as described below under the heading “Financial Covenants.” 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.

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2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes) pursuant to a Note Purchase Agreement dated as of July 29, 2011 (2011 Note Purchase Agreement). OTP used a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of OTP’s 6.63% Senior Notes due December 1, 2011 at maturity and to retire early $10.4 million aggregate principal amount of outstanding pollution control refunding revenue bonds due December 1, 2012. No penalty was paid for the early retirement. The remaining proceeds of the 2021 Notes were used to repay short-term debt of OTP which was issued to fund capital expenditures, to pay fees and expenses related to the debt issuance and to fund a $10 million contribution to the Company’s pension plan in January 2012.

OTP also has outstanding its $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 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

The 2011 Note Purchase Agreement and the 2007 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 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including 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 note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of March 31, 2014.

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

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

● Under the Otter Tail Corporation Credit Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the Otter Tail Corporation Credit Agreement. As of March 31, 2014 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 4.24 to 1.00.

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

● 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 March 31, 2014 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 4.04 to 1.00.

● 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 Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement.

As of March 31, 2014 our interest-bearing debt to total capitalization was 0.48 to 1.00 on a consolidated basis and 0.53 to 1.00 for OTP.

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OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $9.9 million, but our line of credit borrowing limits are only restricted by $4.5 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.

2014 BUSINESS OUTLOOK

We are increasing our consolidated diluted earnings per share guidance for 2014 to be in the range of $1.60 to $1.80 from our previously announced range of $1.55 to $1.75. This updated guidance reflects the current mix of businesses owned by us. It considers the cyclical nature of some of our businesses and reflects challenges, as well as our plans and strategies for improving future operating results.

Segment components of our 2014 earnings per share guidance range are as follows:

	Previous 2014 EPS Guidance		Current 2014 EPS Guidance
	Low	High	Low	High
Electric	$1.19	$1.23	$1.21	$1.25
Manufacturing	$0.29	$0.33	$0.29	$0.33
Plastics	$0.25	$0.29	$0.27	$0.31
Construction	$0.07	$0.11	$0.07	$0.11
Corporate	($0.25)	($0.21)	($0.24)	($0.20)
Total – Continuing Operations	$1.55	$1.75	$1.60	$1.80

Contributing to our updated earnings guidance for 2014 are the following items:

● We expect 2014 net income for our Electric segment to increase from our previously issued guidance primarily as a result of the strong first quarter results driven in part by colder than normal weather. Items affecting our 2014 Electric segment earnings guidance compared with 2013 earnings include:

o Rider recovery increases, including environmental riders in Minnesota and North Dakota related to the Big Stone AQCS environmental upgrades while under construction, and

o A decrease in pension costs of approximately $2.0 million as a result of an increase in the discount rate from 4.5% to 5.3%, offset by

o An increase in interest costs as a result of $150 million of fixed rate long term debt put in place in the first quarter of 2014 to finance the Big Stone Plant AQCS and transmission projects, and

o An increase in operating and maintenance costs primarily for increased labor and a planned outage for maintenance at Hoot Lake Plant.

● We are maintaining our original 2014 earnings expectations for our Manufacturing segment, which we expect to be unchanged from 2013 results due to the following factors:

o An increase at BTD due to increased order volume as a result of expanded relationships with customers in recreational vehicle, lawn and garden, industrial and commercial end markets BTD serves, offset by

o A decrease in earnings from T.O. Plastics due to a reduction in sales of a product the customer will be producing on its own in 2014.

o Backlog for the manufacturing companies of approximately $115 million for 2014 compared with $97 million one year ago.

● We are raising our expectations for 2014 net income for our Plastics segment from our original guidance due to a stronger than expected first quarter.

● We are maintaining our original 2014 guidance for our Construction segment. Net income is expected to be higher in 2014 than in 2013 as a result of improved cost control processes in construction management and more selective bidding on projects with the potential for higher margins. Backlog in place for the construction businesses is $85 million for 2014 compared with $100 million one year ago.

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● Corporate costs are expected to be slightly lower than original guidance as a result of the sale of an investment in tax-credit-qualified low income housing rental property, which was not expected when our original guidance was given, and improved performance in our self-insured health plan.

We review our portfolio of companies at least annually to see where additional opportunities exist to improve our risk profile, improve credit metrics and generate additional sources of cash to support the future capital expenditure plans of our Electric segment.

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 60 through 64 of our Annual Report on Form 10-K for the year ended December 31, 2013. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2014.

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.These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, as well as the various factors described below:

● 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 $20.0 million in discretionary contributions to our defined benefit pension plan in January 2014. We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

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

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● Declines in projected operating cash flows at any of our reporting units may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

● 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 net earnings improved $10.4 million between 2012 and 2013. If future expected operating profits do not meet the corporation’s projections, the reductions in anticipated cash flows from Foley may indicate its fair value is less than its book value, resulting in an impairment of some or all of the goodwill and indefinite-lived intangible assets 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 or cyber-attacks 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.

● 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.

● 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

At March 31, 2014 we had exposure to market risk associated with interest rates because we had $11.9 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 1.75% under the our $150 million revolving credit facility.

All of our consolidated long-term debt outstanding on March 31, 2014 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

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

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 plastics resins. 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 March 31, 2014 OTP had recognized, on a pretax basis, $39,000 in unrealized gains on open forward contracts for sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can cause transmission constraints that result in unanticipated gains or losses in the process of settling transactions.

The market prices used to value OTP’s forward contracts for the purchases and sales of electricity and electricity generating capacity are determined by survey of counterparties or brokers used by OTP’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange and the CME Globex. For certain contracts, prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The forward energy sales contracts that are marked to market as of March 31, 2014 are not offset by forward energy purchase contracts. Therefore, the $39,000 in unrealized gains related to these contracts of as of March 31, 2014 are subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in April and May of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the fair value of the contracts.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. Volumetric limits and loss limits are used to adequately manage the risks associated with our energy trading activities. Additionally, we have a Value at Risk (VaR) limit to further manage market price risk. There was price risk on open positions as of March 31, 2014.

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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 March 31, 2014 and December 31, 2013, and the change in our consolidated balance sheet position from December 31, 2013 to March 31, 2014 and December 31, 2012 to March 31, 2013:

(in thousands)	March 31, 2014			December 31, 2013
Current Asset – Marked-to-Market Gain	$	1,609		$	338
Regulatory Asset – Current Deferred Marked-to-Market Loss		3,258			3,008
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		4,994			8,674
Total Assets		9,861			12,020
Current Liability – Marked-to-Market Loss		(8,252	)		(11,782	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(533	)		(6	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(1,037	)		(117	)
Total Liabilities		(9,822	)		(11,905	)
Net Fair Value of Marked-to-Market Energy Contracts	$	39		$	115

(in thousands)	Year-to-Date March 31, 2014			Year-to-Date March 31, 2013
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	115		$	49
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
Changes in Fair Value of Contracts Entered into in Current Period		39			81
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	39		$	81

The $39,000 in recognized but unrealized gains on the forward energy sales contracts marked to market on March 31, 2014 are expected to be realized on settlement as scheduled in April and May of 2014.

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

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Net (Loss) Gain on Forward Electric Energy Contracts	$	(4	)	$	226

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. OTP’s credit risk with its largest counterparty on delivered and marked-to-market forward contracts as of March 31, 2014 was $83,000. As of March 31, 2014 OTP had a net credit risk exposure of $128,000 from three counterparties with investment grade credit ratings. OTP had no exposure at March 31, 2014 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 $128,000 credit risk exposure included net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after March 31, 2014. 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 March 31, 2014, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2014.

During the fiscal quarter ended March 31, 2014, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 28 through 35 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

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

The Company does not have a publicly announced stock repurchase program. The following table shows common shares that were surrendered to the Company by employees to pay taxes in connection with shares issued for incentive awards in February 2014 under the Company’s 1999 Stock Incentive Plan:

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
January 2014		--		--
February 2014		8,879	$	27.255
March 2014		--		--
Total		8,879

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Item 6.     Exhibits

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 March 31, 2014, 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: May 9, 2014

51

EXHIBIT INDEX

Exhibit Number         Description

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 March 31, 2014, 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: May 9, 2014

/s/ Edward J. McIntyre

Edward J. McIntyre

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: May 9, 2014

/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 March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward J. McIntyre, 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

Chief Executive Officer

May 9, 2014

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 March 31, 2014 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

May 9, 2014

XML

Summary of Significant Accounting Policies - Accounts receivable retained by customers pending project completion (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Accounts Receivable Retained by Customers	$ 6,352	$ 7,125	[1]

[1] Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

XML

Segment Information - Information on continuing operations for business segments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating Revenue	$ 240,472	$ 217,954
Interest Charges	6,595	6,980
Income Taxes	8,288	5,886
Earnings Available for Common Shares	21,430	14,850
Identifiable Assets	1,656,203		1,596,019
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(40)	(47)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	361	1,002
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(857)	(2,294)
Earnings Available for Common Shares	(1,027)	(3,323)
Identifiable Assets	53,631		59,970
Discontinued Operations
Segment Reporting Information [Line Items]
Earnings Available for Common Shares	68	129
Identifiable Assets	38		38
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	119,088	101,010
Interest Charges	5,079	4,808
Income Taxes	5,750	4,082
Earnings Available for Common Shares	16,653	11,931
Identifiable Assets	1,334,155		1,290,416
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	55,435	53,166
Interest Charges	808	815
Income Taxes	1,671	2,218
Earnings Available for Common Shares	2,896	3,318
Identifiable Assets	125,800		119,302
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	40,483	37,400
Interest Charges	247	248
Income Taxes	2,133	2,603
Earnings Available for Common Shares	3,460	3,887
Identifiable Assets	95,779		76,853
Construction | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	25,506	26,425
Interest Charges	100	107
Income Taxes	(409)	(723)
Earnings Available for Common Shares	(620)	(1,092)
Identifiable Assets	$ 46,800		$ 49,440

XML

Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 11) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$ 22,244	[1]	$ 8,901	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$ 3,434	[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.

XML

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 884	$ 1,489
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	42	17
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	123	207
Restricted Stock | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	135	92
Restricted Stock Units (RSUs) | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	58	75
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 526	$ 1,098

XML

Segment Information (Detail Textuals)	3 Months Ended
	Mar. 31, 2014 Segment
Segment Reporting [Abstract]
Number of reportable segments	4

XML

Short-Term and Long-Term Borrowings (Detail textuals) (Otter Tail Power Company, 2013 Note Purchase Agreement, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Feb. 27, 2014	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		$ 150	$ 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 Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B 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

Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 9) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 244	$ 244

XML

Income Tax Expense - Continuing Operations (Tables)

3 Months Ended

Mar. 31, 2014

Income Tax Disclosure [Abstract]

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Income Before Income Taxes – Continuing Operations	$	29,650		$	21,120
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		11,563			8,237
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(2,252	)		(1,589	)
Section 199 Domestic Production Activities Deduction		(358	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(223	)
Employee Stock Ownership Plan Dividend Deduction		(189	)		(190	)
AFUDC Equity		(133	)		(115	)
Corporate Owned Life Insurance		(112	)		(302	)
Other Items – Net		(19	)		68
Income Tax Expense – Continuing Operations	$	8,288		$	5,886
Effective Income Tax Rate – Continuing Operations		28.0	%		27.9	%

Schedule of activity related to unrecognized tax benefits

(in thousands)	2014		2013
Balance on January 1	$	4,239	$	4,436
Increases Related to Tax Positions for Prior Years		137		--
Uncertain Positions Adjusted During Year		--		--
Balance on March 31	$	4,376	$	4,436

XML

Short-Term and Long-Term Borrowings (Detail Textuals 1) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Feb. 27, 2014
Short-term Debt | OTP Credit Agreement
Debt Instrument [Line Items]
Repayments of debt	$ 82.5
Otter Tail Power Company | J P Morgan Chase Bank | Unsecured Term Loan
Debt Instrument [Line Items]
Repayments of debt	$ 40.9

XML

Retained Earnings Restriction (Detail Textuals) (USD $) In Thousands, unless otherwise specified			3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 OTP	Mar. 31, 2014 OTP Minimum	Mar. 31, 2014 OTP 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			47.20%
Total Capitalization	$ 1,048,314	$ 924,419			$ 874,000

XML

Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets of Discontinued Operations	$ 38	$ 38
Liabilities of Discontinued Operations	3,442	3,637
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	38	38
Assets of Discontinued Operations	38	38
Current Liabilities	3,442	3,637
Liabilities of Discontinued Operations	$ 3,442	$ 3,637

