Otter Tail (OTTR) 10-Q 11 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1466593
Trading Symbol	ottr
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		37,483,725
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

Consolidated_Balance_Sheets_no

Consolidated Balance Sheets (not audited) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents	$157
Accounts Receivable:
Trade - Net	74,071	60,172
Other	14,406	13,179
Inventories	84,515	85,203
Deferred Income Taxes	52,065	49,482
Unbilled Revenues	15,199	17,996
Regulatory Assets	20,352	25,273
Other	6,935	7,187
Assets of Discontinued Operations	33,171	48,657
Total Current Assets	300,871	307,149
Investments	10,405	8,582
Other Assets	30,900	30,111
Goodwill	31,488	31,488
Other Intangibles - Net	11,113	11,251
Deferred Debits
Unamortized Debt Expense	4,130	4,300
Regulatory Assets	127,368	129,868
Total Deferred Debits	131,498	134,168
Plant
Electric Plant in Service	1,560,459	1,545,112
Nonelectric Operations	178,289	175,159
Construction Work in Progress	269,999	248,677
Total Gross Plant	2,008,747	1,968,948
Less Accumulated Depreciation and Amortization	709,842	700,418
Net Plant	1,298,905	1,268,530
Total Assets	1,815,180	1,791,279
Current Liabilities
Short-Term Debt	48,652	10,854
Current Maturities of Long-Term Debt	204	201
Accounts Payable	95,876	107,013
Accrued Salaries and Wages	12,826	19,256
Accrued Taxes	15,342	13,793
Derivative Liabilities	11,567	14,230
Other Accrued Liabilities	8,890	8,793
Liabilities of Discontinued Operations	20,732	27,559
Total Current Liabilities	214,089	201,699
Pensions Benefit Liability	93,084	102,711
Other Postretirement Benefits Liability	54,100	53,638
Other Noncurrent Liabilities	24,485	26,794
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	239,999	230,810
Deferred Tax Credits	25,914	26,384
Regulatory Liabilities	77,851	77,013
Other	947	975
Total Deferred Credits	344,711	335,182
Capitalization
Long-Term Debt, Net of Current Maturities	498,437	498,489
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2015-37,422,959 Shares; 2014 - 37,218,053 Shares	187,115	186,090
Premium on Common Shares	284,341	278,436
Retained Earnings	119,340	112,903
Accumulated Other Comprehensive Loss	-4,522	-4,663
Total Common Equity	586,274	572,766
Total Capitalization	1,084,711	1,071,255
Total Liabilities and Equity	1,815,180	1,791,279
Cumulative Preferred Shares
Capitalization
Cumulative Shares
Cumulative Preference Shares
Capitalization
Cumulative Shares

Consolidated_Balance_Sheets_no1

Consolidated Balance Sheets (not audited) (Parentheticals) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Common shares, par value (in dollars per share)	$5	$5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	37,422,959	37,218,053
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding
Cumulative Preference Shares
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding

Consolidated_Statements_of_Inc

Consolidated Statements of Income (not audited) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating Revenues
Electric	$113,533	$119,048
Product Sales	89,308	95,918
Total Operating Revenues	202,841	214,966
Operating Expenses
Production Fuel - Electric	14,599	22,030
Purchased Power - Electric System Use	23,692	21,785
Electric Operation and Maintenance Expenses	37,527	34,622
Cost of Products Sold (depreciation included below)	71,498	73,939
Other Nonelectric Expenses	12,463	9,951
Depreciation and Amortization	14,535	14,267
Property Taxes - Electric	3,502	2,971
Total Operating Expenses	177,816	179,565
Operating Income	25,025	35,401
Interest Charges	7,743	6,595
Other Income	572	1,535
Income Before Income Taxes - Continuing Operations	17,854	30,341
Income Tax Expense - Continuing Operations	4,073	8,562
Net Income from Continuing Operations	13,781	21,779
Discontinued Operations
Loss - net of Income Tax Benefit of $1,376 and $225 for the respective periods	-2,072	-349
Impairment Loss - net of Income Tax Benefit of $0 for the three months ended March 31, 2015	-1,000
Gain on Disposition - net of Income Tax Expense of $4,816 for the three months ended March 31, 2015	7,226
Net Income (Loss) from Discontinued Operations	4,154	-349
Net Income	$17,935	$21,430
Average Number of Common Shares Outstanding-Basic (in shares)	37,243,118	36,240,350
Average Number of Common Shares Outstanding-Diluted (in shares)	37,497,881	36,431,915
Basic Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$0.37	$0.60
Discontinued Operations (in dollars per share)	$0.11	($0.01)
Earnings Per Share, Basic, Total (in dollars per share)	$0.48	$0.59
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$0.37	$0.60
Discontinued Operations (in dollars per share)	$0.11	($0.01)
Earnings Per Share, Diluted, Total (in dollars per share)	$0.48	$0.59
Dividends Declared Per Common Share (in dollars per share)	$0.31	$0.30

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (not audited) (Parentheticals) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Income tax expense (benefit) on income (loss) from discontinued operation	($1,376)	($225)
Income tax (benefit) expense on impairment	0
Income tax (benefit) expense on gain from disposition	$4,816

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (not audited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$17,935	$21,430
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	-3	-17
Gains (Losses) Arising During Period	32	-17
Income Tax (Expense) Benefit	-10	12
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	19	-22
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	204	50
Income Tax (Expense)	-82	-20
Pension and Postretirement Benefit Plans - net-of-tax	122	30
Total Other Comprehensive Income	141	8
Total Comprehensive Income	$18,076	$21,438

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (not audited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash Flows from Operating Activities
Net Income	$17,935	$21,430
Adjustments to Reconcile Net Income to Net Cash Used in Operating Activities:
Net Gain from Sale of Discontinued Operations	-7,226
Net Loss from Discontinued Operations	3,072	349
Depreciation and Amortization	14,535	14,267
Deferred Tax Credits	-470	-454
Deferred Income Taxes	7,038	13,073
Change in Deferred Debits and Other Assets	3,538	-888
Discretionary Contribution to Pension Plan	-10,000	-20,000
Change in Noncurrent Liabilities and Deferred Credits	41	-2,408
Allowance for Equity/Other Funds Used During Construction	-256	-340
Change in Derivatives Net of Regulatory Deferral	-59	118
Stock Compensation Expense - Equity Awards	623	358
Other - Net	206	182
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	-11,288	-22,329
Change in Inventories	688	-9,236
Change in Other Current Assets	1,270	437
Change in Payables and Other Current Liabilities	-20,185	-7,731
Change in Interest and Income Taxes Receivable/Payable	-1,549	1,013
Net Cash Used in Continuing Operations	-2,087	-12,159
Net Cash Used in Discontinued Operations	-6,263	-6,898
Net Cash Used in Operating Activities	-8,350	-19,057
Cash Flows from Investing Activities
Capital Expenditures	-35,738	-37,311
Net Proceeds from Disposal of Noncurrent Assets	1,292	848
Net Increase in Other Investments	-3,492	-989
Net Cash Used in Investing Activities - Continuing Operations	-37,938	-37,452
Net Proceeds from Sale of Discontinued Operations	21,343
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations	-1,759	285
Net Cash Used in Investing Activities	-18,354	-37,167
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	-1,236
Net Short-Term Borrowings (Repayments)	37,798	-39,296
Proceeds from Issuance of Common Stock - net of Issuance Expenses	4,697	3,666
Payments for Retirement of Capital Stock	-1,239	-242
Proceeds from Issuance of Long-Term Debt		150,000
Short-Term and Long-Term Debt Issuance Expenses	-4	-502
Payments for Retirement of Long-Term Debt	-49	-40,946
Dividends Paid and Other Distributions	-11,498	-10,993
Net Cash Provided by Financing Activities - Continuing Operations	28,469	61,687
Net Cash Used in Financing Activities - Discontinued Operations	-1,178
Net Cash Provided by Financing Activities	27,291	61,687
Net Change in Cash and Cash Equivalents - Discontinued Operations	-430	-126
Net Change in Cash and Cash Equivalents	157	5,337
Cash and Cash Equivalents at Beginning of Period		2,007
Cash and Cash Equivalents at End of Period	$157	$7,344

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies
	Revenue Recognition
	Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.
	Warranty Reserves
	The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged 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 Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.
	Fair Value Measurements
	The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).
	Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
	Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
	The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:
	March 31, 2015 (in thousands)	Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--		$	--		$	381
	Investments:
	Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
	Corporate Debt Securities – Held by Captive Insurance Company					6,625
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company					1,229
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
	Total Assets	$	2,550		$	7,854		$	381
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--		$	282		$	--
	Derivative Liabilities - Forward Energy Contracts								11,285
	Total Liabilities	$	--		$	282		$	11,285
	December 31, 2014 (in thousands)	Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--		$	--		$	257
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company					6,761
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company					1,253
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
	Total Assets	$	713		$	8,014		$	257
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--		$	342		$	--
	Derivative Liabilities - Forward Energy Contracts								13,888
	Total Liabilities	$	--		$	342		$	13,888
	The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
	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-Sponsored Enterprises’ 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, 2015 and December 31, 2014, 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, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour.
	In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 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, 2015 and 2014.
	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, 2015 and 2014:
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Forward Energy Contracts - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
	Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
	Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)
	Inventories
	Inventories consist of the following:
		March 31,			December 31,
	(in thousands)	2015			2014
	Finished Goods	$	27,607		$	27,998
	Work in Process		9,894			10,628
	Raw Material, Fuel and Supplies		47,014			46,577
Total Inventories	$	84,515		$	85,203
Goodwill and Other Intangible Assets
An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.
The following table summarizes changes to goodwill by business segment during 2015:
(in thousands)	Gross Balance			Accumulated Impairments			Balance (net of impairments)			Adjustments to Goodwill in 2015			Balance (net of impairments)
	December 31,						December 31,						March 31,
	2014						2014						2015
Manufacturing	$	12,186		$	--		$	12,186		$	--		$	12,186
Plastics		19,302			--			19,302			--			19,302
Total	$	31,488		$	--		$	31,488		$	--	$	31,488
Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014:
March 31, 2015 (in thousands)	Gross Carrying Amount			Accumulated Amortization			Net Carrying		Remaining
							Amount		Amortization
									Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811		$	5,996		$	10,815	57-157 months
Other Intangible Assets Including Contracts		639			447			192	18 months
Emission Allowances		106			--			106	Expensed as used
Total	$	17,556		$	6,443		$	11,113
December 31, 2014 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811		$	5,784		$	11,027	60-160 months
Other Intangible Assets Including Contracts		639			415			224	21 months
Total	$	17,450		$	6,199		$	11,251
The amortization expense for these intangible assets was:
	Three Months Ended
	March 31,
(in thousands)	2015			2014
Amortization Expense – Intangible Assets	$	244		$	244
The estimated annual amortization expense for these intangible assets for the next five years is:
(in thousands)	2015			2016			2017			2018			2019
Estimated Amortization Expense – Intangible Assets	$	977		$	945		$	849		$	849		$	849
The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015:
	Three Months Ended
(in thousands)	31-Mar-15
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(62	)
Emission Allowances Ending Balance	$	106
Supplemental Disclosures of Cash Flow Information
	As of March 31,
(in thousands)	2015			2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	32,838		$	22,244
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554		$	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 certain 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 the Company is not required to include CCMC in its 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. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 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, 2015 could be as high as $28.5 million.
New Accounting Standards
ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.
ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015.
ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements.