XML

Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	$ 20,199		$ 17,940
Regulatory Liability - Current	2,228		1,195
Net Regulatory Assets Position - Current	17,971		16,745
Regulatory Assets - Long-Term	78,839		83,730
Regulatory Liabilities - Long-Term	75,365		73,926
Net Regulatory Assets Position - Long-Term	3,474		9,804
Regulatory Assets - Total	99,038		101,670
Regulatory Liabilities - Total	77,593		75,121
Net Regulatory Asset Position - Total	21,445		26,549
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	4,043	[1]	4,095	[1]
Regulatory Assets - Long-Term	54,038	[1]	55,012	[1]
Regulatory Assets - Total	58,081	[1]	59,107	[1]
Regulatory Assets - Remaining Recovery/Refund Period	see note	[1]	see note	[1]
Deferred Marked-to-Market Loss
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	3,258	[1]	3,008	[1]
Regulatory Assets - Long-Term	4,994	[1]	8,674	[1]
Regulatory Assets - Total	8,252	[1]	11,682	[1]
Regulatory Assets - Remaining Recovery/Refund Period	57 months	[1]	60 months	[1]
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	3,533	[2]	4,945	[2]
Regulatory Assets - Long-Term	4,580	[2]	3,959	[2]
Regulatory Assets - Total	8,113	[2]	8,904	[2]
Regulatory Assets - Remaining Recovery/Refund Period	15 months	[2]	18 months
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Assets - Long-Term	4,779	[1]	4,646	[1]
Regulatory Assets - Total	4,779	[1]	4,646	[1]
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	566	[1]	558	[1]
Regulatory Assets - Long-Term	3,857	[1]	3,967	[1]
Regulatory Assets - Total	4,423	[1]	4,525	[1]
Regulatory Assets - Remaining Recovery/Refund Period	78 months	[1]	81 months	[1]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,452	[1]	1,351	[1]
Regulatory Assets - Long-Term	1,419	[1]	1,753	[1]
Regulatory Assets - Total	2,871	[1]	3,104	[1]
Regulatory Assets - Remaining Recovery/Refund Period	21 months	[1]	24 months	[1]
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	361	[1]	351	[1]
Regulatory Assets - Long-Term	2,154	[1]	2,241	[1]
Regulatory Assets - Total	2,515	[1]	2,592	[1]
Regulatory Assets - Remaining Recovery/Refund Period	222 months	[1]	225 months	[1]
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]		[2]
Regulatory Assets - Long-Term	119	[2]	762	[2]
Regulatory Assets - Total	119	[2]	762	[2]
Regulatory Assets - Remaining Recovery/Refund Period	24 months	[2]	15 months	[2]
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	2,013	[1]	1,805	[1]
Regulatory Liabilities - Long-Term	1,869		1,960
Regulatory Assets - Total	2,013	[1]	1,805	[1]
Regulatory Liabilities - Total	1,869		1,960
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
Minnesota Transmission Rider Accrued Revenue
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,153	[2]
Regulatory Assets - Long-Term		[2]
Regulatory Assets - Total	1,153	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	101	[2]	101	[2]
Regulatory Assets - Long-Term	818	[2]	843	[2]
Regulatory Assets - Total	919	[2]	944	[2]
Regulatory Assets - Remaining Recovery/Refund Period	110 months	[2]	113 months	[2]
Big Stone II Unrecovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			375	[1]
Regulatory Assets - Long-Term				[1]
Regulatory Assets - Total			375	[1]
Regulatory Assets - Remaining Recovery/Refund Period			3 months	[1]
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	3,540	[1]	760	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	3,540	[1]	760	[1]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[1]	12 months	[1]
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term	71,943		71,454
Regulatory Liabilities - Total	71,943		71,454
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	533		6
Regulatory Liabilities - Long-Term	1,037		117
Regulatory Liabilities - Total	1,570		123
Regulatory Liabilities - Remaining Recovery/Refund Period	53 months		56 months
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	21		38
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	21		38
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	1,436		261
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	1,436		261
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
South Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	107	[2]	32	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	107	[2]	32	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	12 months	[2]
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]		[2]
Regulatory Assets - Long-Term	68	[2]	68	[2]
Regulatory Assets - Total	68	[2]	68	[2]
Regulatory Assets - Remaining Recovery/Refund Period	see note	[2]	see note	[2]
Deferred Holding Company Formation Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	14	[1]	27	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	14	[1]	27	[1]
Regulatory Assets - Remaining Recovery/Refund Period	3 months	[1]	6 months	[1]
Minnesota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			670
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			670
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Revenue for Rate Case expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term	412		289
Regulatory Liabilities - Total	412		289
Regulatory Liabilities - Remaining Recovery/Refund Period	see note		see note
Big Stone II Over Recovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	144
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	144
Regulatory Liabilities - Remaining Recovery/Refund Period	6 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	6		5
Regulatory Liabilities - Long-Term	104		106
Regulatory Liabilities - Total	110		111
Regulatory Liabilities - Remaining Recovery/Refund Period	237 months		240 months
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	56
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	56
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
North Dakota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	32		215
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	32		215
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
General Rate Case Recoverable Expenses - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			6	[1]
Regulatory Assets - Long-Term				[1]
Regulatory Assets - Total			6	[1]
Regulatory Assets - Remaining Recovery/Refund Period			1 month	[1]
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,071	[2]	2,331	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	$ 2,071	[2]	$ 2,331	[2]
Regulatory Assets - Remaining Recovery/Refund Period	15 months	[2]	12 months	[2]

[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.

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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	Mar. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Short-Term Debt	$ 11,899	$ 51,195
Long-Term Debt	498,832	389,778
Less: Current Maturities	191	188
Unamortized Debt Discount	1	1
Total Long-Term Debt	498,640	389,589
Total Short-Term and Long-Term Debt (with current maturities)	510,730	440,972
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	52,330	52,330
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 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000
Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt	1,502	1,548
OTP
Debt Instrument [Line Items]
Short-Term Debt		51,195
Long-Term Debt	445,000	335,900
Less: Current Maturities
Unamortized Debt Discount
Total Long-Term Debt	445,000	335,900
Total Short-Term and Long-Term Debt (with current maturities)	445,000	387,095
OTP | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015
Debt Instrument [Line Items]
Long-Term Debt		40,900
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	11,899
Long-Term Debt	53,832	53,878
Less: Current Maturities	191	188
Unamortized Debt Discount	1	1
Total Long-Term Debt	53,640	53,689
Total Short-Term and Long-Term Debt (with current maturities)	65,730	53,877
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | Other Obligations - Various up to 3.95%
Debt Instrument [Line Items]
Long-Term Debt	$ 1,502	$ 1,548

XML

Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%

XML

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
	Mar. 31, 2014		Mar. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	$ 13	[1]	$ 13	[1]
Amortization of Net Actuarial Loss - From Other Comprehensive Income	12	[2]	78	[2]
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	5		5
Amortization of Net Actuarial Loss - From Other Comprehensive Income	33		48
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	8		8
Amortization of Net Actuarial Loss - From Other Comprehensive Income	$ (21)		$ 30

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

[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $33 $48 Other Nonelectric Expenses (21) 30

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Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Disclosure [Abstract]
Balance on January 1	$ 4,239	$ 4,436
Increases Related to Tax Positions for Prior Years	137
Uncertain Positions Adjusted During Year
Balance on March 31	$ 4,376	$ 4,436

XML

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
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 | OTP
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 | OTP
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 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 | OTP
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 | OTP
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 6.37%, 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 | OTP
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 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029
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 | OTP
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 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044
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%

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Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details) (Employee Stock Purchase Plan)	3 Months Ended
	Mar. 31, 2014
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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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule of percent of consolidated sales revenue by country

	Three Months Ended March 31,
	2014			2013
United States of America		97.5	%		97.9	%
Mexico		1.9	%		1.2	%
Canada		0.5	%		0.9	%
All Other Countries (none individually greater than 0.05%)		0.1	%		--

Schedule of information by business segments

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	119,088		$	101,010
Manufacturing		55,435			53,166
Plastics		40,483			37,400
Construction		25,506			26,425
Intersegment Eliminations		(40	)		(47	)
Total	$	240,472		$	217,954

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Electric	$	5,079	$	4,808
Manufacturing		808		815
Plastics		247		248
Construction		100		107
Corporate and Intersegment Eliminations		361		1,002
Total	$	6,595	$	6,980

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	5,750		$	4,082
Manufacturing		1,671			2,218
Plastics		2,133			2,603
Construction		(409	)		(723	)
Corporate		(857	)		(2,294	)
Total	$	8,288		$	5,886

Earnings Available for Common Shares

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	16,653		$	11,931
Manufacturing		2,896			3,318
Plastics		3,460			3,887
Construction		(620	)		(1,092	)
Corporate		(1,027	)		(3,323	)
Discontinued Operations		68			129
Total	$	21,430		$	14,850

Identifiable Assets

	March 31,		December 31,
(in thousands)	2014		2013
Electric	$	1,334,155	$	1,290,416
Manufacturing		125,800		119,302
Plastics		95,779		76,853
Construction		46,800		49,440
Corporate		53,631		59,970
Discontinued Operations		38		38
Total	$	1,656,203	$	1,596,019

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Summary of Significant Accounting Policies (Detail Textuals 1) (USD $)			3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Level 3 Forward Energy Contracts	Mar. 31, 2014 Level 3 Forward Energy Contracts Power purchase contracts	Mar. 31, 2014 Level 3 Forward Energy Contracts Financial Contracts
Significant Accounting Policies [Line Items]
Derivative Assets				$ 1,569,000	$ 40,000
Derivative Liabilities	8,252,000	11,782,000		8,252,000
Net derivative gain related to the contract			$ 40,000

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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	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
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	$ (11,341)	$ (17,782)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	1,160	2,195
Changes in Fair Value of Contracts Entered into in Prior Periods	3,498	3,320
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	(6,683)	(12,267)
Net Gain Recognized as Regulatory Assets on contract entered into in Period	40	32
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$ (6,643)	$ (12,235)

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Short-Term and Long-Term Borrowings - Status of lines of credit (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Line Limit	$ 320,000
In Use	11,899
Restricted due to Outstanding Letters of Credit	4,489
Available	303,612	266,316
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	11,899
Restricted due to Outstanding Letters of Credit	659
Available	137,442	149,341
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use
Restricted due to Outstanding Letters of Credit	3,830
Available	$ 166,170	$ 116,975

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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	Mar. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$ 364,005	$ 361,487
Less Billings to Date	(377,991)	(377,608)
Plus Estimated Earnings Recognized	7,628	6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (6,358)	$ (9,644)

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Summary of Significant Accounting Policies (Detail Textuals 3) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Significant Accounting Policies [Line Items]
Unrecognized tax benefits	$ 4.3
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company
Significant Accounting Policies [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	10.9
Amount of development period costs, development fees and capital charges incurred by CCMC	$ 10.9

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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
	Mar. 31, 2014	Mar. 31, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	$ 534,830
Common Stock Issuances, Net of Expenses	4,252
Common Stock Retirements	(242)
Net Income	21,430	15,363
Other Comprehensive Income	8
Tax Benefit - Stock Compensation	31
Employee Stock Incentive Plans Expense	358
Common Dividends	(10,993)
Balance, End of Period	549,674
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	181,358
Common Stock Issuances, Net of Expenses	748
Common Stock Retirements	(44)
Balance, End of Period	182,062
Premium On Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	255,759
Common Stock Issuances, Net of Expenses	3,504
Common Stock Retirements	(198)
Tax Benefit - Stock Compensation	31
Employee Stock Incentive Plans Expense	358
Balance, End of Period	259,454
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	99,441
Net Income	21,430
Common Dividends	(10,993)
Balance, End of Period	109,878
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	(1,728)
Other Comprehensive Income	8
Balance, End of Period	$ (1,720)

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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
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net (Loss) Gain on Forward Electric Energy Contracts	$ (4)	$ 226

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Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 10) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014
Accounting Policies [Abstract]
2014	$ 977
2015	977
2016	945
2017	849
2018	$ 849

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Segment Information

3 Months Ended

Mar. 31, 2014

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, Plastics and Construction.

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.

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.

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.

Construction consists of businesses involved in commercial and industrial electric contracting and construction of fiber optic, electric distribution, water, wastewater and HVAC systems primarily in the central United States.

OTP is a wholly owned subsidiary 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 2013. 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 March 31,
	2014			2013
United States of America		97.5	%		97.9	%
Mexico		1.9	%		1.2	%
Canada		0.5	%		0.9	%
All Other Countries (none individually greater than 0.05%)		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 months ended March 31, 2014 and 2013 and total assets by business segment as of March 31, 2014 and December 31, 2013 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	119,088		$	101,010
Manufacturing		55,435			53,166
Plastics		40,483			37,400
Construction		25,506			26,425
Intersegment Eliminations		(40	)		(47	)
Total	$	240,472		$	217,954

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Electric	$	5,079	$	4,808
Manufacturing		808		815
Plastics		247		248
Construction		100		107
Corporate and Intersegment Eliminations		361		1,002
Total	$	6,595	$	6,980

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	5,750		$	4,082
Manufacturing		1,671			2,218
Plastics		2,133			2,603
Construction		(409	)		(723	)
Corporate		(857	)		(2,294	)
Total	$	8,288		$	5,886

Earnings Available for Common Shares

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Electric	$	16,653		$	11,931
Manufacturing		2,896			3,318
Plastics		3,460			3,887
Construction		(620	)		(1,092	)
Corporate		(1,027	)		(3,323	)
Discontinued Operations		68			129
Total	$	21,430		$	14,850

Identifiable Assets

	March 31,		December 31,
(in thousands)	2014		2013
Electric	$	1,334,155	$	1,290,416
Manufacturing		125,800		119,302
Plastics		95,779		76,853
Construction		46,800		49,440
Corporate		53,631		59,970
Discontinued Operations		38		38
Total	$	1,656,203	$	1,596,019

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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	Mar. 31, 2014 Counterparty	Dec. 31, 2013 Counterparty
Net Credit Risk on Forward Energy Contracts
Derivative [Line Items]
Exposure	$ 128	$ 856
Counterparties	3	3
Net Credit Risk to Single Largest Counterparty
Derivative [Line Items]
Exposure	$ 83	$ 530

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Summary of Significant Accounting Policies - Inventories (Details 6) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Finished Goods	$ 25,611	$ 20,649
Work in Process	9,654	9,942
Raw Material, Fuel and Supplies	46,610	42,090
Total Inventories	$ 81,875	$ 72,681

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Share-Based Payments (Tables)

3 Months Ended

Mar. 31, 2014

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

Schedule of compensation expense under stock-based payment programs

	Three months ended
	March 31,
(in thousands)	2014		2013
Employee Stock Purchase Plan (15% discount)	$	42	$	17
Restricted Stock Granted to Directors		123		207
Restricted Stock Granted to Employees		135		92
Restricted Stock Units Granted to Employees		58		75
Stock Performance Awards Granted to Executive Officers		526		1,098
Totals	$	884	$	1,489