Segment_Information

Segment Information	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Information	2. Segment Information
	The Company’s businesses have been classified into three 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 three segments are: Electric, Manufacturing and Plastics.
	Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is an active wholesale participant in the 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.
	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 2014. 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,
		2015			2014
	United States of America		96.3	%		97.2	%
	Mexico		3	%		2.2	%
	Canada		0.6	%		0.5	%
	All Other Countries (none individually greater than 0.05%)		0.1	%		0.1	%
	The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2015 and 2014 and total assets by business segment as of March 31, 2015 and December 31, 2014 are presented in the following tables:
	Operating Revenue
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Electric	$	113,547		$	119,088
	Manufacturing		56,759			55,435
	Plastics		32,552			40,483
	Intersegment Eliminations		(17	)		(40	)
	Total	$	202,841		$	214,966
	Interest Charges
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Electric	$	6,121		$	5,079
	Manufacturing		832			808
	Plastics		246			247
	Corporate and Intersegment Eliminations		544			461
	Total	$	7,743		$	6,595
	Income Taxes
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Electric	$	4,221		$	5,750
	Manufacturing		504			1,671
	Plastics		1,264			2,133
	Corporate		(1,916	)		(992	)
	Total	$	4,073		$	8,562
	Net Income
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Electric	$	13,178		$	16,653
	Manufacturing		1,184			2,896
	Plastics		2,120			3,460
	Corporate		(2,701	)		(1,230	)
	Discontinued Operations		4,154			(349	)
	Total	$	17,935		$	21,430
	Identifiable Assets
		March 31,			December 31,
	(in thousands)	2015			2014
	Electric	$	1,484,289		$	1,472,647
	Manufacturing		139,143			130,701
	Plastics		90,256			87,356
	Corporate		68,321			51,918
	Assets of Discontinued Operations		33,171			48,657
	Total	$	1,815,180		$	1,791,279

Rate_and_Regulatory_Matters

Rate and Regulatory Matters	3 Months Ended
	Mar. 31, 2015
Rate and Regulatory Matters [Abstract]
Rate and Regulatory Matters	3. Rate and Regulatory Matters
	Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances 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 2015 and 2014.
	Major Capital Expenditure Projects
	Big Stone Plant Air Quality Control System (AQCS)—The South Dakota Department of Environmental and Natural Resources determined that the Big Stone Plant is subject to Best-Available Retrofit Technology (BART) requirements of the Clean Air Act, based on air dispersion modeling indicating that Big Stone Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan.
	OTP is currently in the final stages 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, 2015 is $174.9 million, excluding Allowance for Funds Used During Construction (AFUDC).
	Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (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 on April 23, 2014. The third and final phase of the Fargo Project, from Alexandria to Fargo, was energized on April 2, 2015.
	Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—The MISO granted unconditional approval of the Brookings Project as a Multi-Value Project (MVP) under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (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 in April 2014. This line was placed into service on March 26, 2015.
	The Big Stone South – Brookings MVP and CapX2020 Project—This is a planned 345 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 and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. 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. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013 and granted approval of a route permit for the southern portion of the line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017.
	The Big Stone South – Ellendale MVP—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 ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019.
	Recovery of OTP’s transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
	Reagent Costs and Emission Allowances
	OTP’s system wide costs for reagents and Cross-State Air Pollution Rule (CSAPR) emissions allowances are expected to increase to approximately $4.1 million annually, $3.6 million for reagents and $0.5 million for emission allowances. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs will be phased in during 2015 and 2016 when the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects are completed and in service. Emissions allowance costs are being incurred during 2015 to maintain compliance with CSAPR rules, which became effective January 1, 2015.
	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. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61%, and its allowed rate of return on equity increased from 10.43% to 10.74%.
	Minnesota Conservation Improvement Programs (MNCIP)—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. Based on results from the 2014 MNCIP program year, OTP now estimates a financial incentive for 2014 of $3.0 million. OTP is estimating a lower incentive for 2014 in response to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016.  Additionally, OTP estimated it saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. OTP requested approval for recovery of its 2014 MNCIP financial incentive and 2014 program costs not included in base rates from the MPUC in an April 1, 2015 filing.
	Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. OTP filed its annual update to its Minnesota TCR rider on February 7, 2013 to include 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 Certificate of Need 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’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015.
	Environmental Cost Recovery (ECR) Rider—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. OTP filed its 2014 annual update on July 31, 2014, requesting a $4.1 million annual increase in the rider from $6.1 million to $10.2 million. The MPUC approved OTP’s ECR rider annual update request on November 24, 2014, effective December 1, 2014. Because the effective date was two months behind the anticipated implementation date for the updated rate and a portion of the requested increase had been collected under the initial rate, the approved updated rate is based on a revenue requirement of $9.8 million. The rate will continue to be updated in annual filings with the MPUC until the costs are rolled into base rates at an undetermined future date.
	Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs will be reviewed in OTP’s next general rate case in Minnesota and considered for recovery either through the FCA rider or general rates.
	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. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.
	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 with a return on investment at the level approved in OTP’s most recent general rate case. 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 2013 annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. OTP submitted its 2014 annual update to the NDRRA on December 31, 2014, which was approved by the NDPSC on March 25, 2015 with an effective date of April 1, 2015. In each instance the NDRRA rates have been based upon a return on investment at the rate of return approved in the OTP’s last general rate case. Approved in the 2014 annual update was a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill.
	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. For qualifying projects, the law authorizes a current return on construction work in progress and a return on investment at the level approved in the utility’s most recent general rate case. 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. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million. The NDPSC approved the annual update on December 17, 2014 with an effective date of January 1, 2015.
	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. The ECR provides for a current return on construction work in progress and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR with a proposed implementation date of July 1, 2015.
	Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through the modification of the ECR rider to add a new variable monthly reagent and emissions allowance charge effective May 1, 2015.
	South Dakota
	2010 General Rate Case—On April 21, 2011, the SDPUC issued a written order approving an overall revenue increase for OTP of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50%. 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. 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 following annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s most recent annual update on February 13, 2015 with an effective date of March 1, 2015.
	Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s jurisdictional share of costs and provide a return on investment for the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014.
	Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.
	Revenues Recorded under Rate Riders
	The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31, 2015 and 2014:
		Three Months Ended March 31,
	Rate Rider (in thousands)	2015		2014
	Minnesota
	Conservation Improvement Program Costs and Incentives1	$	1,928	$	1,521
	Transmission Cost Recovery		1,615		2,304
	Environmental Cost Recovery		2,557		1,763
	North Dakota
	Renewable Resource Adjustment		1,883		1,435
	Transmission Cost Recovery		1,936		1,514
	Environmental Cost Recovery		2,156		1,522
	Big Stone II Project Costs		--		361
	South Dakota
	Transmission Cost Recovery		363		346
	Environmental Cost Recovery		504		--
	1Includes MNCIP costs recovered in base rates.
	FERC
	Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.
	On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the return on equity (ROE) 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. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. Settlement discussions did not resolve the dispute and the FERC set the proceeding to a Track II Hearing for complex cases that can take several months to decide with a FERC decision anticipated in fall 2016 at the earliest. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the resolution of the return on equity complaint proceeding.
	On February 12, 2015 another group of stakeholders filed a complaint with 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 from the current 12.38% to a proposed 8.67%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. As of April 30, 2015, the FERC had not responded to the complaint.
	In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2015
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 Topic 980, Regulated Operations (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:
		31-Mar-15						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,465	$	99,659	$	107,124	see below
	Deferred Marked-to-Market Losses1		2,059		9,226		11,285	69 months
	Conservation Improvement Program Costs and Incentives2		3,815		3,511		7,326	27 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		5,305		5,305	asset lives
	Minnesota Transmission Cost Recovery Rider Accrued Revenues2		2,152		1,835		3,987	12 months
	Big Stone II Unrecovered Project Costs – Minnesota1		601		3,086		3,687	93 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,140		636		2,776	24 months
	Debt Reacquisition Premiums1		351		1,802		2,153	210 months
	Deferred Income Taxes1		--		1,461		1,461	asset lives
	Recoverable Fuel and Purchased Power Costs1		1,249		--		1,249	12 months
	Big Stone II Unrecovered Project Costs – South Dakota2		100		718		818	98 months
	North Dakota Transmission Cost Recovery Rider Accrued Revenues2		420		--		420	12 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
	North Dakota Renewable Resource Rider Accrued Revenues2		--		61		61	12 months
	Total Regulatory Assets	$	20,352	$	127,368	$	147,720
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,220	$	75,220	asset lives
	North Dakota Renewable Resource Rider Accrued Refund		1,803		--		1,803	12 months
	Deferred Income Taxes		--		1,447		1,447	asset lives
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		908		908	see below
	Minnesota Environmental Cost Recovery Rider Accrued Refund		451		--		451	12 months
	Deferred Marked-to-Market Gains		204		177		381	58 months
	Big Stone II Over Recovered Project Costs – North Dakota		111		--		111	9 months
	Deferred Gain on Sale of Utility Property – Minnesota Portion		6		99		105	225 months
	South Dakota Environmental Cost Recovery Rider Accrued Refund		86		--		86	12 months
	South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
	North Dakota Environmental Cost Recovery Rider Accrued Refund		35		--		35	12 months
	Total Regulatory Liabilities	$	2,744	$	77,851	$	80,595
	Net Regulatory Asset Position	$	17,608	$	49,517	$	67,125
	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.
		31-Dec-14						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see below
	Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
	Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
	Minnesota Transmission Cost Recovery Rider Accrued Revenues2		943		2,455		3,398	24 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
	Debt Reacquisition Premiums1		351		1,890		2,241	213 months
	Deferred Income Taxes1		--		2,086		2,086	asset lives
	Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
	North Dakota Transmission Cost Recovery Rider Accrued Revenues2		859		--		859	12 months
	Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
	Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
	South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
	Total Regulatory Assets	$	25,273	$	129,868	$	155,141
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
	Deferred Income Taxes		--		1,550		1,550	asset lives
	North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see below
	Deferred Marked-to-Market Gains		--		257		257	67 months
Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
Net Regulatory Asset Position	$	24,115	$	52,855	$	76,970
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, 2015 are related to forward purchases of energy scheduled for delivery through December 2020.
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.
Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 2015.
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.
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 210 months.
The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.
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 Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of March 31, 2015.
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.
North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2015.
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, 2015.
Revenue for Rate Case Expenses Subject to Refund – Minnesota relate to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.
The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of March 31, 2015.
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 South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2015.
The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2015.
The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to North Dakota customers as of March 31, 2015.
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.

Forward_Contracts_Classified_a

Forward Contracts Classified as Derivatives	3 Months Ended
	Mar. 31, 2015
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 meet the energy requirements of its retail customers and to optimize the use of its generating and transmission facilities. 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. Prior to December 2014, OTP also entered into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales. Effective December 31, 2014 OTP discontinued its trading activities not directly associated with serving retail customers.
	OTP’s forward contracts outstanding as of March 31, 2015 and December 31, 2014 for the purchase of electricity are scheduled for delivery at the OTP node, which is an illiquid trading point. Prices used to value OTP’s forward purchases at this trading point were based on a basis spread between the OTP node and more liquid trading hub prices. These basis spreads were 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 OTP’s forward contracts for the purchase 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, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to March 31, 2015 and December 31, 2013 to March 31, 2014:
	(in thousands)	31-Mar-15			31-Dec-14
	Current Asset – Marked-to-Market Gain	$	381		$	257
	Regulatory Asset – Current Deferred Marked-to-Market Loss		2,059			4,492
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,226			9,396
	Total Assets		11,666			14,145
	Current Liability – Marked-to-Market Loss		(11,285	)		(13,888	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain		(204	)		--
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(177	)		(257	)
	Total Liabilities		(11,666	)		(14,145	)
	Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--
	(in thousands)	Year-to-Date			Year-to-Date
		31-Mar-15			31-Mar-14
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	--		$	115
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		--			(72	)
	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
	Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	39
	The following realized and unrealized net loss on forward energy contracts is included in electric operating revenues on the Company’s consolidated statements of income:
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Net Loss on Forward Electric Energy Contracts	$	--		$	(4	)
	OTP 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. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at March 31, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.
	Individual counterparty exposures for certain contracts can be 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, 2015 and December 31, 2014 are indicated in the following table:
	(in thousands)	31-Mar-15			31-Dec-14
	Derivative assets subject to legally enforceable netting arrangements	$	381		$	257
	Derivative liabilities subject to legally enforceable netting arrangements		(11,567	)		(14,230	)
	Net balance subject to legally enforceable netting arrangements	$	(11,186	)	$	(13,973	)
	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, 2015 and December 31, 2014:
	Current Liability – Marked-to-Market Loss  (in thousands)	March 31,			December 31,
		2015			2014
	Loss Contracts Covered by Deposited Funds or Letters of Credit	$	282		$	45
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,285			13,888
	Loss Contracts with No Ratings Triggers or Deposit Requirements		--			297
	Total Current Liability – Marked-to-Market Loss	$	11,567		$	14,230
	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	$	11,285		$	13,888
	Offsetting Gains with Counterparties under Master Netting Agreements		(381	)		(257	)
	Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,904		$	13,631

Reconciliation_of_Common_Share

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share	3 Months Ended
	Mar. 31, 2015
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,			Premium			Retained			Accumulated			Total
		Common			on			Earnings			Other			Common
		Shares			Common						Comprehensive			Equity
					Shares						Income/(Loss)
	Balance, December 31, 2014	$	186,090		$	278,436		$	112,903		$	(4,663	)	$	572,766
	Common Stock Issuances, Net of Expenses		1,220			6,302									7,522
	Common Stock Retirements		(195	)		(1,044	)								(1,239	)
	Net Income								17,935						17,935
	Other Comprehensive Income											141			141
	Tax Benefit – Stock Compensation					24									24
	Employee Stock Incentive Plans Expense					623									623
	Common Dividends ($0.3075 per share)								(11,498	)					(11,498	)
	Balance, March 31, 2015	$	187,115		$	284,341		$	119,340		$	(4,522	)	$	586,274
	Shelf Registration
	The Company’s shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 11, 2012, under which the Company 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, including common shares of the Company, expires on May 10, 2015. On May 14, 2012, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.
	Common Shares
	Following is a reconciliation of the Company’s common shares outstanding from December 31, 2014 through March 31, 2015:
	Common Shares Outstanding, December 31, 2014		37,218,053
	Issuances:
	Executive Stock Performance Awards (2012-2014 shares earned)		89,991
	Automatic Dividend Reinvestment and Share Purchase Plan:
	Dividends Reinvested		42,518
	Cash Invested		16,553
	At-the-Market Offering		38,160
	Employee Stock Purchase Plan:
	Cash Invested		19,993
	Dividends Reinvested		5,985
	Employee Stock Ownership Plan		21,137
	Stock Options Exercised		9,000
	Vesting of Restricted Stock Units		700
	Retirements:
	Shares Withheld for Individual Income Tax Requirements		(39,131	)
	Common Shares Outstanding, March 31, 2015		37,422,959
	Earnings Per Share
	The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 2015 and 2014. 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 basic shares outstanding for the items listed in the following reconciliation of Weighted Average Common Shares Outstanding – Basic to Weighted Average Common Shares Outstanding – Diluted for the three month periods ended March 31:
		2015			2014
	Weighted Average Common Shares Outstanding – Basic		37,243,118			36,240,350
	Plus:
	Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		229,100			131,000
	Nonvested Restricted Shares		83,330			90,798
	Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		70,900			55,655
	Shares Expected to be Issued Under the Deferred Compensation Program for Directors		40,462			39,197
	Potentially Dilutive Stock Options		3,750			18,050
	Less:
	Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(169,842	)		(127,709	)
	Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(2,937	)		(15,426	)
	Total Dilutive Shares		254,763			191,565
	Weighted Average Common Shares Outstanding – Diluted		37,497,881			36,431,915
	The effect of dilutive shares on earnings per share for the three month periods ended March 31, 2015 and 2014, 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 period.

ShareBased_Payments

Share-Based Payments	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Share-Based Payments	7. Share-Based Payments
	Stock Incentive Awards
	On February 6, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s executive officers under the 2014 Stock Incentive Plan.
	Award	Shares/Units		Weighted		Vesting
		Granted		Average
				Grant-Date
				Fair Value
				per Award
	Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	31-Dec-17
	Restricted Stock Units Granted to Executive Officers:
	Graded Vesting		20,900	$	31.675	25% per year through February 6, 2019
	Cliff Vesting		6,400	$	31.675	100% on February 6, 2020
	Under the performance share awards the aggregate award for performance at target is 77,500 shares. For target performance the Company’s executive officers would earn an aggregate of 51,667 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, 2015 through December 31, 2017. The Company’s executive officers would also earn an aggregate of 25,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 116,250 common shares. 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, Compensation–Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.
	Under the 2015 performance award agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be made at target at the date of any such event.
	The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement or, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.
	The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.
	As of March 31, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.
	Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2015 and 2014 are presented in the table below:
		Three months ended
		March 31,
	(in thousands)	2015		2014
	Employee Stock Purchase Plan (15% discount)	$	49	$	42
	Restricted Stock Granted to Directors		98		123
	Restricted Stock Granted to Executive Officers		157		135
	Restricted Stock Units Granted to Non-Executive Employees		66		58
	Restricted Stock Units Granted to Executive Officers		253		--
	Stock Performance Awards Granted to Executive Officers		1,020		526
	Totals	$	1,643	$	884

Retained_Earnings_Restriction

Retained Earnings Restriction	3 Months Ended
	Mar. 31, 2015
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 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, 2015 the Company was in compliance with the debt covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2014 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 45.0% and 55.0%. OTP’s equity to total capitalization ratio including short-term debt was 50.7% as of March 31, 2015. Total capitalization for OTP cannot currently exceed $987 million.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	9. Commitments and Contingencies
	Construction and Other Purchase Commitments
	At December 31, 2014 OTP had commitments under contracts in connection with construction programs extending into 2018 of approximately $106.6 million. At March 31, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $106.1 million.
	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 into 2039. In the first quarter of 2015, OTP entered into an energy purchase agreement for the purchase of electricity in April, May and June of 2015 to make up for reduced generation from Coyote Station as it continues to make repairs related to damage caused by a boiler feed pump failure and ensuing fire in December 2014. The total cost for the replacement power will be approximately $2.9 million.
	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 2015, 2016, 2017 and 2040. In the first quarter of 2015, OTP entered into a second contract for the purchase of Wyoming subbituminous coal to meet a portion of its 2015 through 2017 coal requirements at Big Stone Plant. OTP’s share of the purchase commitment under this contract as of March 31, 2015 is approximately $10.0 million. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs.
	Operating Leases
	In April of 2015, OTP entered into an agreement to extend the term of its lease of rail cars used for the transport of coal to Hoot Lake Plant by 36 months beginning April 1, 2015, for a total commitment of approximately $2.8 million.
	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, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $5.0 million.
	In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.
	On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes. Under the other proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for nonhazardous solid wastes. On December 19, 2014 the EPA announced a final rule following the Subtitle D nonhazardous provisions. Publication of the final rule on April 17, 2015 opened a 90-day window within which petitions for judicial review may be filed in the D.C. Circuit. Challenges by environmental groups are possible and the outcome of such challenges cannot be predicted. Thus, uncertainty regarding the status of this rule is likely to continue for a period of time. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. The cost impact of this rule will not be known until those actions are completed. As of the date of this report on From 10-Q, OTP had not completed its assessment under the final rule nor made a determination if compliance with the rule would require immediate remediation or result in the recognition of additional AROs beyond those already recognized by OTP in connection with its active and inactive ash disposal sites.  Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. The EPA is also considering future regulation of coal ash under Subtitle C.
	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, 2015 will not be material.