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

3 Months Ended

Mar. 31, 2014

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, 2013	$	181,358		$	255,759		$	99,441		$	(1,728	)	$	534,830
Common Stock Issuances, Net of Expenses		748			3,504									4,252
Common Stock Retirements		(44	)		(198	)								(242	)
Net Income								21,430						21,430
Other Comprehensive Income											8			8
Tax Benefit – Stock Compensation					31									31
Employee Stock Incentive Plans Expense					358									358
Common Dividends								(10,993	)					(10,993	)
Balance, March 31, 2014	$	182,062		$	259,454		$	109,878		$	(1,720	)	$	549,674

Schedule of common shares outstanding from December 31, 2013 through March 31, 2014

Common Shares Outstanding, December 31, 2013	36,271,696
Issuances:
Dividend Reinvestments	49,402
Employee Stock Ownership Plan	22,650
Executive Stock Performance Awards (2011-2013 shares earned)	22,630
Employee Stock Purchase Plan	19,661
Shareholder Stock Purchase Program	18,681
Stock Options Exercised	16,650
Retirements:
Shares Withheld for Individual Income Tax Requirements	(8,879	)
Common Shares Outstanding, March 31, 2014	36,412,491

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Rate and Regulatory Matters (Detail Textuals) (USD $)			3 Months Ended		1 Months Ended	3 Months Ended							0 Months Ended	1 Months Ended					3 Months Ended	1 Months Ended		3 Months Ended		1 Months Ended	3 Months Ended		12 Months Ended			3 Months Ended			1 Months Ended		3 Months Ended		1 Months Ended			3 Months Ended			0 Months Ended	3 Months Ended		12 Months Ended	3 Months Ended				1 Months Ended		3 Months Ended	1 Months Ended	3 Months Ended		1 Months Ended	0 Months Ended			12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Big Stone AQCS Project BART - compliant AQCS	Mar. 31, 2014 EPA CSAPR Hoot Lake Plant	Jun. 30, 2005 Otter Tail Power Company Big Stone II Project Project	Mar. 31, 2014 Otter Tail Power Company Conservation Improvement Program Minimum	Mar. 31, 2014 Otter Tail Power Company Capacity Expansion 2020 Investor Project	Mar. 31, 2014 Otter Tail Power Company Capacity Expansion 2020 Fargo Project kV	Mar. 31, 2014 Otter Tail Power Company Capacity Expansion 2020 Brookings Project mi kV	Mar. 31, 2014 Otter Tail Power Company Capacity Expansion 2020 Bemidji Project kV	Mar. 31, 2014 Otter Tail Power Company Capacity Expansion 2020 Twin Cities La Crosse kV	Mar. 31, 2014 Otter Tail Power Company Big Stone AQCS Project BART - compliant AQCS	Apr. 02, 2010 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case	Apr. 25, 2011 Otter Tail Power Company Minnesota Public Utilities Commission General Rate Case Property	May 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone II Project	May 01, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone II Project	Oct. 31, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone II Project	Apr. 25, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone II Project	Mar. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Big Stone South - Brookings MVP	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	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Transmission Cost Recovery Rider	Jan. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Mar. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Dec. 31, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program	Oct. 10, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program Fiscal Year 2012	Apr. 01, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Conservation Improvement Program Fiscal Year 2013 Subsequent Event	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2016	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2020	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Resource Cost Recovery Rider Fiscal Year 2025	May 01, 2013 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate	Apr. 25, 2011 Otter Tail Power Company Minnesota Public Utilities Commission Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate Turbine	Mar. 31, 2014 Otter Tail Power Company Minnesota Public Utilities Commission Environmental Cost Recovery Rider	Nov. 25, 2009 Otter Tail Power Company North Dakota Public Service Commission General Rate Case	Jun. 25, 2010 Otter Tail Power Company North Dakota Public Service Commission Big Stone II Project	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Big Stone II Project	Jul. 30, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone II Project	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Big Stone South - Brookings MVP	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Transmission Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Transmission Cost Recovery Rider	Mar. 12, 2014 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Renewable Resource Cost Recovery Rider	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Environmental Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company North Dakota Public Service Commission Environmental Cost Recovery Rider	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Environmental Cost Recovery Rider Maximum	Mar. 31, 2014 Otter Tail Power Company North Dakota Public Service Commission Environmental Cost Recovery Rider Minimum	Apr. 21, 2011 Otter Tail Power Company South Dakota Public Utilities Commission General Rate Case	May 31, 2013 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone II Project	Mar. 31, 2011 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone II Project	Aug. 20, 2010 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone II Project General Rate Case	Mar. 31, 2014 Otter Tail Power Company South Dakota Public Utilities Commission Transmission Cost Recovery Rider	Mar. 31, 2013 Otter Tail Power Company South Dakota Public Utilities Commission Transmission Cost Recovery Rider	Sep. 19, 2011 Otter Tail Power Company South Dakota Public Utilities Commission Big Stone AQCS Project BART - compliant AQCS	Nov. 12, 2013 Otter Tail Power Company Federal Energy Regulatory Commission	Jan. 31, 2012 Otter Tail Power Company Federal Energy Regulatory Commission Project	Dec. 31, 2010 Otter Tail Power Company Federal Energy Regulatory Commission Project	Dec. 31, 2011 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Brookings MVP mi kV	Dec. 31, 2011 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP kV	Dec. 31, 2011 Otter Tail Power Company Federal Energy Regulatory Commission Big Stone South - Ellendale MVP Maximum mi	Dec. 31, 2011 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	5 years			60 months																				36 months																10 years	5 years
Big Stone Plant Air Quality Control System (AQCS) project, installation period deadline																																																									5 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	$ 99,038,000	$ 101,670,000																				$ 1,200,000			$ 8,100,000																						$ 2,100,000								$ 100,000
Regulatory Liabilities	77,593,000	75,121,000																																	100,000			100,000			100,000			1,300,000
Number of additional projects approved																				3
Expected cost recovery from customers																																														9,900,000
Percentage of operating revenue from service to be invested in energy conservation in Minnesota						1.50%
Financial incentive filing request																												2,700,000	4,000,000
Financial incentives recognized during period																											3,900,000
Conservation improvement programs previous surcharge																								3.80%
Revised conservation improvement programs surcharge per kwh																								0.00142
Decrease to percentage of customers bill																								1.90%
Conservation costs recoverable and incentives earned																									1,500,000	1,600,000
Renewable resource adjustment rate																																	0
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate																																																											100.00%	100.00%
Percentage of prudently incurred costs of cancelled or abandoned transmission facilities, authorized for recovery by formula transmission rate																																																												100.00%
Number of projects authorized for recovery of costs if abandoned																																																											2	3
Number of investor							11
Number of major transmission projects							4
Expanded capacity of projects								345	345	230	345																																																		345	345
Extended distance of transmission line									250																																																				70		170	160
Recoverable amount of generation costs																		3,200,000																			4,300,000
Present value of recoverable amount of generation costs																		2,800,000																			3,900,000
Project transmission related costs																		3,200,000																			2,600,000
Number of other electric providers entered in agreement for development of project					6
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
Discounted present value of recoverable deferred costs															2,800,000
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																																																				200,000
Revenue increase approved by rate authority														5,000,000																						3,600,000															643,000
Percentage of increase in base rate revenue approved by rate authority														1.60%																						3.00%															2.32%
Number of transmission lines approved for transfer of investments from rider recovery to base rate recovery														2
Amount of recognized revenue for amounts eligible for recovery																						2,300,000	1,000,000												1,800,000						1,500,000	800,000		1,400,000	2,300,000		1,500,000	700,000							300,000	100,000
Big Stone II generation costs																																					10,100,000
Percentage of reduction in the NDRRA																																											13.50%
Percentage of ECR rider rate																																																	7.531%	4.319%
Public utilities, allowance for funds used during construction, rate																																					7.65%
Carrying charge of generation cost including in total recovery amount																																					300,000
Transmission cost plus accrued AFUDC																																							1,000,000
Public utilities allowed rate of return subsequent to approval of increase in base rate																																																			8.50%
Recovery of Big Stone II generation development costs approved																																																					1,000,000
Current return on equity used in transmission rates																																																										12.38%
Proposed reduced return on equity used in transmission rates																																																										9.15%
Predicted annual purchase costs of SO2 allowances				1,000,000
Current projected cost			384,000,000									207,000,000
Percentage of projected cost												53.90%
Construction expenditures												$ 113,000,000
Number of wind farms																																		3
Extended period of new rate by request																																		18 months
Number of additional transmission related projects																					12

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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	3 Months Ended
	Mar. 31, 2014
Goodwill [Line Items]
Gross Balance December 31, 2013	$ 38,971
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2013	38,971
Adjustments to Goodwill in 2014	163
Balance (net of impairments) March 31,2014	38,808
Manufacturing
Goodwill [Line Items]
Gross Balance December 31, 2013	12,186
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2013	12,186
Adjustments to Goodwill in 2014
Balance (net of impairments) March 31,2014	12,186
Plastics
Goodwill [Line Items]
Gross Balance December 31, 2013	19,302
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2013	19,302
Adjustments to Goodwill in 2014
Balance (net of impairments) March 31,2014	19,302
Construction
Goodwill [Line Items]
Gross Balance December 31, 2013	7,483
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2013	7,483
Adjustments to Goodwill in 2014	163
Balance (net of impairments) March 31,2014	$ 7,320

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Short-Term and Long-Term Borrowings (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Schedule of lines of credit

(in thousands)	Line Limit		In Use on March 31,  2014		Restricted due to Outstanding Letters of Credit		Available on March 31,  2014		Available on December 31,  2013
Otter Tail Corporation Credit Agreement	$	150,000	$	11,899	$	659	$	137,442	$	149,341
OTP Credit Agreement		170,000		--		3,830		166,170		116,975
Total	$	320,000	$	11,899	$	4,489	$	303,612	$	266,316

Schedule of short-term and long-term debt outstanding

March 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	11,899	$	11,899
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
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 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
Other Obligations - Various up to 3.95% at March 31, 2014		--		1,502		1,502
Total	$	445,000	$	53,832	$	498,832
Less: Current Maturities		--		191		191
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,640	$	498,640
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	65,730	$	510,730

December 31, 2013 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	51,195	$	--	$	51,195
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			$	52,330		52,330
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 December 31, 2013		--		1,548		1,548
Total	$	335,900	$	53,878	$	389,778
Less: Current Maturities		--		188		188
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	335,900	$	53,689	$	389,589
Total Short-Term and Long-Term Debt (with current maturities)	$	387,095	$	53,877	$	440,972

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Pension Plan and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Pension Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	1,175		$	1,418
Interest Cost on Projected Benefit Obligation		3,285			3,036
Expected Return on Assets		(4,187	)		(3,632	)
Amortization of Prior-Service Cost:
From Regulatory Asset		64			83
From Other Comprehensive Income1		2			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		868			1,663
From Other Comprehensive Income1		23			45
Net Periodic Pension Cost	$	1,230		$	2,615
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 March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	13		$	13
Interest Cost on Projected Benefit Obligation		380			352
Amortization of Prior-Service Cost:
From Regulatory Asset		5			5
From Other Comprehensive Income1		13			13
Amortization of Net Actuarial Loss:
From Regulatory Asset		35			52
From Other Comprehensive Income2		12			78
Net Periodic Pension Cost	$	458		$	513
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5		$	5
Other Nonelectric Expenses		8			8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	33		$	48
Other Nonelectric Expenses		(21	)		30

Postretirement Benefits

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	315		$	441
Interest Cost on Projected Benefit Obligation		558			610
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		--			248
From Other Comprehensive Income1		--			6
Net Periodic Postretirement Benefit Cost	$	925		$	1,357
Effect of Medicare Part D Subsidy	$	(308	)	$	(564	)
1 Corporate cost included in other nonelectric expenses.

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

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) 815, Derivatives and Hedging. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

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 March 31,
	2014			2013
Percentage-of-Completion Revenues		9.1	%		12.1	%

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs Incurred on Uncompleted Contracts	$	364,005		$	361,487
Less Billings to Date		(377,991	)		(377,608	)
Plus Estimated Earnings Recognized		7,628			6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,719		$	4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(10,077	)		(13,707	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

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.

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The warranty reserve balance as of December 31, 2013 and March 31, 2014 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies and is included in liabilities of discontinued operations. See note 17 to condensed 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:

	March 31,		December 31,
(in thousands)	2014		2013
Accounts Receivable Retained by Customers	$	6,352	$	7,125	1
1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

Fair Value Measurements

The Company follows Accounting Standards Codification (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 March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	1,609
Forward Gasoline Purchase Contracts				20
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,438
U.S. Government Debt Securities – Held by Captive Insurance Company				964
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		745
Total Assets	$	865	$	8,422	$	1,609
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	8,252
Total Liabilities	$	--	$	--	$	8,252

December 31, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	338
Forward Gasoline Purchase Contracts				62
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,671
U.S. Government Debt Securities – Held by Captive Insurance Company				1,271
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		866
Total Assets	$	976	$	9,004	$	338
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	103	$	11,679
Total Liabilities	$	--	$	103	$	11,679

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 March 31, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. 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 March 31, 2014 Level 3 forward electric price inputs ranged from $1.52 to $7.00 per megawatt-hour underthe active trading hub price. The weighted average price was $36.77 per megawatt-hour.

In the table above, $1,569,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $8,252,000 of the fair value of the Level 3 forward energy contracts in a derivative liability position as of March 31, 2014 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 month periods ended March 31, 2014 or 2013.