ShortTerm_and_LongTerm_Borrowi

Short-Term and Long-Term Borrowings	3 Months Ended
	Mar. 31, 2015
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, 2015 and December 31, 2014:
	(in thousands)	Line Limit		In Use on		Restricted due to		Available on		Available on
				31-Mar-15		Outstanding		March 31,		December 31,
						Letters of Credit		2015		2014
	Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
	OTP Credit Agreement		170,000		7,806		560		161,634		169,440
	Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312
	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, 2015 and December 31, 2014:
	March 31, 2015 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation
						Consolidated
	Short-Term Debt	$	7,806	$	40,846	$	48,652
	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
	North Dakota Development Note, 3.95%, due April 1, 2018		--		237		237
	Partnership in Assisting Community Expansion (PACE) Note,		--		1,074		1,074
	2.54%, due March 18, 2021
	Total	$	445,000	$	53,641	$	498,641
	Less: Current Maturities		--		204		204
	Total Long-Term Debt	$	445,000	$	53,437	$	498,437
	Total Short-Term and Long-Term Debt (with current maturities)	$	452,806	$	94,487	$	547,293
	December 31, 2014 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation
						Consolidated
	Short-Term Debt	$	--	$	10,854	$	10,854
	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
	North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
	Partnership in Assisting Community Expansion (PACE) Note,		--		1,105		1,105
	2.54%, due March 18, 2021
	Total	$	445,000	$	53,691	$	498,691
	Less: Current Maturities		--		201		201
	Unamortized Debt Discount		--		1		1
	Total Long-Term Debt	$	445,000	$	53,489	$	498,489
	Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544

Pension_Plan_and_Other_Postret

Pension Plan and Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Pension Plan and Other Postretirement Benefits	11. 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)	2015			2014
	Service Cost—Benefit Earned During the Period	$	1,500		$	1,175
	Interest Cost on Projected Benefit Obligation		3,325			3,285
	Expected Return on Assets		(4,600	)		(4,187	)
	Amortization of Prior-Service Cost:
	From Regulatory Asset		47			64
	From Other Comprehensive Income1		1			2
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		1,633			868
	From Other Comprehensive Income1		40			23
	Net Periodic Pension Cost	$	1,946		$	1,230
	1Corporate cost included in Other Nonelectric Expenses.
	Cash flows—The Company made discretionary plan contributions totaling $10,000,000 in January 2015. The Company currently is not required and does not expect to make an additional contribution to the plan in 2015. The Company also made discretionary plan contributions totaling $20,000,000 in January 2014.
	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)	2015			2014
	Service Cost—Benefit Earned During the Period	$	47		$	13
	Interest Cost on Projected Benefit Obligation		381			380
	Amortization of Prior-Service Cost:
	From Regulatory Asset		4			5
	From Other Comprehensive Income1		10			13
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		83			35
	From Other Comprehensive Income2		151			12
	Net Periodic Pension Cost	$	676		$	458
	1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses	$	4		$	5
	Other Nonelectric Expenses		6			8
	2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses	$	78		$	33
	Other Nonelectric Expenses		73			(21	)
	Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:
		Three Months Ended March 31,
	(in thousands)	2015			2014
	Service Cost—Benefit Earned During the Period	$	375		$	315
	Interest Cost on Projected Benefit Obligation		550			558
	Amortization of Prior-Service Cost:
	From Regulatory Asset		51			51
	From Other Comprehensive Income1		1			1
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		48			--
	From Other Comprehensive Income1		1			--
	Net Periodic Postretirement Benefit Cost	$	1,026		$	925
	Effect of Medicare Part D Subsidy	$	(450	)	$	(308	)
	1 Corporate cost included in Other Nonelectric Expenses.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	12. 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, 2015 and December 31, 2014 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to 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.
		31-Mar-15						31-Dec-14
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Cash and Cash Equivalents	$	157		$	157		$	--		$	--
	Short-Term Debt		(48,652	)		(48,652	)		(10,854	)		(10,854	)
	Long-Term Debt including Current Maturities		(498,641	)		(571,801	)		(498,690	)		(600,828	)

Income_Tax_Expense_Continuing_

Income Tax Expense Continuing Operations	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax Expense - Continuing Operations	14. 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, 2015 and 2014:
		Three Months Ended March 31,
	(in thousands)	2015			2014
	Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
	Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
	Increases (Decreases) in Tax from:
	Federal Production Tax Credits		(2,054	)		(2,252	)
	Section 199 Domestic Production Activities Deduction		(362	)		(358	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
	Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
	AFUDC Equity		(100	)		(133	)
	Corporate Owned Life Insurance		(80	)		(112	)
	Other Items – Net		90			(15	)
	Income Tax Expense – Continuing Operations	$	4,073		$	8,562
	Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%
	The following table summarizes the activity related to our unrecognized tax benefits:
	(in thousands)	2015			2014
	Balance on January 1	$	222		$	4,239
	Increases Related to Tax Positions for Prior Years		--			137
	Increases Related to Tax Positions for Current Year		44			--
	Uncertain Positions Resolved During Year		--			--
	Balance on March 31	$	266		$	4,376
	The balance of unrecognized tax benefits as of March 31, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2015 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, 2015.
	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, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2011. 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, 2015 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.

Discontinued_Operations

Discontinued Operations	3 Months Ended
	Mar. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	16. Discontinued Operations
	In 2014 the Company entered into signed letters of intent to sell its two construction companies that made up its Construction segment. On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor headquartered in Kansas City, Missouri, for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) in exchange for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets to be determined within 90 days of closing. The Company recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. The assets, liabilities, operating results and cash flows of Foley and AEV, Inc. are being reported as discontinued operations as of, and for the periods preceding, March 31, 2015. On February 8, 2013 the Company completed the sale of substantially all the assets of its former waterfront equipment manufacturing company previously included in the Company’s Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing company. The following summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2015 and 2014, include the operating results of Foley, AEV, Inc. and residual expenses from the Company’s former wind tower and waterfront equipment manufacturers:
		For the Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Operating Revenues	$	18,724		$	25,506
	Operating Expenses		22,141			26,368
	Goodwill Impairment Charge		1,000			--
	Operating Loss		(4,417	)		(862	)
	Other (Deductions) Income		(31	)		288
	Income Tax Benefit		(1,376	)		(225	)
	Net Loss from Operations		(3,072	)		(349	)
	Gain on Disposition Before Taxes		12,042			--
	Income Tax Expense on Disposition		4,816			--
	Net Gain on Disposition		7,226			--
	Net Income (Loss)	$	4,154		$	(349	)
	Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2015 and December 31, 2014:
	(in thousands)	March 31,			December 31,
		2015			2014
	Current Assets	$	26,928		$	35,174
	Goodwill and Intangibles		1,814			2,814
	Net Plant		4,429			10,669
	Assets of Discontinued Operations	$	33,171		$	48,657
	Current Liabilities	$	15,616		$	22,864
	Deferred Income Taxes		5,116			4,695
	Liabilities of Discontinued Operations	$	20,732		$	27,559
	Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts have been 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.
	The following tables summarize costs incurred and billings and estimated earnings recognized on uncompleted contracts included in current assets and current liabilities of discontinued operations:
		March 31,			December 31,
	(in thousands)	2015			2014
	Costs Incurred on Uncompleted Contracts	$	339,594		$	402,332
	Less Billings to Date		(354,256	)		(411,909	)
	Plus Estimated Earnings Recognized		14,458			15,154
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577
		March 31,			December 31,
	(in thousands)	2015			2014
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,216		$	8,133
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(3,420	)		(2,556	)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577
	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. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in $2.3 million in pretax charges in the first quarter of 2015.
	In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge as a result of a revision in the estimated valuation of Foley due to first quarter financial results. The first quarter 2015 goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations.
	Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:
	(in thousands)	2015			2014
	Warranty Reserve Balance, January 1	$	2,527		$	3,087
	Additional Provision for Warranties Made During the Year		--			--
	Settlements Made During the Year		(6	)		--
	Decrease in Warranty Estimates for Prior Years		--			(100	)
	Warranty Reserve Balance, March 31	$	2,521		$	2,987
	The warranty reserve balances as of March 31, 2015 relate entirely to warranties scheduled to expire over the next five years on 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 these companies produced prior to the companies being sold. 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.
	Retainage
	Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction companies that have been retained by customers pending project completion:
		March 31,			December 31,
	(in thousands)	2015			2014
	Accounts Receivable Retained by Customers	$	4,018		$	6,759

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events
	Sale of Foley
	On April 30, 2015 the Company completed the sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. Although the net carrying value of Foley had been adjusted to its indicated fair value through goodwill impairment charges recorded prior to the sale based on acceptance of the buyer’s offering price, the final proceeds and loss on sale will not be known until the adjustments for working capital and other related items have been determined.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Revenue Recognition	Revenue Recognition
	Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.
Warranty Reserves	Warranty Reserves
	The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged 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 Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.
Fair Value Measurements	Fair Value Measurements
	The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).
	Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
	Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
	The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:
	March 31, 2015 (in thousands)	Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--		$	--		$	381
	Investments:
	Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
	Corporate Debt Securities – Held by Captive Insurance Company					6,625
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company					1,229
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
	Total Assets	$	2,550		$	7,854		$	381
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--		$	282		$	--
	Derivative Liabilities - Forward Energy Contracts								11,285
	Total Liabilities	$	--		$	282		$	11,285
	December 31, 2014 (in thousands)	Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--		$	--		$	257
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company					6,761
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company					1,253
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
	Total Assets	$	713		$	8,014		$	257
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--		$	342		$	--
	Derivative Liabilities - Forward Energy Contracts							13,888
	Total Liabilities	$	--		$	342		$	13,888
	The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
	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-Sponsored Enterprises’ 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, 2015 and December 31, 2014, 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, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour.
	In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 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, 2015 and 2014.
	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, 2015 and 2014:
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Forward Energy Contracts  - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
	Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
	Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)
Inventories	Inventories
	Inventories consist of the following:
		March 31,			December 31,
	(in thousands)	2015			2014
	Finished Goods	$	27,607		$	27,998
	Work in Process		9,894			10,628
	Raw Material, Fuel and Supplies		47,014			46,577
	Total Inventories	$	84,515		$	85,203
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets
	An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.
	The following table summarizes changes to goodwill by business segment during 2015:
		Gross Balance			Accumulated Impairments			Balance (net of impairments)			Adjustments to Goodwill in 2015		Balance (net of impairments)
	(in thousands)	December 31,						December 31,					March 31,
		2014						2014					2015
	Manufacturing	$	12,186		$	--		$	12,186		$	--	$	12,186
	Plastics		19,302			--			19,302			--		19,302
	Total	$	31,488		$	--		$	31,488		$	--	$	31,488
	Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014:
	March 31, 2015 (in thousands)	Gross Carrying Amount			Accumulated Amortization			Net Carrying		Remaining
								Amount		Amortization
										Periods
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811		$	5,996		$	10,815	57-157 months
	Other Intangible Assets Including Contracts		639			447			192	18 months
	Emission Allowances		106			--			106	Expensed as used
	Total	$	17,556		$	6,443		$	11,113
	December 31, 2014 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811		$	5,784		$	11,027	60-160 months
	Other Intangible Assets Including Contracts		639			415			224	21 months
	Total	$	17,450		$	6,199		$	11,251
	The amortization expense for these intangible assets was:
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Amortization Expense – Intangible Assets	$	244		$	244
	The estimated annual amortization expense for these intangible assets for the next five years is:
	(in thousands)	2015			2016			2017			2018		2019
	Estimated Amortization Expense – Intangible Assets	$	977		$	945		$	849		$	849	$	849
	The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015:
		Three Months Ended
	(in thousands)	31-Mar-15
	Emission Allowances Beginning Balance	$	--
	Allowances Purchased		168
	Allowances Used		(62	)
	Emission Allowances Ending Balance	$	106
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information
		As of March 31,
	(in thousands)	2015			2014
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1	$	32,838		$	22,244
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554		$	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 certain 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 the Company is not required to include CCMC in its 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. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 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, 2015 could be as high as $28.5 million.
New Accounting Standards	New Accounting Standards
	ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
	ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.
	ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015.
	ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Schedule of assets and liabilities that are measured at fair value on a recurring basis	March 31, 2015 (in thousands)	Level 1				Level 2				Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--			$	--			$	381
	Investments:
	Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
	Corporate Debt Securities – Held by Captive Insurance Company						6,625
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,229
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
	Total Assets	$	2,550			$	7,854			$	381
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	--			$	282			$	--
	Derivative Liabilities - Forward Energy Contracts										11,285
	Total Liabilities	$	--			$	282			$	11,285
	December 31, 2014 (in thousands)	Level 1				Level 2				Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--			$	--			$	257
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company						6,761
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,253
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
	Total Assets	$	713			$	8,014			$	257
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--			$	342			$	--
	Derivative Liabilities - Forward Energy Contracts										13,888
	Total Liabilities	$	--			$	342			$	13,888
Schedule of derivative asset and liability fair valuations		Three Months Ended
		March 31,
	(in thousands)	2015				2014
	Forward Energy Contracts - Fair Values Beginning of Period	$	(13,631	)		$	(11,341	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386				1,160
	Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)			3,498
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)			(6,683	)
	Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)			40
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)		$	(6,643	)
Schedule of inventories		March 31,				December 31,
	(in thousands)	2015				2014
	Finished Goods	$	27,607			$	27,998
	Work in Process		9,894				10,628
	Raw Material, Fuel and Supplies		47,014				46,577
	Total Inventories	$	84,515			$	85,203
Schedule of changes to goodwill by business segment		Gross Balance				Accumulated Impairments				Balance (net of impairments)			Adjustments to Goodwill in 2015		Balance (net of impairments)
	(in thousands)	December 31,								December 31,					March 31,
		2014								2014					2015
	Manufacturing	$	12,186			$	--			$	12,186		$	--	$	12,186
	Plastics		19,302				--				19,302			--		19,302
	Total	$	31,488			$	--			$	31,488		$	--	$	31,488
Schedule of components of intangible assets	March 31, 2015 (in thousands)	Gross Carrying Amount				Accumulated Amortization				Net Carrying		Remaining
										Amount		Amortization
												Periods
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811			$	5,996			$	10,815	57-157 months
	Other Intangible Assets Including Contracts		639				447				192	18 months
	Emission Allowances		106				--				106	Expensed as used
	Total	$	17,556			$	6,443			$	11,113
	December 31, 2014 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811			$	5,784			$	11,027	60-160 months
	Other Intangible Assets Including Contracts		639				415				224	21 months
	Total	$	17,450			$	6,199			$	11,251
Schedule of amortization expense for intangible assets	The amortization expense for these intangible assets was:
		Three Months Ended
		March 31,
	(in thousands)	2015				2014
	Amortization Expense – Intangible Assets	$	244			$	244
	The estimated annual amortization expense for these intangible assets for the next five years is:
	(in thousands)	2015				2016				2017			2018		2019
	Estimated Amortization Expense – Intangible Assets	$	977			$	945			$	849		$	849	$	849
Schedule of reconciliation of OTP's emission allowances		Three Months Ended
	(in thousands)	31-Mar-15
	Emission Allowances Beginning Balance	$	--
	Allowances Purchased		168
	Allowances Used		(62	)
	Emission Allowances Ending Balance	$	106
Schedule of supplemental disclosure of cash flow information		As of March 31,
	(in thousands)	2015				2014
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1	$	32,838			$	22,244
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554			$	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.