The remaining $40,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position as of March 31, 2014 are related to financial contracts that will not be settled by physical delivery of electricity but will be settled financially by the counterparty to the contract paying or receiving the difference between the contract price and the market price at the hour of scheduled delivery. The related forward energy sales contracts are not offset by forward energy purchase contracts. Therefore, the $40,000 in derivative gains related to these contracts as of March 31, 2014 are subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in April and May of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the fair value of the contracts.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Forward Energy Contracts - Fair Values Beginning of Period	$	(11,341	)	$	(17,782	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		1,160			2,195
Changes in Fair Value of Contracts Entered into in Prior Periods		3,498			3,320
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(6,683	)		(12,267	)
Net Gain Recognized as Regulatory Assets on contract entered into in Period		40			32
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(6,643	)	$	(12,235	)

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2014		2013
Finished Goods	$	25,611	$	20,649
Work in Process		9,654		9,942
Raw Material, Fuel and Supplies		46,610		42,090
Total Inventories	$	81,875	$	72,681

Goodwill and Other Intangible Assets

In the first quarter of 2014, Aevenia, Inc. (Aevenia) recorded a $289,000 gain on the sale of its data communication installation and services business which, over the years of its existence, did not provide a materially significant impact to Aevenia’s operating results. In connection with this sale, Aevenia disposed of $163,000 in goodwill associated with the purchase of this business in May 2004.

The following table summarizes changes to goodwill by business segment during 2014:

(in thousands)	Gross Balance December 31, 2013		Accumulated Impairments		Balance (net of impairments) December 31, 2013		Adjustments to Goodwill in 2014		Balance (net of impairments) March 31, 2014
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Construction		7,483		--		7,483		163		7,320
Total	$	38,971	$	--	$	38,971	$	163	$	38,808

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. The following table summarizes the components of the Company’s intangible assets at March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,147	$	11,664	15 – 25 years
Other Intangible Assets Including Contracts		825		505		320	5 – 30 years
Total	$	17,636	$	5,652	$	11,984
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2013(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,935	$	11,876	15 – 25 years
Other Intangible Assets Including Contracts		825		473		352	5 – 30 years
Total	$	17,636	$	5,408	$	12,228
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2014		2015		2016		2017		2018
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	945	$	849	$	849

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2014		2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	22,244	$	8,901
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	3,434	$	--
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, has 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 and 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 March 31, 2014 is $10.9 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 as of March 31, 2014 could be as high as $10.9 million.

Revisions to Presentation

Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the three months ended March 31, 2013 have been revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for the three months ended March 31, 2014. The change in presentation of 2013 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for the three month period ended March 31, 2013.

New Accounting Standards

Accounting Standards Update (ASU) 2013-11

In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis. The Company’s long-term deferred income tax reported on its March 31, 2014 consolidated balance sheet include $4.3 million of unrecognized tax benefits.

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Schedule of long-term debt including current maturities

	March 31, 2014						December 31, 2013
(in thousands)	Carrying Amount			Fair Value			Carrying  Amount			Fair Value
Cash and Cash Equivalents	$	6,613		$	6,613		$	1,150		$	1,150
Short-Term Debt	$	(11,899	)	$	(11,899	)		(51,195	)		(51,195	)
Long-Term Debt including Current Maturities	$	(498,831	)	$	(546,269	)		(389,777	)		(427,796	)

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Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 6,613	$ 1,150
Short-Term Debt	(11,899)	(51,195)
Long-Term Debt including Current Maturities	(498,831)	(389,777)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	6,613	1,150
Short-Term Debt	(11,899)	(51,195)
Long-Term Debt including Current Maturities	$ (546,269)	$ (427,796)

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Summary of Significant Accounting Policies - Accounts Receivable Retained by Customers Pending Project Completion (Parentheticals) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Accounting Policies [Abstract]
Retainage related to projects in excess of one year	$ 89,000

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Segment Information - Percent of sales revenue by country (Details) (Sales)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	97.50%	97.90%
Mexico
Segment Reporting Information [Line Items]
Percentage of sales revenue	1.90%	1.20%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.50%	0.90%
All Other Countries (none individually greater than 0.05%)
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.10%

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Share-Based Payments (Detail Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 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	$ 3.6
Weighted-average period of amortization	1 year 9 months 18 days

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Consolidated Balance Sheets (not audited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current Assets
Cash and Cash Equivalents	$ 6,613	$ 1,150
Accounts Receivable:
Trade - Net	99,892	83,572
Other	11,523	9,790
Inventories	81,875	72,681
Deferred Income Taxes	39,352	35,452
Unbilled Revenues	16,902	18,157
Costs and Estimated Earnings in Excess of Billings	3,719	4,063
Regulatory Assets	20,199	17,940
Other	11,336	7,747
Assets of Discontinued Operations	38	38
Total Current Assets	291,449	250,590
Investments	8,753	9,362
Other Assets	29,605	28,834
Goodwill	38,808	38,971
Other Intangibles - Net	13,084	13,328
Deferred Debits
Unamortized Debt Expense	4,498	4,188
Regulatory Assets	78,839	83,730
Total Deferred Debits	83,337	87,918
Plant
Electric Plant in Service	1,473,685	1,460,884
Nonelectric Operations	196,500	194,872
Construction Work in Progress	207,442	187,461
Total Gross Plant	1,877,627	1,843,217
Less Accumulated Depreciation and Amortization	686,460	676,201
Net Plant	1,191,167	1,167,016
Total Assets	1,656,203	1,596,019
Current Liabilities
Short-Term Debt	11,899	51,195
Current Maturities of Long-Term Debt	191	188
Accounts Payable	104,486	113,457
Accrued Salaries and Wages	13,556	19,903
Billings In Excess Of Costs and Estimated Earnings	10,077	13,707
Accrued Taxes	14,057	12,491
Derivative Liabilities	8,252	11,782
Other Accrued Liabilities	8,272	6,532
Liabilities of Discontinued Operations	3,442	3,637
Total Current Liabilities	174,232	232,892
Pensions Benefit Liability	50,129	69,743
Other Postretirement Benefits Liability	45,547	45,221
Other Noncurrent Liabilities	21,367	25,209
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	212,682	195,603
Deferred Tax Credits	27,834	28,288
Regulatory Liabilities	75,365	73,926
Other	733	718
Total Deferred Credits	316,614	298,535
Capitalization
Long-Term Debt, Net of Current Maturities	498,640	389,589
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2014 - 36,412,491 Shares; 2013 - 36,271,696 Shares	182,062	181,358
Premium on Common Shares	259,454	255,759
Retained Earnings	109,878	99,441
Accumulated Other Comprehensive Loss	(1,720)	(1,728)
Total Common Equity	549,674	534,830
Total Capitalization	1,048,314	924,419
Total Liabilities and Equity	1,656,203	1,596,019
Cumulative Preferred Shares
Capitalization
Cumulative Shares
Cumulative Preference Shares
Capitalization
Cumulative Shares

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Summary of Significant Accounting Policies - Components of intangible assets (Details 8) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Amortizable Intangible Assets:
Gross Carrying Amount	$ 17,636	$ 17,636
Accumulated Amortization	5,652	5,408
Net Carrying Amount	11,984	12,228
Trade Name
Indefinite-lived Intangible Assets:
Indefinite-lived Intangible Assets	1,100	1,100
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	5,147	4,935
Net Carrying Amount	11,664	11,876
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	825
Accumulated Amortization	505	473
Net Carrying Amount	$ 320	$ 352
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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Consolidated Statements of Comprehensive Income (not audited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 21,430	$ 15,363
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	(17)	(25)
(Losses) Arising During Period	(17)	(5)
Income Tax Benefit	12	11
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	(22)	(19)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 12)	50	145
Income Tax (Expense)	(20)	(58)
Pension and Postretirement Benefit Plans - net-of-tax	30	87
Total Other Comprehensive Income	8	68
Total Comprehensive Income	$ 21,438	$ 15,431

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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	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$ 20,199	$ 17,940
Regulatory Assets - Long-Term	78,839	83,730
Current Liability - Marked-to-Market Loss	(8,252)	(11,782)
Regulatory Liability - Current	(2,228)	(1,195)
Regulatory Liabilities - Long-Term	(75,365)	(73,926)
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Current Asset - Marked-to-Market Gain	1,609	338
Total Assets	9,861	12,020
Current Liability - Marked-to-Market Loss	(8,252)	(11,782)
Total Liabilities	(9,822)	(11,905)
Net Fair Value of Marked-to-Market Energy Contracts	39	115	81	49
Forward Electricity Contracts | Deferred Marked-to-Market Loss
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	3,258	3,008
Regulatory Assets - Long-Term	4,994	8,674
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current	(533)	(6)
Regulatory Liabilities - Long-Term	$ (1,037)	$ (117)

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Subsequent Events (Tables)

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Schedule of stock incentive awards granted

Award	Shares/Units Granted		Weighted Average  Grant-Date  Fair Value  per Award		Vesting
Restricted Stock Granted to Nonemployee Directors		16,800	$	29.41	25% per year through April 8, 2018
Restricted Stock Granted to Executive Officers		26,700	$	29.41	25% per year through April 8, 2018
Stock Performance Awards Granted to Executive Officers		115,200	$	22.94	December 31, 2016
Restricted Stock Units Granted to Employees		11,800	$	24.95	100% on April 8, 2018

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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	Mar. 31, 2014		Dec. 31, 2013
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$ 8,252	[1]	$ 11,679	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	(1,569)		(117)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$ 6,683		$ 11,562

[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 $ 8,252 $ 11,679 Offsetting Gains with Counterparties under Master Netting Agreements (1,569) (117) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 6,683 $ 11,562

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Subsequent Events

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Subsequent Events

18. Subsequent Events

2014 Stock Incentive Plan

On April 14, 2014 the Company’s shareholders approved the Company’s 2014 Stock Incentive Plan. The Company’s 2014 Stock Incentive Plan allows the Company to provide compensation through various stock-based arrangements. The material terms of the 2014 Stock Incentive Plan are disclosed in the Company’s Proxy Statement for its 2014 Annual Meeting of Shareholders filed with the Securities and Exchange Commission (SEC) on March 3, 2014. The 2014 Stock Incentive Plan was filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-8 filed with the SEC on April 17, 2014.

Stock Incentive Awards

On April 14, 2014 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 2014 Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average  Grant-Date  Fair Value  per Award		Vesting
Restricted Stock Granted to Nonemployee Directors		16,800	$	29.41	25% per year through April 8, 2018
Restricted Stock Granted to Executive Officers		26,700	$	29.41	25% per year through April 8, 2018
Stock Performance Awards Granted to Executive Officers		115,200	$	22.94	December 31, 2016
Restricted Stock Units Granted to Employees		11,800	$	24.95	100% on April 8, 2018

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 150,400 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, 2014 through December 31, 2016. The aggregate target share award is 115,200 shares. Actual payment may range from zero to 150% 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 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, Stock Compensation (ASC 718), and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

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

Under the terms of the award agreements, all outstanding (unvested) shares or units held by a retiring grantee vest immediately on normal retirement. When the Company is made aware of a retirement or pending retirement, the Company accelerates recognition of compensation expense related to the unvested awards to correspond with the remaining service period of the grantee, in accordance with the requirements of ASC 718.

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Summary of Significant Accounting Policies - Percentages of companys consolidated revenues recorded under percentage-of-completion method (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accounting Policies [Abstract]
Percentage-of-Completion Revenues	9.10%	12.10%

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

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

	Three Months Ended March 31,
	2014			2013
Percentage-of-Completion Revenues		9.1	%		12.1	%

Schedule of costs incurred and billings and estimated earnings

	March 31,			December 31,
(in thousands)	2014			2013
Costs Incurred on Uncompleted Contracts	$	364,005		$	361,487
Less Billings to Date		(377,991	)		(377,608	)
Plus Estimated Earnings Recognized		7,628			6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

Schedule of percentage-of-completion balance sheet amounts

	March 31,			December 31,
(in thousands)	2014			2013
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,719		$	4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(10,077	)		(13,707	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

Schedule of receivables from customers being retained pending project completion

	March 31,		December 31,
(in thousands)	2014		2013
Accounts Receivable Retained by Customers	$	6,352	$	7,125	1
1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

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

March 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	1,609
Forward Gasoline Purchase Contracts				20
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,438
U.S. Government Debt Securities – Held by Captive Insurance Company				964
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		745
Total Assets	$	865	$	8,422	$	1,609
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	8,252
Total Liabilities	$	--	$	--	$	8,252

December 31, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	338
Forward Gasoline Purchase Contracts				62
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,671
U.S. Government Debt Securities – Held by Captive Insurance Company				1,271
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		866
Total Assets	$	976	$	9,004	$	338
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	103	$	11,679
Total Liabilities	$	--	$	103	$	11,679

Schedule of derivative asset and liability fair valuations

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Forward Energy Contracts - Fair Values Beginning of Period	$	(11,341	)	$	(17,782	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		1,160			2,195
Changes in Fair Value of Contracts Entered into in Prior Periods		3,498			3,320
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(6,683	)		(12,267	)
Net Gain Recognized as Regulatory Assets on contract entered into in Period		40			32
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(6,643	)	$	(12,235	)

Schedule of inventories

	March 31,		December 31,
(in thousands)	2014		2013
Finished Goods	$	25,611	$	20,649
Work in Process		9,654		9,942
Raw Material, Fuel and Supplies		46,610		42,090
Total Inventories	$	81,875	$	72,681

Schedule of changes to goodwill by business segment

(in thousands)	Gross Balance December 31, 2013		Accumulated Impairments		Balance (net of impairments) December 31, 2013		Adjustments to Goodwill in 2014		Balance (net of impairments) March 31, 2014
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Construction		7,483		--		7,483		163		7,320
Total	$	38,971	$	--	$	38,971	$	163	$	38,808

Schedule of components of intangible assets

March 31, 2014 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,147	$	11,664	15 – 25 years
Other Intangible Assets Including Contracts		825		505		320	5 – 30 years
Total	$	17,636	$	5,652	$	11,984
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2013(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,935	$	11,876	15 – 25 years
Other Intangible Assets Including Contracts		825		473		352	5 – 30 years
Total	$	17,636	$	5,408	$	12,228
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

Schedule of amortization expense for intangible assets

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Amortization Expense – Intangible Assets	$	244	$	244

Schedule of estimated annual amortization expense for Intangible Assets

(in thousands)	2014		2015		2016		2017		2018
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	945	$	849	$	849

Schedule of supplemental disclosure of cash flow information

	As of March 31,
(in thousands)	2014		2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	22,244	$	8,901
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	3,434	$	--
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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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details)	3 Months Ended
	Mar. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares Outstanding, December 31, 2013	36,271,696
Issuances:
Dividend Reinvestments	49,402
Employee Stock Ownership Plan	22,650
Executive Stock Performance Awards (2011-2013 shares earned)	22,630
Employee Stock Purchase Plan	19,661
Shareholder Stock Purchase Program	18,681
Stock Options Exercised	16,650
Retirements:
Shares Withheld for Individual Income Tax Requirements	(8,879)
Common Shares Outstanding, March 31, 2014	36,412,491

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Consolidated Statements of Cash Flows (not audited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash Flows from Operating Activities
Net Income	$ 21,430	$ 15,363
Adjustments to Reconcile Net Income to Net Cash (Used in) Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		(210)
Net (Income) Loss from Discontinued Operations	(68)	81
Depreciation and Amortization	14,780	14,920
Deferred Tax Credits	(454)	(483)
Deferred Income Taxes	12,872	6,139
Change in Deferred Debits and Other Assets	(888)	4,800
Discretionary Contribution to Pension Plan	(20,000)	(10,000)
Change in Noncurrent Liabilities and Deferred Credits	(2,408)	1,975
Allowance for Equity/Other Funds Used During Construction	(340)	(293)
Change in Derivatives Net of Regulatory Deferral	118	378
Stock Compensation Expense - Equity Awards	358	392
Other - Net	(255)	25
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(17,884)	(13,423)
Change in Inventories	(9,234)	(4,062)
Change in Other Current Assets	(1,599)	(3,025)
Change in Payables and Other Current Liabilities	(16,363)	(3,440)
Change in Interest and Income Taxes Receivable/Payable	1,013	1,076
Net Cash (Used in) Provided by Continuing Operations	(18,922)	10,213
Net Cash Used in Discontinued Operations	(135)	(2,400)
Net Cash (Used in) Provided by Operating Activities	(19,057)	7,813
Cash Flows from Investing Activities
Capital Expenditures	(37,690)	(23,327)
Net Proceeds from Disposal of Noncurrent Assets	1,505	729
Net Increase in Other Investments	(989)	(923)
Net Cash Used in Investing Activities - Continuing Operations	(37,174)	(23,521)
Net Proceeds from Sale of Discontinued Operations		10,465
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations	7	(208)
Net Cash Used in Investing Activities	(37,167)	(13,264)
Cash Flows from Financing Activities
Net Short-Term (Repayments) Borrowings	(39,296)	1,335
Proceeds from Issuance of Common Stock	3,666	1,156
Payments for Retirement of Capital Stock	(242)	(15,500)
Proceeds from Issuance of Long-Term Debt	150,000	40,900
Short-Term and Long-Term Debt Issuance Expenses	(502)	(7)
Payments for Retirement of Long-Term Debt	(40,946)	(25,178)
Dividends Paid and Other Distributions	(10,993)	(11,307)
Net Cash Provided by (Used in) Financing Activities	61,687	(8,601)
Net Change in Cash and Cash Equivalents - Discontinued Operations		(778)
Net Change in Cash and Cash Equivalents	5,463	(14,830)
Cash and Cash Equivalents at Beginning of Period	1,150	52,362
Cash and Cash Equivalents at End of Period	$ 6,613	$ 37,532

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Consolidated Balance Sheets (not audited) (Parentheticals) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Common Shares, Par Value	$ 5	$ 5
Common Shares, Authorized	50,000,000	50,000,000
Common Shares, Outstanding	36,412,491	36,271,696
Cumulative Preferred Shares
Cumulative Shares, Authorized	1,500,000	1,500,000
Cumulative Shares, Without Par Value
Cumulative Shares, Outstanding
Cumulative Preference Shares
Cumulative Shares, Authorized	1,000,000	1,000,000
Cumulative Shares, Without Par Value
Cumulative Shares, Outstanding

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Short-Term and Long-Term Borrowings

3 Months Ended

Mar. 31, 2014

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 March 31, 2014 and December 31, 2013:

(in thousands)	Line Limit		In Use on March 31,  2014		Restricted due to Outstanding Letters of Credit		Available on March 31,  2014		Available on December 31,  2013
Otter Tail Corporation Credit Agreement	$	150,000	$	11,899	$	659	$	137,442	$	149,341
OTP Credit Agreement		170,000		--		3,830		166,170		116,975
Total	$	320,000	$	11,899	$	4,489	$	303,612	$	266,316

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 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 Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes.

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 Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B 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 OTP 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 became 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.

On February 27, 2014 OTP used a portion of the proceeds of the Notes to retire OTP’s $40.9 million unsecured term loan under a Credit Agreement with JPMorgan Chase Bank, N.A., and to repay $82.5 million of short-term debt then outstanding under OTP’s Second Amended and Restated Credit Agreement (the OTP Credit Agreement). Remaining proceeds of the Notes will be used to fund OTP 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 March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	11,899	$	11,899
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
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 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
Other Obligations - Various up to 3.95% at March 31, 2014		--		1,502		1,502
Total	$	445,000	$	53,832	$	498,832
Less: Current Maturities		--		191		191
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,640	$	498,640
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	65,730	$	510,730

December 31, 2013 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	51,195	$	--	$	51,195
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			$	52,330		52,330
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 December 31, 2013		--		1,548		1,548
Total	$	335,900	$	53,878	$	389,778
Less: Current Maturities		--		188		188
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	335,900	$	53,689	$	389,589
Total Short-Term and Long-Term Debt (with current maturities)	$	387,095	$	53,877	$	440,972

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Subsequent Events (Detail Textuals 1) (Subsequent Event, USD $)	0 Months Ended
	Apr. 14, 2014
Stock Performance Awards | Executive Officers
Subsequent Event [Line Items]
Maximum aggregate common shares award	150,400
Shares/Units Granted	115,200
Grant date fair value per share	$ 22.94
Stock Performance Awards | Executive Officers | Maximum
Subsequent Event [Line Items]
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Executive Officers | Minimum
Subsequent Event [Line Items]
Percentage of target amount as actual payment	0.00%
Restricted Stock Units (RSUs)
Subsequent Event [Line Items]
Vesting period for restricted stock units (in years)	4 years

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Discontinued Operations (Detail Textuals) (USD $)	3 Months Ended	0 Months Ended	1 Months Ended	3 Months Ended
	Mar. 31, 2013	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	Mar. 31, 2013 Disposal groups held for sale or disposed of by sale DMS
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations	$ 10,465,000	$ 13,000,000
Amount of working capital true up received			2,400,000
Gain on working capital settlement				$ 200,000

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	0001466593
Trading Symbol	ottr
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		36,471,911
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1

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Pension Plan and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2014

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 March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	1,175		$	1,418
Interest Cost on Projected Benefit Obligation		3,285			3,036
Expected Return on Assets		(4,187	)		(3,632	)
Amortization of Prior-Service Cost:
From Regulatory Asset		64			83
From Other Comprehensive Income1		2			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		868			1,663
From Other Comprehensive Income1		23			45
Net Periodic Pension Cost	$	1,230		$	2,615
1Corporate cost included in other nonelectric expenses.

Cash flows—The Company made discretionary plan contributions totaling $20,000,000 in January 2014. The Company currently is not required and does not expect to make an additional contribution to the plan in 2014. The Company also made a discretionary plan contribution of $10,000,000 in January 2013.

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	13		$	13
Interest Cost on Projected Benefit Obligation		380			352
Amortization of Prior-Service Cost:
From Regulatory Asset		5			5
From Other Comprehensive Income1		13			13
Amortization of Net Actuarial Loss:
From Regulatory Asset		35			52
From Other Comprehensive Income2		12			78
Net Periodic Pension Cost	$	458		$	513
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	5		$	5
Other Nonelectric Expenses		8			8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	33		$	48
Other Nonelectric Expenses		(21	)		30

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Service Cost—Benefit Earned During the Period	$	315		$	441
Interest Cost on Projected Benefit Obligation		558			610
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		--			248
From Other Comprehensive Income1		--			6
Net Periodic Postretirement Benefit Cost	$	925		$	1,357
Effect of Medicare Part D Subsidy	$	(308	)	$	(564	)
1 Corporate cost included in other nonelectric expenses.

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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
	Mar. 31, 2014		Mar. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	$ 1,175		$ 1,418
Interest Cost on Projected Benefit Obligation	3,285		3,036
Expected Return on Assets	(4,187)		(3,632)
Amortization of Prior-Service Cost:
From Regulatory Asset	64		83
From Other Comprehensive Income	2	[1]	2	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	868		1,663
From Other Comprehensive Income	23	[1]	45	[1]
Net Periodic Pension Cost	1,230		2,615
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	13		13
Interest Cost on Projected Benefit Obligation	380		352
Amortization of Prior-Service Cost:
From Regulatory Asset	5		5
From Other Comprehensive Income	13	[2]	13	[2]
Amortization of Net Actuarial Loss:
From Regulatory Asset	35		52
From Other Comprehensive Income	12	[3]	78	[3]
Net Periodic Pension Cost	458		513
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	315		441
Interest Cost on Projected Benefit Obligation	558		610
Amortization of Prior-Service Cost:
From Regulatory Asset	51		51
From Other Comprehensive Income	1	[1]	1	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset			248
From Other Comprehensive Income		[1]	6	[1]
Net Periodic Pension Cost	925		1,357
Effect of Medicare Part D Subsidy	$ (308)		$ (564)

[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 Other Nonelectric Expenses 8 8

[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $33 $48 Other Nonelectric Expenses (21) 30

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Discontinued Operations - Warranty Reserves (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]
Warranty Reserve Balance, January 1	$ 3,087	$ 5,027
Provision for Warranties Used During the Year		120
Less Settlements Made During the Year		(583)
Decrease in Warranty Estimates for Prior Years	(100)	(63)
Warranty Reserve Balance, March 31	$ 2,987	$ 4,501

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Consolidated Statements of Income (not audited) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues
Electric	$ 119,048	$ 100,976
Product Sales	95,918	90,561
Construction Services	25,506	26,417
Total Operating Revenues	240,472	217,954
Operating Expenses
Production Fuel - Electric	22,030	17,953
Purchased Power - Electric System Use	21,785	16,639
Electric Operation and Maintenance Expenses	34,622	32,447
Cost of Products Sold (depreciation included below)	73,939	67,787
Cost of Construction Revenues Earned (depreciation included below)	22,362	24,275
Other Nonelectric Expenses	13,561	13,778
Depreciation and Amortization	14,780	14,920
Property Taxes - Electric	2,971	2,916
Total Operating Expenses	206,050	190,715
Operating Income	34,422	27,239
Interest Charges	6,595	6,980
Other Income	1,823	861
Income Before Income Taxes from Continuing Operations	29,650	21,120
Income Tax Expense -Continuing Operations	8,288	5,886
Net Income from Continuing Operations	21,362	15,234
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of$49 and ($205) for the respective periods	68	(81)
Gain on Disposition - net of Income Tax Expense of$6 for the three months ended March 31, 2013		210
Net Income from Discontinued Operations	68	129
Net Income	21,430	15,363
Preferred Dividend Requirements and Other Adjustments		513
Earnings Available for Common Shares	$ 21,430	$ 14,850
Average Number of Common Shares Outstanding - Basic	36,240,350	36,075,131
Average Number of Common Shares Outstanding - Diluted	36,431,915	36,259,115
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$ 0.59	$ 0.41
Discontinued Operations
Earnings Per Share, Basic, Total	$ 0.59	$ 0.41
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement and other adjustments)	$ 0.59	$ 0.41
Discontinued Operations
Earnings Per Share, Diluted, Total	$ 0.59	$ 0.41
Dividends Declared Per Common Share	$ 0.3025	$ 0.2975

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Forward Contracts Classified as Derivatives

3 Months Ended

Mar. 31, 2014

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 March 31, 2014 OTP had recognized, on a pretax basis, $39,000 in net unrealized gains on open forward contracts for the 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 March 31, 2014 and December 31, 2013, and the change in the Company’s consolidated balance sheet position from December 31, 2013 to March 31, 2014 and December 31, 2012 to March 31, 2013:

(in thousands)	March 31, 2014			December 31, 2013
Current Asset – Marked-to-Market Gain	$	1,609		$	338
Regulatory Asset – Current Deferred Marked-to-Market Loss		3,258			3,008
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		4,994			8,674
Total Assets		9,861			12,020
Current Liability – Marked-to-Market Loss		(8,252	)		(11,782	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(533	)		(6	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(1,037	)		(117	)
Total Liabilities		(9,822	)		(11,905	)
Net Fair Value of Marked-to-Market Energy Contracts	$	39		$	115

(in thousands)	Year-to-Date March 31, 2014			Year-to-Date March 31, 2013
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	115		$	49
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
Changes in Fair Value of Contracts Entered into in Current Period		39			81
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	39		$	81

The $39,000 in recognized but unrealized gains on the forward energy sales contracts marked to market on March 31, 2014 are expected to be realized on settlement as scheduled in April and May of 2014.