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Schedule of percent of consolidated sales revenue by country			Three Months Ended March 31,
			2015				2014
	United States of America			96.3	%			97.2	%
	Mexico			3	%			2.2	%
	Canada			0.6	%			0.5	%
	All Other Countries (none individually greater than 0.05%)			0.1	%			0.1	%
Schedule of information by business segments
	Operating Revenue
			Three Months Ended
			March 31,
	(in thousands)		2015				2014
	Electric		$	113,547			$	119,088
	Manufacturing			56,759				55,435
	Plastics			32,552				40,483
	Intersegment Eliminations			(17	)			(40	)
	Total		$	202,841			$	214,966
	Interest Charges
			Three Months Ended
			March 31,
	(in thousands)		2015				2014
	Electric		$	6,121			$	5,079
	Manufacturing			832				808
	Plastics			246				247
	Corporate and Intersegment Eliminations			544				461
	Total		$	7,743			$	6,595
	Income Taxes
			Three Months Ended
			March 31,
	(in thousands)		2015				2014
	Electric		$	4,221			$	5,750
	Manufacturing			504				1,671
	Plastics			1,264				2,133
	Corporate			(1,916	)			(992	)
	Total		$	4,073			$	8,562
	Net Income
			Three Months Ended
			March 31,
	(in thousands)		2015				2014
	Electric		$	13,178			$	16,653
	Manufacturing			1,184				2,896
	Plastics			2,120				3,460
	Corporate			(2,701	)			(1,230	)
	Discontinued Operations			4,154				(349	)
	Total		$	17,935			$	21,430
	Identifiable Assets
		March 31,				December 31,
	(in thousands)		2015				2014
	Electric		$	1,484,289			$	1,472,647
	Manufacturing			139,143				130,701
	Plastics			90,256				87,356
	Corporate			68,321				51,918
	Assets of Discontinued Operations			33,171				48,657
	Total		$	1,815,180			$	1,791,279

Rate_and_Regulatory_Matters_Ta

Rate and Regulatory Matters (Tables)	3 Months Ended
	Mar. 31, 2015
Rate and Regulatory Matters [Abstract]
Schedule of revenues recorded under rate riders		Three Months Ended March 31,
	Rate Rider (in thousands)	2015		2014
	Minnesota
	Conservation Improvement Program Costs and Incentives1	$	1,928	$	1,521
	Transmission Cost Recovery		1,615		2,304
	Environmental Cost Recovery		2,557		1,763
	North Dakota
	Renewable Resource Adjustment		1,883		1,435
	Transmission Cost Recovery		1,936		1,514
	Environmental Cost Recovery		2,156		1,522
	Big Stone II Project Costs		--		361
	South Dakota
	Transmission Cost Recovery		363		346
	Environmental Cost Recovery		504		--
	1Includes MNCIP costs recovered in base rates.

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of amount of regulatory assets and liabilities		31-Mar-15						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,465	$	99,659	$	107,124	see below
	Deferred Marked-to-Market Losses1		2,059		9,226		11,285	69 months
	Conservation Improvement Program Costs and Incentives2		3,815		3,511		7,326	27 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		5,305		5,305	asset lives
	Minnesota Transmission Cost Recovery Rider Accrued Revenues2		2,152		1,835		3,987	12 months
	Big Stone II Unrecovered Project Costs – Minnesota1		601		3,086		3,687	93 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,140		636		2,776	24 months
	Debt Reacquisition Premiums1		351		1,802		2,153	210 months
	Deferred Income Taxes1		--		1,461		1,461	asset lives
	Recoverable Fuel and Purchased Power Costs1		1,249		--		1,249	12 months
	Big Stone II Unrecovered Project Costs – South Dakota2		100		718		818	98 months
	North Dakota Transmission Cost Recovery Rider Accrued Revenues2		420		--		420	12 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
	North Dakota Renewable Resource Rider Accrued Revenues2		--		61		61	12 months
	Total Regulatory Assets	$	20,352	$	127,368	$	147,720
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,220	$	75,220	asset lives
	North Dakota Renewable Resource Rider Accrued Refund		1,803		--		1,803	12 months
	Deferred Income Taxes		--		1,447		1,447	asset lives
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		908		908	see below
	Minnesota Environmental Cost Recovery Rider Accrued Refund		451		--		451	12 months
	Deferred Marked-to-Market Gains		204		177		381	58 months
	Big Stone II Over Recovered Project Costs – North Dakota		111		--		111	9 months
	Deferred Gain on Sale of Utility Property – Minnesota Portion		6		99		105	225 months
	South Dakota Environmental Cost Recovery Rider Accrued Refund		86		--		86	12 months
	South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
	North Dakota Environmental Cost Recovery Rider Accrued Refund		35		--		35	12 months
	Total Regulatory Liabilities	$	2,744	$	77,851	$	80,595
	Net Regulatory Asset Position	$	17,608	$	49,517	$	67,125
	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.
		31-Dec-14						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see below
	Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
	Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
	Minnesota Transmission Cost Recovery Rider Accrued Revenues2		943		2,455		3,398	24 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
	Debt Reacquisition Premiums1		351		1,890		2,241	213 months
	Deferred Income Taxes1		--		2,086		2,086	asset lives
	Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
	North Dakota Transmission Cost Recovery Rider Accrued Revenues2		859		--		859	12 months
	Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
	Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
	South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
	Total Regulatory Assets	$	25,273	$	129,868	$	155,141
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
	Deferred Income Taxes		--		1,550		1,550	asset lives
	North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see below
	Deferred Marked-to-Market Gains		--		257		257	67 months
	Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
	Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
Net Regulatory Asset Position	$	24,115	$	52,855	$	76,970
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.

Forward_Contracts_Classified_a1

Forward Contracts Classified as Derivatives (Tables)	3 Months Ended
	Mar. 31, 2015
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)	31-Mar-15			31-Dec-14
	Current Asset – Marked-to-Market Gain	$	381		$	257
	Regulatory Asset – Current Deferred Marked-to-Market Loss		2,059			4,492
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,226			9,396
	Total Assets		11,666			14,145
	Current Liability – Marked-to-Market Loss		(11,285	)		(13,888	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain		(204	)		--
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(177	)		(257	)
	Total Liabilities		(11,666	)		(14,145	)
	Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--
	(in thousands)	Year-to-Date			Year-to-Date
		31-Mar-15			31-Mar-14
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	--		$	115
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		--			(72	)
	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
	Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	39
Schedule of realized and unrealized net loss on forward energy contracts
		Three Months Ended
		March 31,
	(in thousands)	2015			2014
	Net Loss on Forward Electric Energy Contracts	$	--		$	(4	)
Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements
	(in thousands)	31-Mar-15			31-Dec-14
	Derivative assets subject to legally enforceable netting arrangements	$	381		$	257
	Derivative liabilities subject to legally enforceable netting arrangements		(11,567	)		(14,230	)
	Net balance subject to legally enforceable netting arrangements	$	(11,186	)	$	(13,973	)
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,			December 31,
		2015			2014
	Loss Contracts Covered by Deposited Funds or Letters of Credit	$	282		$	45
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,285			13,888
	Loss Contracts with No Ratings Triggers or Deposit Requirements		--			297
	Total Current Liability – Marked-to-Market Loss	$	11,567		$	14,230
	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	$	11,285		$	13,888
	Offsetting Gains with Counterparties under Master Netting Agreements		(381	)		(257	)
	Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,904		$	13,631