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

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Net (Loss) Gain on Forward Electric Energy Contracts	$	(4	)	$	226

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 March 31, 2014 and December 31, 2013:

	March 31, 2014				December 31, 2013
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	128		3	$	856		3
Net Credit Risk to Single Largest Counterparty	$	83			$	530

OTP had a net credit risk exposure to three counterparties with investment grade credit ratings. OTP had no exposure at March 31, 2014 or December 31, 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 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 March 31, 2014. 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 amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of March 31, 2014 and December 31, 2013 are indicated in the following table:

(in thousands)	March 31, 2014			December 31, 2013
Derivative assets subject to legally enforceable netting arrangements	$	1,629		$	400
Derivative liabilities subject to legally enforceable netting arrangements		(8,252	)		(11,782	)
Net balance subject to legally enforceable netting arrangements	$	(6,623	)	$	(11,382	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of March 31, 2014 and December 31, 2013:

Current Liability – Marked-to-Market Loss (in thousands)	March 31, 2014			December 31, 2013
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	--
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		8,252			11,679
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			103
Total Current Liability – Marked-to-Market Loss	$	8,252		$	11,782
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	$	8,252		$	11,679
Offsetting Gains with Counterparties under Master Netting Agreements		(1,569	)		(117	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	6,683		$	11,562

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2014

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:

	March 31, 2014						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	4,043	$	54,038	$	58,081	see note
Deferred Marked-to-Market Losses1		3,258		4,994		8,252	57 months
Conservation Improvement Program Costs and Incentives2		3,533		4,580		8,113	15 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,779		4,779	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		566		3,857		4,423	78 months
Recoverable Fuel and Purchased Power Costs1		3,540		--		3,540	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,452		1,419		2,871	21 months
Debt Reacquisition Premiums1		361		2,154		2,515	222 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,071		--		2,071	15 months
Deferred Income Taxes1		--		2,013		2,013	asset lives
Minnesota Transmission Rider Accrued Revenues2		1,153		--		1,153	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		101		818		919	110 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		119		119	24 months
South Dakota Transmission Rider Accrued Revenues2		107		--		107	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		14		--		14	3 months
Total Regulatory Assets	$	20,199	$	78,839	$	99,038
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,943	$	71,943	asset lives
Deferred Income Taxes		--		1,869		1,869	asset lives
Deferred Marked-to-Market Gains		533		1,037		1,570	53 months
North Dakota Renewable Resource Rider Accrued Refund		1,436		--		1,436	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		412		412	see note
Big Stone II Over Recovered Project Costs – North Dakota		144		--		144	6 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		104		110	237 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		56		--		56	12 months
North Dakota Transmission Rider Accrued Refund		32		--		32	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		21		--		21	12 months
Total Regulatory Liabilities	$	2,228	$	75,365	$	77,593
Net Regulatory Asset Position	$	17,971	$	3,474	$	21,445
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, 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	$	4,095	$	55,012	$	59,107	see note
Deferred Marked-to-Market Losses1		3,008		8,674		11,682	60 months
Conservation Improvement Program Costs and Incentives2		4,945		3,959		8,904	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,646		4,646	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		558		3,967		4,525	81 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,351		1,753		3,104	24 months
Debt Reacquisition Premiums1		351		2,241		2,592	225 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,331		--		2,331	12 months
Deferred Income Taxes1		--		1,805		1,805	asset lives
Big Stone II Unrecovered Project Costs – South Dakota2		101		843		944	113 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		762		762	15 months
Recoverable Fuel and Purchased Power Costs1		760		--		760	12 months
Big Stone II Unrecovered Project Costs – North Dakota1		375		--		375	3 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
South Dakota Transmission Rider Accrued Revenues2		32		--		32	12 months
Deferred Holding Company Formation Costs1		27		--		27	6 months
General Rate Case Recoverable Expenses – South Dakota1		6		--		6	1 month
Total Regulatory Assets	$	17,940	$	83,730	$	101,670
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,454	$	71,454	asset lives
Deferred Income Taxes		--		1,960		1,960	asset lives
Minnesota Transmission Rider Accrued Refund		670		--		670	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		289		289	see note
North Dakota Renewable Resource Rider Accrued Refund		261		--		261	12 months
North Dakota Transmission Rider Accrued Refund		215		--		215	12 months
Deferred Marked-to-Market Gains		6		117		123	56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		5		106		111	240 months
South Dakota – Nonasset-Based Margin Sharing Excess		38		--		38	12 months
Total Regulatory Liabilities	$	1,195	$	73,926	$	75,121
Net Regulatory Asset Position	$	16,745	$	9,804	$	26,549
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 March 31, 2014 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.

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

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

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 March 31, 2014 balance is being amortized on a straight-line basis over two consecutive 12-month periods that began in January 2014.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 222 months.

North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.

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

Minnesota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers net of transmission revenues that have not been billed to Minnesota customers as of March 31, 2014.

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.

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2014 and that are not scheduled to be recovered prior to March 31, 2015.

South Dakota Transmission Rider Accrued Revenues relate to revenues earned 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 March 31, 2014.

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. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

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

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2014.

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.

Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of 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. The March 31, 2014 liability will be refunded to North Dakota customers through an adjustment to revenue requirements under the North Dakota TCR rider.

The Minnesota Environmental Cost Recovery Rider Accrued refund relates to amounts billed under the Minnesota ECR rider in excess of an allowed return granted on the Minnesota share of amounts invested in the construction of the Big Stone Plant AQCS project.

The North Dakota Transmission Rider Accrued Refund relates to amounts collected for 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 March 31, 2014.

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

If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

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) 815, Derivatives and Hedging. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

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 March 31,
	2014			2013
Percentage-of-Completion Revenues		9.1	%		12.1	%

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs Incurred on Uncompleted Contracts	$	364,005		$	361,487
Less Billings to Date		(377,991	)		(377,608	)
Plus Estimated Earnings Recognized		7,628			6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

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

	March 31,			December 31,
(in thousands)	2014			2013
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,719		$	4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(10,077	)		(13,707	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(6,358	)	$	(9,644	)

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.

Warranty Reserves

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The warranty reserve balance as of December 31, 2013 and March 31, 2014 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies and is included in liabilities of discontinued operations. See note 17 to condensed 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:

	March 31,		December 31,
(in thousands)	2014		2013
Accounts Receivable Retained by Customers	$	6,352	$	7,125	1
1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

Fair Value Measurements

Fair Value Measurements

The Company follows Accounting Standards Codification (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 March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	1,609
Forward Gasoline Purchase Contracts				20
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,438
U.S. Government Debt Securities – Held by Captive Insurance Company				964
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		745
Total Assets	$	865	$	8,422	$	1,609
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	--	$	8,252
Total Liabilities	$	--	$	--	$	8,252

December 31, 2013 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	338
Forward Gasoline Purchase Contracts				62
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				7,671
U.S. Government Debt Securities – Held by Captive Insurance Company				1,271
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		866
Total Assets	$	976	$	9,004	$	338
Liabilities:
Derivative Liabilities - Forward Energy Contracts	$	--	$	103	$	11,679
Total Liabilities	$	--	$	103	$	11,679

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 March 31, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. 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 March 31, 2014 Level 3 forward electric price inputs ranged from $1.52 to $7.00 per megawatt-hour underthe active trading hub price. The weighted average price was $36.77 per megawatt-hour.

In the table above, $1,569,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $8,252,000 of the fair value of the Level 3 forward energy contracts in a derivative liability position as of March 31, 2014 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 month periods ended March 31, 2014 or 2013.

The remaining $40,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position as of March 31, 2014 are related to financial contracts that will not be settled by physical delivery of electricity but will be settled financially by the counterparty to the contract paying or receiving the difference between the contract price and the market price at the hour of scheduled delivery. The related forward energy sales contracts are not offset by forward energy purchase contracts. Therefore, the $40,000 in derivative gains related to these contracts as of March 31, 2014 are subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in April and May of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the fair value of the contracts.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Forward Energy Contracts - Fair Values Beginning of Period	$	(11,341	)	$	(17,782	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		1,160			2,195
Changes in Fair Value of Contracts Entered into in Prior Periods		3,498			3,320
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(6,683	)		(12,267	)
Net Gain Recognized as Regulatory Assets on contract entered into in Period		40			32
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(6,643	)	$	(12,235	)

Inventories

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2014		2013
Finished Goods	$	25,611	$	20,649
Work in Process		9,654		9,942
Raw Material, Fuel and Supplies		46,610		42,090
Total Inventories	$	81,875	$	72,681

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

In the first quarter of 2014, Aevenia, Inc. (Aevenia) recorded a $289,000 gain on the sale of its data communication installation and services business which, over the years of its existence, did not provide a materially significant impact to Aevenia’s operating results. In connection with this sale, Aevenia disposed of $163,000 in goodwill associated with the purchase of this business in May 2004.

The following table summarizes changes to goodwill by business segment during 2014:

(in thousands)	Gross Balance December 31, 2013		Accumulated Impairments		Balance (net of impairments) December 31, 2013		Adjustments to Goodwill in 2014		Balance (net of impairments) March 31, 2014
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Construction		7,483		--		7,483		163		7,320
Total	$	38,971	$	--	$	38,971	$	163	$	38,808

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. The following table summarizes the components of the Company’s intangible assets at March 31, 2014 and December 31, 2013:

March 31, 2014 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,147	$	11,664	15 – 25 years
Other Intangible Assets Including Contracts		825		505		320	5 – 30 years
Total	$	17,636	$	5,652	$	11,984
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100
December 31, 2013(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	4,935	$	11,876	15 – 25 years
Other Intangible Assets Including Contracts		825		473		352	5 – 30 years
Total	$	17,636	$	5,408	$	12,228
Indefinite-Lived Intangible Assets:
Trade Name	$	1,100		--	$	1,100

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2014		2013
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2014		2015		2016		2017		2018
Estimated Amortization Expense – Intangible Assets	$	977	$	977	$	945	$	849	$	849

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2014		2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	22,244	$	8,901
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	3,434	$	--
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, has 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 and 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 March 31, 2014 is $10.9 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 as of March 31, 2014 could be as high as $10.9 million.

Revisions to Presentation

Revisions to Presentation

Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the three months ended March 31, 2013 have been revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for the three months ended March 31, 2014. The change in presentation of 2013 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for the three month period ended March 31, 2013.

New Accounting Standards

New Accounting Standards

Accounting Standards Update (ASU) 2013-11

In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis. The Company’s long-term deferred income tax reported on its March 31, 2014 consolidated balance sheet include $4.3 million of unrecognized tax benefits.

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2014

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 obligations are short-term and the balances outstanding as of March 31, 2014 related to the Otter Tail Corporation Credit Agreement and December 31, 2013 related to the OTP Credit Agreement were subject to a variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.

Long-Term Debt including Current Maturities—The fair value of the Company’s and OTP’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, Fair Value Measurement.

	March 31, 2014						December 31, 2013
(in thousands)	Carrying Amount			Fair Value			Carrying  Amount			Fair Value
Cash and Cash Equivalents	$	6,613		$	6,613		$	1,150		$	1,150
Short-Term Debt	$	(11,899	)	$	(11,899	)		(51,195	)		(51,195	)
Long-Term Debt including Current Maturities	$	(498,831	)	$	(546,269	)		(389,777	)		(427,796	)

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Fair Value of Financial Instruments (Detail Textuals)	3 Months Ended	12 Months Ended
	Mar. 31, 2014 Otter Tail Corporation Credit Agreement	Dec. 31, 2013 OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis	LIBOR	LIBOR
Basis spread on variable rate	1.75%	1.25%

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Retained Earnings Restriction

3 Months Ended

Mar. 31, 2014

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 March 31, 2014 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, 2013 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 47.2% as of March 31, 2014. Total capitalization for OTP cannot currently exceed $874 million.

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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 $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Forward Electricity Contracts
Derivatives Fair Value [Roll Forward]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$ 115,000	$ 49,000
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods	(72,000)	(49,000)
Changes in Fair Value of Contracts Entered into in Prior Periods	(43,000)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period
Changes in Fair Value of Contracts Entered into in Current Period	39,000	81,000
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$ 39,000	$ 81,000

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

3 Months Ended

Mar. 31, 2014

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, 2013	$	181,358		$	255,759		$	99,441		$	(1,728	)	$	534,830
Common Stock Issuances, Net of Expenses		748			3,504									4,252
Common Stock Retirements		(44	)		(198	)								(242	)
Net Income								21,430						21,430
Other Comprehensive Income											8			8
Tax Benefit – Stock Compensation					31									31
Employee Stock Incentive Plans Expense					358									358
Common Dividends								(10,993	)					(10,993	)
Balance, March 31, 2014	$	182,062		$	259,454		$	109,878		$	(1,720	)	$	549,674

Common Shares

In 2014, the Company began issuing shares to meet the requirements of its dividend reinvestment, employee stock ownership, and employee stock purchase plans and shareholder stock purchase program, rather than purchasing shares in the open market. Following is a reconciliation of the Company’s common shares outstanding from December 31, 2013 through March 31, 2014:

Common Shares Outstanding, December 31, 2013	36,271,696
Issuances:
Dividend Reinvestments	49,402
Employee Stock Ownership Plan	22,650
Executive Stock Performance Awards (2011-2013 shares earned)	22,630
Employee Stock Purchase Plan	19,661
Shareholder Stock Purchase Program	18,681
Stock Options Exercised	16,650
Retirements:
Shares Withheld for Individual Income Tax Requirements	(8,879	)
Common Shares Outstanding, March 31, 2014	36,412,491

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 month periods ended March 31, 2014 and 2013. 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. Adjustments to the denominator used to calculate diluted earnings per share of 191,565 shares and 183,984 shares for the three month periods ended March 31, 2014 and 2013, respectively, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either quarter.