Reconciliation_of_Common_Share1

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Schedule of reconciliation of common shareholders' equity
	(in thousands)	Par Value,			Premium			Retained			Accumulated			Total
		Common			on			Earnings			Other			Common
		Shares			Common						Comprehensive			Equity
					Shares						Income/(Loss)
	Balance, December 31, 2014	$	186,090		$	278,436		$	112,903		$	(4,663	)	$	572,766
	Common Stock Issuances, Net of Expenses		1,220			6,302									7,522
	Common Stock Retirements		(195	)		(1,044	)								(1,239	)
	Net Income								17,935						17,935
	Other Comprehensive Income											141			141
	Tax Benefit – Stock Compensation					24									24
	Employee Stock Incentive Plans Expense					623									623
	Common Dividends ($0.3075 per share)								(11,498	)					(11,498	)
	Balance, March 31, 2015	$	187,115		$	284,341		$	119,340		$	(4,522	)	$	586,274
Schedule of common shares outstanding from December 31, 2014 through March 31, 2015
	Common Shares Outstanding, December 31, 2014		37,218,053
	Issuances:
	Executive Stock Performance Awards (2012-2014 shares earned)		89,991
	Automatic Dividend Reinvestment and Share Purchase Plan:
	Dividends Reinvested		42,518
	Cash Invested		16,553
	At-the-Market Offering		38,160
	Employee Stock Purchase Plan:
	Cash Invested		19,993
	Dividends Reinvested		5,985
	Employee Stock Ownership Plan		21,137
	Stock Options Exercised		9,000
	Vesting of Restricted Stock Units		700
	Retirements:
	Shares Withheld for Individual Income Tax Requirements		(39,131	)
	Common Shares Outstanding, March 31, 2015		37,422,959
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted
		2015			2014
	Weighted Average Common Shares Outstanding – Basic		37,243,118			36,240,350
	Plus:
	Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		229,100			131,000
	Nonvested Restricted Shares		83,330			90,798
	Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		70,900			55,655
	Shares Expected to be Issued Under the Deferred Compensation Program for Directors		40,462			39,197
	Potentially Dilutive Stock Options		3,750			18,050
	Less:
	Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(169,842	)		(127,709	)
	Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(2,937	)		(15,426	)
	Total Dilutive Shares		254,763			191,565
	Weighted Average Common Shares Outstanding – Diluted		37,497,881			36,431,915

ShareBased_Payments_Tables

Share-Based Payments (Tables)	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Schedule of stock incentive awards granted to the company's executive officers
	Award	Shares/Units		Weighted		Vesting
		Granted		Average
				Grant-Date
				Fair Value
				per Award
	Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	31-Dec-17
	Restricted Stock Units Granted to Executive Officers:
	Graded Vesting		20,900	$	31.675	25% per year through February 6, 2019
	Cliff Vesting		6,400	$	31.675	100% on February 6, 2020
Schedule of compensation expense under stock-based payment programs
		Three months ended
		March 31,
	(in thousands)	2015		2014
	Employee Stock Purchase Plan (15% discount)	$	49	$	42
	Restricted Stock Granted to Directors		98		123
	Restricted Stock Granted to Executive Officers		157		135
	Restricted Stock Units Granted to Non-Executive Employees		66		58
	Restricted Stock Units Granted to Executive Officers		253		--
	Stock Performance Awards Granted to Executive Officers		1,020		526
	Totals	$	1,643	$	884

ShortTerm_and_LongTerm_Borrowi1

Short-Term and Long-Term Borrowings (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Schedule of lines of credit
	(in thousands)	Line Limit		In Use on		Restricted due to		Available on		Available on
				31-Mar-15		Outstanding		March 31,		December 31,
						Letters of Credit		2015		2014
	Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
	OTP Credit Agreement		170,000		7,806		560		161,634		169,440
	Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312
Schedule of short-term and long-term debt outstanding
	March 31, 2015 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation
						Consolidated
	Short-Term Debt	$	7,806	$	40,846	$	48,652
	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
	North Dakota Development Note, 3.95%, due April 1, 2018		--		237		237
	Partnership in Assisting Community Expansion (PACE) Note,		--		1,074		1,074
	2.54%, due March 18, 2021
	Total	$	445,000	$	53,641	$	498,641
	Less: Current Maturities		--		204		204
	Total Long-Term Debt	$	445,000	$	53,437	$	498,437
	Total Short-Term and Long-Term Debt (with current maturities)	$	452,806	$	94,487	$	547,293
	December 31, 2014 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation
						Consolidated
	Short-Term Debt	$	--	$	10,854	$	10,854
	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
	North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
	Partnership in Assisting Community Expansion (PACE) Note,		--		1,105		1,105
	2.54%, due March 18, 2021
	Total	$	445,000	$	53,691	$	498,691
	Less: Current Maturities		--		201		201
	Unamortized Debt Discount		--		1		1
	Total Long-Term Debt	$	445,000	$	53,489	$	498,489
	Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544

Pension_Plan_and_Other_Postret1

Pension Plan and Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2015
Pension Plan
Schedule of components of net periodic postretirement benefit cost
		Three Months Ended March 31,
	(in thousands)	2015			2014
	Service Cost—Benefit Earned During the Period	$	1,500		$	1,175
	Interest Cost on Projected Benefit Obligation		3,325			3,285
	Expected Return on Assets		(4,600	)		(4,187	)
	Amortization of Prior-Service Cost:
	From Regulatory Asset		47			64
	From Other Comprehensive Income1		1			2
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		1,633			868
	From Other Comprehensive Income1		40			23
	Net Periodic Pension Cost	$	1,946		$	1,230
	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)	2015			2014
	Service Cost—Benefit Earned During the Period	$	47		$	13
	Interest Cost on Projected Benefit Obligation		381			380
	Amortization of Prior-Service Cost:
	From Regulatory Asset		4			5
	From Other Comprehensive Income1		10			13
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		83			35
	From Other Comprehensive Income2		151			12
	Net Periodic Pension Cost	$	676		$	458
	1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses	$	4		$	5
	Other Nonelectric Expenses		6			8
	2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses	$	78		$	33
	Other Nonelectric Expenses		73			(21	)
Postretirement Benefits
Schedule of components of net periodic postretirement benefit cost
		Three Months Ended March 31,
	(in thousands)	2015			2014
	Service Cost—Benefit Earned During the Period	$	375		$	315
	Interest Cost on Projected Benefit Obligation		550			558
	Amortization of Prior-Service Cost:
	From Regulatory Asset		51			51
	From Other Comprehensive Income1		1			1
	Amortization of Net Actuarial Loss:
	From Regulatory Asset		48			--
	From Other Comprehensive Income1		1			--
	Net Periodic Postretirement Benefit Cost	$	1,026		$	925
	Effect of Medicare Part D Subsidy	$	(450	)	$	(308	)
	1 Corporate cost included in Other Nonelectric Expenses.

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of long-term debt including current maturities
		31-Mar-15						31-Dec-14
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Cash and Cash Equivalents	$	157		$	157		$	--		$	--
	Short-Term Debt		(48,652	)		(48,652	)		(10,854	)		(10,854	)
	Long-Term Debt including Current Maturities		(498,641	)		(571,801	)		(498,690	)		(600,828	)

Income_Tax_Expense_Continuing_1

Income Tax Expense - Continuing Operations (Tables)	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of income from continuing operations before income taxes and income tax expense
		Three Months Ended March 31,
	(in thousands)	2015			2014
	Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
	Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
	Increases (Decreases) in Tax from:
	Federal Production Tax Credits		(2,054	)		(2,252	)
	Section 199 Domestic Production Activities Deduction		(362	)		(358	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
	Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
	AFUDC Equity		(100	)		(133	)
	Corporate Owned Life Insurance		(80	)		(112	)
	Other Items – Net		90			(15	)
	Income Tax Expense – Continuing Operations	$	4,073		$	8,562
	Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%
Schedule of activity related to unrecognized tax benefits
	(in thousands)	2015			2014
	Balance on January 1	$	222		$	4,239
	Increases Related to Tax Positions for Prior Years		--			137
	Increases Related to Tax Positions for Current Year		44			--
	Uncertain Positions Resolved During Year		--			--
	Balance on March 31	$	266		$	4,376

Discontinued_Operations_Tables

Discontinued Operations (Tables)	3 Months Ended
	Mar. 31, 2015
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)	2015			2014
	Operating Revenues	$	18,724		$	25,506
	Operating Expenses		22,141			26,368
	Goodwill Impairment Charge		1,000			--
	Operating Loss		(4,417	)		(862	)
	Other (Deductions) Income		(31	)		288
	Income Tax Benefit		(1,376	)		(225	)
	Net Loss from Operations		(3,072	)		(349	)
	Gain on Disposition Before Taxes		12,042			--
	Income Tax Expense on Disposition		4,816			--
	Net Gain on Disposition		7,226			--
	Net Income (Loss)	$	4,154		$	(349	)
	(in thousands)	March 31,			December 31,
		2015			2014
	Current Assets	$	26,928		$	35,174
	Goodwill and Intangibles		1,814			2,814
	Net Plant		4,429			10,669
	Assets of Discontinued Operations	$	33,171		$	48,657
	Current Liabilities	$	15,616		$	22,864
	Deferred Income Taxes		5,116			4,695
	Liabilities of Discontinued Operations	$	20,732		$	27,559
Schedule of costs incurred and billings and estimated earnings
		March 31,			December 31,
	(in thousands)	2015			2014
	Costs Incurred on Uncompleted Contracts	$	339,594		$	402,332
	Less Billings to Date		(354,256	)		(411,909	)
	Plus Estimated Earnings Recognized		14,458			15,154
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577
Schedule of costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings
		March 31,			December 31,
	(in thousands)	2015			2014
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,216		$	8,133
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(3,420	)		(2,556	)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577
Schedule of warranty reserves
	(in thousands)	2015			2014
	Warranty Reserve Balance, January 1	$	2,527		$	3,087
	Additional Provision for Warranties Made During the Year		--			--
	Settlements Made During the Year		(6	)		--
	Decrease in Warranty Estimates for Prior Years		--			(100	)
	Warranty Reserve Balance, March 31	$	2,521		$	2,987
Schedule of accounts receivable retained by customers pending project completion
		March 31,			December 31,
	(in thousands)	2015			2014
	Accounts Receivable Retained by Customers	$	4,018		$	6,759

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) (Fair Value, Measurements, Recurring, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Level 1
Assets:
Total Assets	$2,550	$713
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Level 1 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale	2,000
Level 1 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities
Level 1 | Money Market and Mutual Funds
Assets:
Derivative Assets		120
Other Assets - Nonqualified Retirement Savings Plan	550	593
Level 2
Assets:
Total Assets	7,854	8,014
Liabilities:
Total Liabilities	282	342
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets
Level 2 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale
Level 2 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities	282	342
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	6,625	6,761
Level 2 | U.S. Government-Sponsored Enterprises' Debt Securities
Assets:
Investments - Held by Captive Insurance Company	1,229	1,253
Level 3
Assets:
Total Assets	381	257
Liabilities:
Total Liabilities	11,285	13,888
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	381	257
Liabilities:
Derivative Liabilities	11,285	13,888
Level 3 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale
Level 3 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 1) (Forward Energy Contracts, Level 3, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
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	($13,631)	($11,341)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	3,386	1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods	-368	3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	-10,613	-6,683
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period	-291	40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	($10,904)	($6,643)

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Inventories (Details 2) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Finished Goods	$27,607	$27,998
Work in Process	9,894	10,628
Raw Material, Fuel and Supplies	47,014	46,577
Total Inventories	$84,515	$85,203

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 3) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Goodwill [Line Items]
Gross Balance December 31, 2014	$31,488
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	31,488
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	31,488
Manufacturing
Goodwill [Line Items]
Gross Balance December 31, 2014	12,186
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	12,186
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	12,186
Plastics
Goodwill [Line Items]
Gross Balance December 31, 2014	19,302
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	19,302
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	$19,302

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Components of intangible assets (Details 4) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Amortizable Intangible Assets:
Gross Carrying Amount	17,556	17,450
Accumulated Amortization	6,443	6,199
Net Carrying Amount	11,113	11,251
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	5,996	5,784
Net Carrying Amount	10,815	11,027
Customer Relationships | Minimum
Amortizable Intangible Assets:
Amortization Periods	57 months	60 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Amortization Periods	157 months	160 months
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Gross Carrying Amount	639	639
Accumulated Amortization	447	415
Net Carrying Amount	192	224
Amortization Periods	18 months	21 months
Emission Allowances
Amortizable Intangible Assets:
Gross Carrying Amount	106
Accumulated Amortization
Net Carrying Amount	106

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 5) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$244	$244

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 6) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
2015	$977
2016	945
2017	849
2018	849
2019	$849

Recovered_Sheet1

Summary of Significant Accounting Policies - Reconciliation of OTP's emission allowances (Details 7) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Intangible Assets [Line Items]
Emission Allowances Beginning Balance		$11,251
Emission Allowances Ending Balance	11,113	11,251
Emission Allowances
Intangible Assets [Line Items]
Emission Allowances Beginning Balance
Allowances Purchased	168
Allowances Used	-62
Emission Allowances Ending Balance	$106

Recovered_Sheet2

Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 8) (USD $)	Mar. 31, 2015		Mar. 31, 2014
In Thousands, unless otherwise specified
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$32,838	[1]	$22,244	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$7,554	[2]	$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.

Recovered_Sheet3

Summary of Significant Accounting Policies (Detail Textuals) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Minimum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	1 year
Maximum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	15 years
Forward Electricity Contracts | Level 3
Significant Accounting Policies [Line Items]
Electric inputs minimum deviation below active trade hub prices per megawatt-hour	2.46
Electric inputs maximum deviation below active trading hub price per megawatt-hour	8
Electric inputs weighted average price per megawatt-hour	34.45
Forward Electricity Contracts | Power purchase contracts | Level 3
Significant Accounting Policies [Line Items]
Percentage of offset by regulatory liabilities and assets of fuel clause adjustment treatment of fuel costs	100.00%
Net impact of recorded fair valuation gains or losses related to derivative contract	0
Net income impact of future fair valuation adjustments of contracts	0

Recovered_Sheet4

Summary of Significant Accounting Policies (Detail Textuals 1) (Coyote Creek Mining Company, L.L.C. (CCMC), Lignite Sales Agreement, Otter Tail Power Company, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
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%
Amount of development period costs, development fees and capital charges incurred by CCMC	$28.50
Maximum exposure to loss as a result of involvement with CCMC	$28.50

Segment_Information_Percent_of

Segment Information - Percent of sales revenue by country (Details) (Sales)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	96.30%	97.20%
Mexico
Segment Reporting Information [Line Items]
Percentage of sales revenue	3.00%	2.20%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.60%	0.50%
All Other Countries (none individually greater than 0.05%)
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.10%	0.10%

Segment_Information_Informatio

Segment Information - Information on continuing operations for business segments (Details 1) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating Revenue	$202,841	$214,966
Interest Charges	7,743	6,595
Income Taxes	4,073	8,562
Net Income	17,935	21,430
Identifiable Assets	1,815,180		1,791,279
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	-17	-40
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	544	461
Corporate
Segment Reporting Information [Line Items]
Income Taxes	-1,916	-992
Net Income	-2,701	-1,230
Identifiable Assets	68,321		51,918
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income	4,154	-349
Identifiable Assets	33,171		48,657
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	113,547	119,088
Interest Charges	6,121	5,079
Income Taxes	4,221	5,750
Net Income	13,178	16,653
Identifiable Assets	1,484,289		1,472,647
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	56,759	55,435
Interest Charges	832	808
Income Taxes	504	1,671
Net Income	1,184	2,896
Identifiable Assets	139,143		130,701
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	32,552	40,483
Interest Charges	246	247
Income Taxes	1,264	2,133
Net Income	2,120	3,460
Identifiable Assets	$90,256		$87,356

Segment_Information_Detail_Tex

Segment Information (Detail Textuals)	3 Months Ended
	Mar. 31, 2015
	Segment
Segment Reporting [Abstract]
Number of reportable segments	3

Rate_and_Regulatory_Matters_Su

Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 1) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	$202,841		$214,966
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,615		2,304
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	2,557		1,763
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,928	[1]	1,521	[1]
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,883		1,435
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,936		1,514
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	2,156		1,522
Otter Tail Power Company | North Dakota | Big Stone II Project Costs
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders			361
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	363		346
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	$504
[1]	Includes MNCIP costs recovered in base rates.

Rate_and_Regulatory_Matters_De

Rate and Regulatory Matters (Detail Textuals) (USD $)	3 Months Ended	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2011	Mar. 31, 2014
		mi	mi
		Kv
Otter Tail Power Company
Regulatory Matters [Line Items]
Increase In reagent costs and emission allowances	$4.10
Reagent costs	3.6
Emission allowances	0.5
Otter Tail Power Company | Minnesota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	50.00%
Otter Tail Power Company | North Dakota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	40.00%
Otter Tail Power Company | South Dakota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	10.00%
Otter Tail Power Company | Big Stone South - Brookings MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Expanded capacity of projects		345
Extended distance of transmission line		70
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Expanded capacity of projects		345
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Minimum
Regulatory Matters [Line Items]
Extended distance of transmission line		160
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Maximum
Regulatory Matters [Line Items]
Extended distance of transmission line		170
Big Stone AQCS Project BART - compliant AQCS
Regulatory Matters [Line Items]
Current projected cost	384
Big Stone AQCS Project BART - compliant AQCS | Otter Tail Power Company
Regulatory Matters [Line Items]
Current projected cost	207
Percentage of projected cost	53.90%
Construction expenditures	$174.90
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project
Regulatory Matters [Line Items]
Extended distance of transmission line			250

Rate_and_Regulatory_Matters_De1

Rate and Regulatory Matters (Detail Textuals 1) (USD $)	3 Months Ended	0 Months Ended	1 Months Ended
	Mar. 31, 2015	Feb. 07, 2013	Dec. 31, 2014	Jul. 30, 2014	Jul. 31, 2014	Apr. 25, 2011	Sep. 26, 2014
		Project
Conservation Improvement Program | Fiscal Year 2014
Regulatory Matters [Line Items]
Financial incentives recognized during period	$3,000,000
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013
Regulatory Matters [Line Items]
Financial incentive request approved							4,000,000
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 To 2015
Regulatory Matters [Line Items]
Lower Estimated Incentives	0.09
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 To 2016
Regulatory Matters [Line Items]
Lower Estimated Incentives	0.07
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Number of additional projects approved		3
Otter Tail Power Company | Minnesota Public Utilities Commission | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Annual revenue requirement			9,800,000	6,100,000	10,200,000
Annual increase in revenue requirement					4,100,000
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved						$5,000,000
Percentage of increase in base rate revenue approved by rate authority						1.60%
Public utilities allowed rate of return prior to approval of increase in base rate						8.33%
Public utilities allowed rate of return subsequent to approval of increase in base rate						8.61%
Public utilities allowed rate of return on equity prior to approval of increase in base rate						10.43%
Public utilities allowed rate of return on equity subsequent to approval of increase in base rate						10.74%

Rate_and_Regulatory_Matters_De2

Rate and Regulatory Matters (Detail Textuals 2) (Otter Tail Power Company, North Dakota Public Service Commission, USD $)	1 Months Ended	0 Months Ended	1 Months Ended
	Aug. 29, 2014	Mar. 12, 2014	Mar. 31, 2014	Nov. 25, 2009
Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Regulators jurisdictional share of transmission costs	$100,000
Renewable Resource Cost Recovery Rider
Regulatory Matters [Line Items]
Percentage of reduction in the NDRRA		13.50%
Environmental Cost Recovery Rider | Minimum
Regulatory Matters [Line Items]
Percentage of ECR rider rate			4.32%
Environmental Cost Recovery Rider | Maximum
Regulatory Matters [Line Items]
Percentage of ECR rider rate			7.53%
2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority				$3,600,000
Percentage of increase in base rate revenue approved by rate authority				3.00%
Percentage Of Allowed Rate Of Return On Rate Base				8.62%
Percentage Of Allowed Rate Of Return On Equity				10.75%

Rate_and_Regulatory_Matters_De3

Rate and Regulatory Matters (Detail Textuals 3) (Otter Tail Power Company, USD $)	1 Months Ended	0 Months Ended	1 Months Ended
	Apr. 21, 2011	Feb. 12, 2015	Nov. 30, 2013	Mar. 31, 2015
South Dakota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority	643,000
Percentage of increase in base rate revenue approved by rate authority	2.32%
South Dakota Public Utilities Commission | 2010 General Rate Case | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Public utilities allowed rate of return subsequent to approval of increase in base rate	8.50%
Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Proposed reduced return on equity used in transmission rates		8.67%	9.15%
Estimated liability of refund obligation				$600,000
Current return on equity used in transmission rates			12.38%