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Share-Based Payments

3 Months Ended

Mar. 31, 2014

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

Share-Based Payments

7. Share-Based Payments

The Company has five share-based payment programs. No new stock awards were granted under these programs in the first quarter of 2014. As of March 31, 2014 the remaining unrecognized compensation expense related to stock-based compensation was approximately $3.6 million (before income taxes) which will be amortized over a weighted-average period of 1.8 years.

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three month periods ended March 31, 2014 and 2013 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2014		2013
Employee Stock Purchase Plan (15% discount)	$	42	$	17
Restricted Stock Granted to Directors		123		207
Restricted Stock Granted to Employees		135		92
Restricted Stock Units Granted to Employees		58		75
Stock Performance Awards Granted to Executive Officers		526		1,098
Totals	$	884	$	1,489

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2013 OTP had commitments under contracts in connection with construction programs aggregating approximately $108.2 million. At March 31, 2014 OTP had commitments under contracts in connection with construction programs aggregating approximately $103.2 million. The decrease in construction commitments from December 31, 2013 to March 31, 2014 is mainly for OTP’s share of commitments related to the construction of the Big Stone Plant AQCS pertaining to materials and services ordered or under contract as of December 31, 2013 that were received in the first quarter of 2014.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending through 2038. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. 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, 2015, 2016 and 2040. OTP entered into no additional agreements for the purchase of capacity or to meet energy requirements or for the purchase of coal to meet its remaining coal requirements in the first quarter of 2014.

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 March 31, 2014 will not be material.

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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	Mar. 31, 2014		Dec. 31, 2013
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	8,252	[1]	11,679	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements			103
Total Current Liability - Marked-to-Market Loss	$ 8,252		$ 11,782

[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 $ 8,252 $ 11,679 Offsetting Gains with Counterparties under Master Netting Agreements (1,569) (117) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 6,683 $ 11,562

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Income Tax Expense - Continuing operations effective income tax rate (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 29,650	$ 21,120
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	11,563	8,237
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)	(2,252)	(1,589)
Section 199 Domestic Production Activities Deduction	(358)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(212)	(223)
Employee Stock Ownership Plan Dividend Deduction	(189)	(190)
AFUDC Equity	(133)	(115)
Corporate Owned Life Insurance	(112)	(302)
Other Items - Net	(19)	68
Income Tax Expense - Continuing Operations	$ 8,288	$ 5,886
Effective Income Tax Rate - Continuing Operations	28.00%	27.90%

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Forward Contracts Classified as Derivatives (Detail Textuals) (Otter Tail Power Company, USD $)	3 Months Ended
	Mar. 31, 2014
Derivative [Line Items]
Unrealized gain on derivatives	$ 39,000
Investment grade credit ratings
Derivative [Line Items]
Counterparties	3

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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	Mar. 31, 2014	Dec. 31, 2013
Legally enforceable netting arrangements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative assets subject to legally enforceable netting arrangements	$ 1,629	$ 400
Derivative liabilities subject to legally enforceable netting arrangements	(8,252)	(11,782)
Net balance subject to legally enforceable netting arrangements	$ (6,623)	$ (11,382)

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Subsequent Events - Stock Incentive Awards (Details) (Subsequent Event, USD $)	0 Months Ended
	Apr. 14, 2014
Restricted Stock | Nonemployee Directors
Subsequent Event [Line Items]
Shares/Units Granted	16,800
Grant-Date Fair Value per Award	$ 29.41
Vesting Percentage	25.00%
Vesting Date	April 8, 2018
Restricted Stock | Executive Officers
Subsequent Event [Line Items]
Shares/Units Granted	26,700
Grant-Date Fair Value per Award	$ 29.41
Vesting Percentage	25.00%
Vesting Date	April 8, 2018
Stock Performance Awards | Executive Officers
Subsequent Event [Line Items]
Shares/Units Granted	115,200
Grant-Date Fair Value per Award	$ 22.94
Vesting Date	December 31, 2016
Restricted Stock Units | Employees
Subsequent Event [Line Items]
Shares/Units Granted	11,800
Grant-Date Fair Value per Award	$ 24.95
Vesting Percentage	100.00%
Vesting Date	April 8, 2018

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations

	For the Three Months Ended March 31,
(in thousands)	2014			2013
Operating Revenues	$	--		$	2,009
Operating Expenses		(117	)		2,707
Operating Income (Loss)		117			(698	)
Other Income		--			412
Income Tax Benefit		(49	)		(205	)
Net Income (Loss) from Operations		68			(81	)
Gain on Disposition Before Taxes		--			216
Income Tax Expense on Disposition		--			6
Net Gain on Disposition		--			210
Net Income	$	68		$	129

(in thousands)	March 31,  2014		December 31,  2013
Current Assets	$	38	$	38
Assets of Discontinued Operations	$	38	$	38
Current Liabilities	$	3,442	$	3,637
Liabilities of Discontinued Operations	$	3,442	$	3,637

Schedule of warranty reserves

(in thousands)	2014			2013
Warranty Reserve Balance, January 1	$	3,087		$	5,027
Provision for Warranties Used During the Year		--			120
Less Settlements Made During the Year		--			(583	)
Decrease in Warranty Estimates for Prior Years		(100	)		(63	)
Warranty Reserve Balance, March 31	$	2,987		$	4,501

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Summary of Significant Accounting Policies (Detail Textuals 2) (Aevenia, Inc., USD $)	3 Months Ended
	Mar. 31, 2014
Aevenia, Inc.
Significant Accounting Policies [Line Items]
Gain on the sale of a group of assets	$ 289,000
Disposal of goodwill in connection with sale of Aevenia	$ 163,000

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Discontinued Operations

3 Months Ended

Mar. 31, 2014

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 former wind tower manufacturing company and on February 29, 2012 the Company completed the sale of DMS Health Technologies, Inc. (DMS) and recorded an additional $0.2 million gain on the sale in the first quarter of 2013 related to a working capital true up. Following are summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2014 and 2013, which mainly includes residual revenues and expenses from the Company’s former wind tower and waterfront equipment manufacturers and the additional $0.2 million gain on the sale of DMS in the first quarter of 2013:

	For the Three Months Ended March 31,
(in thousands)	2014			2013
Operating Revenues	$	--		$	2,009
Operating Expenses		(117	)		2,707
Operating Income (Loss)		117			(698	)
Other Income		--			412
Income Tax Benefit		(49	)		(205	)
Net Income (Loss) from Operations		68			(81	)
Gain on Disposition Before Taxes		--			216
Income Tax Expense on Disposition		--			6
Net Gain on Disposition		--			210
Net Income	$	68		$	129

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2014 and December 31, 2013:

(in thousands)	March 31,  2014		December 31,  2013
Current Assets	$	38	$	38
Assets of Discontinued Operations	$	38	$	38
Current Liabilities	$	3,442	$	3,637
Liabilities of Discontinued Operations	$	3,442	$	3,637

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

(in thousands)	2014			2013
Warranty Reserve Balance, January 1	$	3,087		$	5,027
Provision for Warranties Used During the Year		--			120
Less Settlements Made During the Year		--			(583	)
Decrease in Warranty Estimates for Prior Years		(100	)		(63	)
Warranty Reserve Balance, March 31	$	2,987		$	4,501

The warranty reserve balances as of March 31, 2014 and December 31, 2013 relate 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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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of amount of regulatory assets and liabilities

	March 31, 2014						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	4,043	$	54,038	$	58,081	see note
Deferred Marked-to-Market Losses1		3,258		4,994		8,252	57 months
Conservation Improvement Program Costs and Incentives2		3,533		4,580		8,113	15 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,779		4,779	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		566		3,857		4,423	78 months
Recoverable Fuel and Purchased Power Costs1		3,540		--		3,540	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,452		1,419		2,871	21 months
Debt Reacquisition Premiums1		361		2,154		2,515	222 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,071		--		2,071	15 months
Deferred Income Taxes1		--		2,013		2,013	asset lives
Minnesota Transmission Rider Accrued Revenues2		1,153		--		1,153	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		101		818		919	110 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		119		119	24 months
South Dakota Transmission Rider Accrued Revenues2		107		--		107	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
Deferred Holding Company Formation Costs1		14		--		14	3 months
Total Regulatory Assets	$	20,199	$	78,839	$	99,038
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,943	$	71,943	asset lives
Deferred Income Taxes		--		1,869		1,869	asset lives
Deferred Marked-to-Market Gains		533		1,037		1,570	53 months
North Dakota Renewable Resource Rider Accrued Refund		1,436		--		1,436	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		412		412	see note
Big Stone II Over Recovered Project Costs – North Dakota		144		--		144	6 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		104		110	237 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		56		--		56	12 months
North Dakota Transmission Rider Accrued Refund		32		--		32	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		21		--		21	12 months
Total Regulatory Liabilities	$	2,228	$	75,365	$	77,593
Net Regulatory Asset Position	$	17,971	$	3,474	$	21,445
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, 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	$	4,095	$	55,012	$	59,107	see note
Deferred Marked-to-Market Losses1		3,008		8,674		11,682	60 months
Conservation Improvement Program Costs and Incentives2		4,945		3,959		8,904	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		4,646		4,646	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		558		3,967		4,525	81 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,351		1,753		3,104	24 months
Debt Reacquisition Premiums1		351		2,241		2,592	225 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,331		--		2,331	12 months
Deferred Income Taxes1		--		1,805		1,805	asset lives
Big Stone II Unrecovered Project Costs – South Dakota2		101		843		944	113 months
North Dakota Renewable Resource Rider Accrued Revenues2		--		762		762	15 months
Recoverable Fuel and Purchased Power Costs1		760		--		760	12 months
Big Stone II Unrecovered Project Costs – North Dakota1		375		--		375	3 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
South Dakota Transmission Rider Accrued Revenues2		32		--		32	12 months
Deferred Holding Company Formation Costs1		27		--		27	6 months
General Rate Case Recoverable Expenses – South Dakota1		6		--		6	1 month
Total Regulatory Assets	$	17,940	$	83,730	$	101,670
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,454	$	71,454	asset lives
Deferred Income Taxes		--		1,960		1,960	asset lives
Minnesota Transmission Rider Accrued Refund		670		--		670	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		289		289	see note
North Dakota Renewable Resource Rider Accrued Refund		261		--		261	12 months
North Dakota Transmission Rider Accrued Refund		215		--		215	12 months
Deferred Marked-to-Market Gains		6		117		123	56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		5		106		111	240 months
South Dakota – Nonasset-Based Margin Sharing Excess		38		--		38	12 months
Total Regulatory Liabilities	$	1,195	$	73,926	$	75,121
Net Regulatory Asset Position	$	16,745	$	9,804	$	26,549
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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Summary of Significant Accounting Policies (Detail Textuals) (Forward Electricity Contracts, Level 3, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Significant Accounting Policies [Line Items]
Electric inputs minimum deviation below active trade hub prices	1.52
Electric inputs maximum deviation below active trading hub price per megawatt-hour	7.00
Electric inputs weighted average price per megawatt-hour	36.77
Power purchase contracts
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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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	Mar. 31, 2014	Dec. 31, 2013
Level 1
Assets:
Total Assets	$ 865	$ 976
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Liabilities:
Derivative Liabilities:
Level 1 | Money Market and Mutual Funds
Assets:
Other Current Assets - Nonqualified Retirement Savings Plan	120	110
Other Assets - Nonqualified Retirement Savings Plan	745	866
Level 2
Assets:
Total Assets	8,422	9,004
Liabilities:
Total Liabilities		103
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets
Liabilities:
Derivative Liabilities:		103
Level 2 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets	20	62
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	7,438	7,671
Level 2 | U.S. Government Debt Securities
Assets:
Investments - Held by Captive Insurance Company	964	1,271
Level 3
Assets:
Total Assets	1,609	338
Liabilities:
Total Liabilities	8,252	11,679
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	1,609	338
Liabilities:
Derivative Liabilities:	$ 8,252	$ 11,679

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Consolidated Statements of Income (not audited) (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Statement [Abstract]
Income tax expense (benefit) on Income (Loss) from discontinued operation	$ 49	$ (205)
Income Tax (Benefit) Expense on Disposition		$ 6

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Discontinued Operations - Results of discontinued operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Income (Loss) from Operations	$ 68	$ (81)
Income Tax Expense on Disposition		6
Net Gain on Disposition		210
Net Income	68	129
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		2,009
Operating Expenses	(117)	2,707
Operating Income (Loss)	117	(698)
Other Income		412
Income Tax Benefit	(49)	(205)
Net Income (Loss) from Operations	68	(81)
Gain on Disposition Before Taxes		216
Income Tax Expense on Disposition		6
Net Gain on Disposition		210
Net Income	$ 68	$ 129

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Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2014

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2014 and 2013.

Major Capital Expenditure Projects

Multi-Value Transmission Projects—On December 16, 2010, FERC approved the cost allocation for a new classification of projects in the MISO region 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 areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. Effective January 1, 2012, the FERC authorized OTP to recover 100% of prudently incurred Construction Work in Progress (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. Abandoned Plant recovery provides a basis for OTP to request recovery of prudently incurred costs in the event a project is cancelled for reasons beyond OTP’s control. On February 24, 2014 the U.S. Supreme Court denied petitions for a writ of certiorari of the United States Court of Appeals, Seventh Circuit decision upholding the FERC’s MVP orders. The petitioners did not seek rehearing. The following projects have been approved by MISO as MVPs under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff).

The Big Stone South – Brookings Project—This is a planned 345 kiloVolt (kV) transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. This line is expected to be in service in 2017. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. The SDPUC granted OTP and Xcel Energy approval of a route permit for the southern portion of the Big Stone South - Brookings line on February 18, 2014.

The Big Stone South – Ellendale Project—This is a proposed 345 kV transmission 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 on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor Compatibility along with an application for a route permit with the NDPSC on October 18, 2013.

Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kV Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji–Grand Rapids 230 kV Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project. Recovery of OTP’s CapX2020 transmission investments is through the MISO Tariff (the Brookings Project as an MVP) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (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. The St. Cloud to Alexandria portion of the Fargo Project was placed into service April 23, 2014. Construction is underway for the remaining portions of the project.

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 also granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011.The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized on April 29, 2014.

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

Big Stone Plant Air Quality Control System (AQCS)—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 the EPA agreed on non-substantive rule revisions, which were adopted by the South Dakota 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 AQCS 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.

OTP is currently in the process of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through March 31, 2014 is $113 million.

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. OTP requested jurisdictional recovery in Minnesota, North Dakota and South Dakota of amounts it had invested in the Big Stone II Project at the time of its withdrawal, which are discussed below.

Minnesota

2010 General Rate Case—OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (MNCIP) costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota Fuel Clause Adjustment.

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 potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

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

The costs for three major wind farms previously approved by the MPUC for recovery through OTP’s Minnesota Renewable Resource Adjustment (MNRRA) were 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. Effective May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs.

Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal.

The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

In December 2012, the MPUC 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. 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 recognized $3.9 million in MNCIP financial incentives in 2013 related to the results of its conservation improvement programs in Minnesota in 2013. On April 1, 2014 OTP submitted its annual 2013 financial incentive filing request for $4.0 million along with a request for an updated surcharge rate with a proposed implementation date of July 1, 2014.

OTP had a regulatory asset of $8.1 million for allowable costs and financial incentives eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of March 31, 2014. OTP recognized revenue for Minnesota conservation costs and incentives earned totaling $1.5 million in the three month period ended March 31, 2014, compared with $1.6 million in the three month period ended March 31, 2013.

Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or 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. 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.

MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers. On March 26, 2012 the MPUC approved an update to OTP’s Minnesota TCR rider along with an all-in method for MISO regional cost allocations in which OTP’s retail customers would be responsible for the entire investment OTP made in transmission facilities that qualify for regional cost allocation under the MISO Tariff, with an offsetting credit for revenues received from other MISO utilities under the MISO Tariff for projects included in the TCR. OTP’s updated Minnesota TCR rider went into effect April 1, 2012.

On May 24, 2012 OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery through the TCR rider. OTP filed its annual update to the TCR rider on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of CON estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC approval of OTP’s annual TCR update, OTP submitted compliance filings in April 2014 seeking no rate change. OTP filed its 2014 annual update on May 1, 2014 with a proposed implementation date of July 1, 2014.

OTP had a regulatory asset of $1.2 million as of March 31, 2014 for amounts eligible for recovery through the Minnesota TCR rider that had not been billed to Minnesota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota TCR rider of $2.3 million in the three month period ended March 31, 2014, compared with $1.0 million in the three month period ended March 31, 2013.

Environmental Cost Recovery (ECR) Rider—In a written order issued on January 23, 2012 the MPUC granted OTP’s petition for Advance Determination of Prudence (ADP) for costs associated with the design, construction and operation of the BART-compliant AQCS at Big Stone Plant attributable to serving OTP’s Minnesota customers. On May 24, 2013 legislation was enacted in Minnesota which allowed OTP to file 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 OTP’s most recent general rate case, unless a different return is determined by the MPUC to be in the public interest. On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. The rate will be updated in an annual filing with the MPUC until the costs are rolled into base rates at an undetermined future date.

OTP had a regulatory liability of $0.1 million as of March 31, 2014 for amounts billed to Minnesota customers that were subject to refund through the Minnesota ECR rider. OTP recognized revenue for amounts eligible for recovery through the Minnesota ECR rider of $1.8 million in the three month period ended March 31, 2014.

Big Stone II Cost Recovery—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 as part of the rates established in that proceeding was $3.2 million. Because OTP will not earn a return on these deferred costs over the 60-month recovery period, the recoverable amount of $3.2 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate, in accordance with ASC Topic 980, Regulated Operations (ASC 980), accounting requirements.Transmission-related project costs of $3.2 million remained in CWIP as active project costs.

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, along with accumulated AFUDC, were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota 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 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 which began in May 2013.

North Dakota

General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009.

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables 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. On March 21, 2012 the NDPSC approved an update to OTP’s NDRRA effective April 1, 2012. The updated NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. 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 updated rates implemented on April 1, 2013. The NDPSC approved OTP’s most recent annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014. The update approved on March 12, 2014 resulted in a 13.5% reduction in the NDRRA rate.

OTP had a net regulatory liability of $1.3 million as of March 31, 2014 for amounts billed to North Dakota customers that were subject to refund through the NDRRA rider. OTP recognized revenue for amounts eligible for recovery through the NDRRA rider of $1.4 million in the three month period ended March 31, 2014, compared with $2.3 million in the three month period ended March 31, 2013.

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014.

OTP had a regulatory liability of less than $0.1 million as of March 31, 2014 for amounts billed to North Dakota customers that were subject to refund through the North Dakota TCR rider. OTP recognized revenue for amounts eligible for recovery through the North Dakota TCR rider of $1.5 million in the three month period ended March 31, 2014, compared with $0.8 million in the three month period ended March 31, 2013.

Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate with a proposed implementation date of July 1, 2014. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The ECR rider rate will continue to be updated at least annually in a filing with the NDPSC until the project costs are rolled into base rates at an undetermined future date.

OTP had a regulatory asset of $2.1 million as of March 31, 2014 for amounts eligible for recovery through the North Dakota ECR rider that had not been billed to North Dakota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota ECR rider of $1.5 million in the three month period ended March 31, 2014, compared with $0.7 million in the three month period ended March 31, 2013.

Big Stone II Cost Recovery—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 total amount of Big Stone II generation costs incurred by OTP (which excluded $2.6 million of project transmission-related costs) was determined to be $10.1 million, of which $4.1 million represents North Dakota’s jurisdictional share.

OTP is including in its total recovery amount a carrying charge of approximately $0.3 million on the North Dakota share of Big Stone II generation costs for the period from September 1, 2009 through the date the recovery of costs begins based on OTP’s average 2009 AFUDC rate of 7.65%. Because OTP will not earn a return on these deferred costs over the 36-month recovery period, the recoverable amount of $4.3 million was discounted to its then present value of $3.9 million using OTP’s incremental borrowing rate, in accordance with ASC 980 accounting requirements. The North Dakota portion of Big Stone II generation costs was 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. 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. On July 30, 2013 the NDPSC approved OTP’s request to continue the Big Stone II cost recovery rates for an additional eight months through March 31, 2014 to recover the remaining North Dakota share of Big Stone II transmission-related costs plus accrued AFUDC totaling $1.0 million. As of April 1, 2014 North Dakota customer’s bills no longer include a charge for North Dakota share of Big Stone II costs. OTP had a regulatory liability of $0.1 million as of March 31, 2014 for amounts billed to North Dakota customers that will be subject to refund through the North Dakota TCR rider.

South Dakota

2010 General Rate Case—On April 21, 2011 the SDPUC issued a written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50% for the interim rates and final rates for OTP in South Dakota. Final rates were effective with bills rendered on and after June 1, 2011.

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP submitted a request for an initial South Dakota TCR rider to the SDPUC on November 5, 2010. The South Dakota TCR was approved by the SDPUC and implemented on December 1, 2011. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s most recent annual update to its South Dakota TCR on February 18, 2014 with an effective date of March 1, 2014.

OTP had a regulatory asset of $0.1 million as of March 31, 2014 for amounts eligible for recovery through the South Dakota TCR rider that had not been billed to South Dakota customers as of March 31, 2014. OTP recognized revenue for amounts eligible for recovery through the South Dakota TCR rider of $0.3 million in the three month period ended March 31, 2014, compared with $0.1 million in the three month period ended March 31, 2013.

Environmental Cost Recovery Rider—On March 30, 2012 OTP requested approval from the SDPUC for an ECR rider to recover costs associated with the Big Stone Plant AQCS. 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 Cost Recovery—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 is allowed to earn a return on the amount subject to recovery over the ten-year recovery period. Therefore, the South Dakota settlement amount is not discounted. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP.

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.

Federal

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

Effective January 1, 2010 the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Tariff. OTP was also authorized by the FERC to recover in its formula rate: (1) 100% of prudently incurred CWIP in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects in which OTP is invested.

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint at the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. The complaint is pending at the FERC.

Environmental Protection Agency (EPA) Cross-State Air Pollution Rule (CSPAR)

On April 29, 2014 the U.S. Supreme Court issued its opinion in litigation concerning EPA’s CSAPR, reversing the August 21, 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated CSAPR. The Supreme Court’s opinion does not remove or otherwise address the D.C. Circuit’s December 30, 2011 order staying CSAPR. CSAPR will now be remanded to the D.C. Circuit for further proceedings; however, CSAPR will continue to be stayed until the D.C. Circuit in the future lifts or modifies the stay. Therefore, at this time implementation and compliance dates for the rule are unknown.

The CSAPR rule that was vacated in 2012 would have applied to OTP’s Solway gas peaking plant and the Hoot Lake coal-fired plant in Minnesota. The primary impact of the rule would have been for Hoot Lake Plant to acquire sulfur dioxide (SO2) allowances to continue operating at historical levels. Based on Hoot Lake’s historical generation and EPA’s predicted allowance costs at the time of the 2012 rule, CSAPR would have resulted in annual SO2 allowance purchase costs of approximately $1.0 million.

XML

Regulatory Assets and Liabilities (Detail Textuals)	3 Months Ended
	Mar. 31, 2014
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	222 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%

XML

Pension Plan and Other Postretirement Benefits (Detail Textuals) (Pension Plan, USD $) In Thousands, unless otherwise specified	1 Months Ended
	Jan. 31, 2014	Jan. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discretionary plan contributions	$ 20,000,000	$ 10,000,000

XML

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Stockholders Equity and Earnings Per Share [Abstract]
Adjustments to denominator diluted earnings per share	191,565	183,984
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations	$ 0.01	$ 0.01

XML

Forward Contracts Classified as Derivatives (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule for balance sheet location and fair value amounts of the company's forward energy contracts classified as derivatives

(in thousands)	March 31, 2014			December 31, 2013
Current Asset – Marked-to-Market Gain	$	1,609		$	338
Regulatory Asset – Current Deferred Marked-to-Market Loss		3,258			3,008
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		4,994			8,674
Total Assets		9,861			12,020
Current Liability – Marked-to-Market Loss		(8,252	)		(11,782	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(533	)		(6	)
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(1,037	)		(117	)
Total Liabilities		(9,822	)		(11,905	)
Net Fair Value of Marked-to-Market Energy Contracts	$	39		$	115

Schedule of change in the consolidated balance sheet position of the company's forward energy contracts classified as derivatives

(in thousands)	Year-to-Date March 31, 2014			Year-to-Date March 31, 2013
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	115		$	49
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
Changes in Fair Value of Contracts Entered into in Current Period		39			81
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	39		$	81

Schedule of realized and unrealized net gains on forward energy contracts

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Net (Loss) Gain on Forward Electric Energy Contracts	$	(4	)	$	226

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

	March 31, 2014				December 31, 2013
(in thousands)	Exposure		Counterparties		Exposure		Counterparties
Net Credit Risk on Forward Energy Contracts	$	128		3	$	856		3
Net Credit Risk to Single Largest Counterparty	$	83			$	530

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

(in thousands)	March 31, 2014			December 31, 2013
Derivative assets subject to legally enforceable netting arrangements	$	1,629		$	400
Derivative liabilities subject to legally enforceable netting arrangements		(8,252	)		(11,782	)
Net balance subject to legally enforceable netting arrangements	$	(6,623	)	$	(11,382	)

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)	March 31, 2014			December 31, 2013
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--		$	--
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		8,252			11,679
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			103
Total Current Liability – Marked-to-Market Loss	$	8,252		$	11,782
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	$	8,252		$	11,679
Offsetting Gains with Counterparties under Master Netting Agreements		(1,569	)		(117	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	6,683		$	11,562

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Commitments and Contingencies (Detail Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Line Items]
Loss contingency, range of possible loss, maximum	$ 2.0
Otter Tail Power Company | Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year	2038
Otter Tail Power Company | Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year	2014, 2015, 2016 and 2040
Otter Tail Power Company | Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$ 103.2	$ 108.2

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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	Mar. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$ 3,719	$ 4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(10,077)	(13,707)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (6,358)	$ (9,644)

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Income Tax Expense Continuing Operations

3 Months Ended

Mar. 31, 2014

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 periods ended March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands)	2014			2013
Income Before Income Taxes – Continuing Operations	$	29,650		$	21,120
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		11,563			8,237
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(2,252	)		(1,589	)
Section 199 Domestic Production Activities Deduction		(358	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(223	)
Employee Stock Ownership Plan Dividend Deduction		(189	)		(190	)
AFUDC Equity		(133	)		(115	)
Corporate Owned Life Insurance		(112	)		(302	)
Other Items – Net		(19	)		68
Income Tax Expense – Continuing Operations	$	8,288		$	5,886
Effective Income Tax Rate – Continuing Operations		28.0	%		27.9	%

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

(in thousands)	2014		2013
Balance on January 1	$	4,239	$	4,436
Increases Related to Tax Positions for Prior Years		137		--
Uncertain Positions Adjusted During Year		--		--
Balance on March 31	$	4,376	$	4,436

The balance of unrecognized tax benefits as of March 31, 2014 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2014 is not expected to change significantly within the next twelve 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 March 31, 2014.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of March 31, 2014, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2010. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at March 31, 2014 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014.