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	$20,352		$25,273
Regulatory Liability - Current	2,744		1,158
Net Regulatory Assets Position - Current	17,608		24,115
Regulatory Assets - Long-Term	127,368		129,868
Regulatory Liabilities - Long-Term	77,851		77,013
Net Regulatory Assets (Liability) Position - Long-Term	49,517		52,855
Regulatory Assets - Total	147,720		155,141
Regulatory Liabilities - Total	80,595		78,171
Net Regulatory Asset Position - Total	67,125		76,970
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	7,465	[1]	7,464	[1]
Regulatory Assets - Long-Term	99,659	[1]	101,526	[1]
Regulatory Assets - Total	107,124	[1]	108,990	[1]
Regulatory Assets - Remaining Recovery/Refund Period	see below	[1]	see below	[1]
Deferred Marked-to-Market Loss
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,059	[1]	4,492	[1]
Regulatory Assets - Long-Term	9,226	[1]	9,396	[1]
Regulatory Assets - Total	11,285	[1]	13,888	[1]
Regulatory Assets - Remaining Recovery/Refund Period	69 months	[1]	72 months	[1]
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	3,815	[2]	5,843	[2]
Regulatory Assets - Long-Term	3,511	[2]	2,500	[2]
Regulatory Assets - Total	7,326	[2]	8,343	[2]
Regulatory Assets - Remaining Recovery/Refund Period	27 months	[2]	18 months	[2]
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Assets - Long-Term	5,305	[1]	5,190	[1]
Regulatory Assets - Total	5,305	[1]	5,190	[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	601	[1]	592	[1]
Regulatory Assets - Long-Term	3,086	[1]	3,207	[1]
Regulatory Assets - Total	3,687	[1]	3,799	[1]
Regulatory Assets - Remaining Recovery/Refund Period	93 months	[1]	96 months	[1]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,140	[1]	2,585	[1]
Regulatory Assets - Long-Term	636	[1]	807	[1]
Regulatory Assets - Total	2,776	[1]	3,392	[1]
Regulatory Assets - Remaining Recovery/Refund Period	24 months		24 months	[1]
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	351	[1]	351	[1]
Regulatory Assets - Long-Term	1,802	[1]	1,890	[1]
Regulatory Assets - Total	2,153	[1]	2,241	[1]
Regulatory Assets - Remaining Recovery/Refund Period	210 months	[1]	213 months	[1]
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	1,461	[1]	2,086	[1]
Regulatory Liabilities - Long-Term	1,447		1,550
Regulatory Assets - Total	1,461	[1]	2,086	[1]
Regulatory Liabilities - Total	1,447		1,550
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			706	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			706	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
Minnesota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			186	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			186	[2]
Regulatory Assets - Remaining Recovery/Refund Period			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 below	[2]	see below	[2]
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term	75,220		74,237
Regulatory Liabilities - Total	75,220		74,237
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	204
Regulatory Liabilities - Long-Term	177		257
Regulatory Liabilities - Total	381		257
Regulatory Liabilities - Remaining Recovery/Refund Period	58 months		67 months
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	1,803		933
Regulatory Liabilities - Long-Term			85
Regulatory Liabilities - Total	1,803		1,018
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		15 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	908		784
Regulatory Liabilities - Total	908		784
Regulatory Liabilities - Remaining Recovery/Refund Period	see below		see below
Big Stone II Over Recovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	111		147
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	111		147
Regulatory Liabilities - Remaining Recovery/Refund Period	9 months		12 months
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	100	[2]	100	[2]
Regulatory Assets - Long-Term	718	[2]	743	[2]
Regulatory Assets - Total	818	[2]	843	[2]
Regulatory Assets - Remaining Recovery/Refund Period	98 months	[2]	101 months	[2]
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]
Regulatory Assets - Long-Term	61	[2]
Regulatory Assets - Total	61	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	6		6
Regulatory Liabilities - Long-Term	99		100
Regulatory Liabilities - Total	105		106
Regulatory Liabilities - Remaining Recovery/Refund Period	225 months		228 months
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,249	[1]	1,114	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	1,249	[1]	1,114	[1]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[1]	12 months	[1]
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			24
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			24
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,152	[2]	943	[2]
Regulatory Assets - Long-Term	1,835	[2]	2,455	[2]
Regulatory Assets - Total	3,987	[2]	3,398	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	24 months	[2]
North Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	420	[2]	859	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	420	[2]	859	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	12 months	[2]
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	451
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	451
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
South Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			38	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			38	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
South Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	48		48
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	48		48
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	35
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	35
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	86
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	$86
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
[1]	Costs subject to recovery without a rate of return.
[2]	Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities (Detail Textuals) (Debt Reacquisition Premiums)	3 Months Ended
	Mar. 31, 2015
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	210 months

Forward_Contracts_Classified_a2

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 $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$20,352	$25,273
Regulatory Assets - Long-Term	127,368	129,868
Current Liability - Marked-to-Market Loss	-11,567	-14,230
Regulatory Liability - Current	-2,744	-1,158
Regulatory Liabilities - Long-Term	-77,851	-77,013
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Current Asset - Marked-to-Market Gain	381	257
Total Assets	11,666	14,145
Current Liability - Marked-to-Market Loss	-11,285	-13,888
Total Liabilities	-11,666	-14,145
Net Fair Value of Marked-to-Market Energy Contracts			39	115
Forward Electricity Contracts | Deferred Marked-to-Market Loss
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	2,059	4,492
Regulatory Assets - Long-Term	9,226	9,396
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current	-204
Regulatory Liabilities - Long-Term	($177)	($257)

Forward_Contracts_Classified_a3

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
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Forward Electricity Contracts
Derivatives Fair Value [Roll Forward]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year		$115
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		-72
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
Cumulative Fair Value Adjustments Included in Earnings - End of Period		$39

Forward_Contracts_Classified_a4

Forward Contracts Classified as Derivatives - Realized and unrealized net (losses)/gains on forward energy contracts included in electric operating revenues (Details 2) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Loss on Forward Electric Energy Contracts		($4)

Forward_Contracts_Classified_a5

Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 3) (Legally enforceable netting arrangements, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Legally enforceable netting arrangements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative assets subject to legally enforceable netting arrangements	$381	$257
Derivative liabilities subject to legally enforceable netting arrangements	-11,567	-14,230
Net balance subject to legally enforceable netting arrangements	($11,186)	($13,973)

Forward_Contracts_Classified_a6

Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 4) (Otter Tail Power Company, USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit	$282		$45
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	11,285	[1]	13,888	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements			297
Total Current Liability - Marked-to-Market Loss	$11,567		$14,230
[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 $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631

Forward_Contracts_Classified_a7

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 $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$11,285	[1]	$13,888	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	-381		-257
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$10,904		$13,631
[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 $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631

Reconciliation_of_Common_Share2

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	$572,766
Common Stock Issuances, Net of Expenses	7,522
Common Stock Retirements	-1,239
Net Income	17,935	21,430
Other Comprehensive Income	141
Tax Benefit - Stock Compensation	24
Employee Stock Incentive Plans Expense	623
Common Dividends ($0.3075 per share)	-11,498
Balance, End of Period	586,274
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	186,090
Common Stock Issuances, Net of Expenses	1,220
Common Stock Retirements	-195
Balance, End of Period	187,115
Premium On Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	278,436
Common Stock Issuances, Net of Expenses	6,302
Common Stock Retirements	-1,044
Tax Benefit - Stock Compensation	24
Employee Stock Incentive Plans Expense	623
Balance, End of Period	284,341
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	112,903
Net Income	17,935
Common Dividends ($0.3075 per share)	-11,498
Balance, End of Period	119,340
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	-4,663
Other Comprehensive Income	141
Balance, End of Period	($4,522)

Reconciliation_of_Common_Share3

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$0.31	$0.30

Reconciliation_of_Common_Share4

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1)	3 Months Ended
	Mar. 31, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Executive Stock Performance Awards (2012-2014 shares earned)	89,991
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	42,518
Cash Invested	16,553
At-the-Market Offering	38,160
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	5,985
Employee Stock Ownership Plan	21,137
Stock Options Exercised	9,000
Vesting of Restricted Stock Units	700
Retirements:
Shares Withheld for Individual Income Tax Requirements	-39,131
Common Shares Outstanding, March 31, 2015	37,422,959

Reconciliation_of_Common_Share5

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted (Details 2)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	37,243,118	36,240,350
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers	229,100	131,000
Nonvested Restricted Shares	83,330	90,798
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	70,900	55,655
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	40,462	39,197
Potentially Dilutive Stock Options	3,750	18,050
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares	-169,842	-127,709
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options	-2,937	-15,426
Total Dilutive Shares	254,763	191,565
Weighted Average Common Shares Outstanding - Diluted	37,497,881	36,431,915

Reconciliation_of_Common_Share6

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015
Stockholders Equity Note [Line Items]
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations	$0.01
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS)
Stockholders Equity Note [Line Items]
Agreement To Sell Shares Value	$75

ShareBased_Payments_Stock_Ince

Share-Based Payments - Stock Incentive Awards (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	116,250
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	77,500
Weighted Average Grant-Date Fair Value per Award	26.99
Vesting Date	31-Dec-17
Restricted Stock Units | Executive Officer Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	20,900
Weighted Average Grant-Date Fair Value per Award	31.675
Vesting Percentage	25.00%
Vesting Date	6-Feb-19
Restricted Stock Units | Executive Officer Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	6,400
Weighted Average Grant-Date Fair Value per Award	31.675
Vesting Percentage	100.00%
Vesting Date	6-Feb-20

ShareBased_Payments_Amounts_of

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$1,643	$884
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	49	42
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	98	123
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	157	135
Restricted Stock Units (RSUs) | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	66	58
Restricted Stock Units (RSUs) | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	253
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$1,020	$526

ShareBased_Payments_Amounts_of1

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details) (Employee Stock Purchase Plan)	3 Months Ended
	Mar. 31, 2015
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense, discount rate	15.00%

ShareBased_Payments_Detail_Tex

Share-Based Payments (Detail Textuals)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award	116,250
Stock Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period specified for average adjusted return	3 years
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target award total shareholder return/equity component	51,667
Targeted aggregate common shares award	77,500
Stock Performance Awards | Executive Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Executive Officers | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	0.00%
Stock Performance Awards Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target award total shareholder return/equity component	25,833

ShareBased_Payments_Detail_Tex1

Share-Based Payments (Detail Textuals 1) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Unrecognized compensation expense related to stock-based compensation	$2.80
Weighted-average period of amortization	2 years 3 months 18 days

Retained_Earnings_Restriction_

Retained Earnings Restriction (Detail Textuals) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Retained Earnings Restriction [Line Items]
Total Capitalization	$1,084,711	$1,071,255
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	50.70%
Total Capitalization	$987,000
OTP | Minimum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	45.00%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	55.00%

Commitments_and_Contingencies_

Commitments and Contingencies (Detail Textuals) (Otter Tail Power Company, USD $)	3 Months Ended	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Apr. 30, 2015
Commitments and Contingencies Disclosure [Line Items]
Amount of reduction in revenue and liability	$0.60
Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	2.9
Contracts expiration year	2039
Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	10
Contracts expiration year	2015, 2016, 2017 and 2040
Loss contingency, range of possible loss, maximum	5
Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	106.1	106.6
Subsequent event
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount			$2.80

ShortTerm_and_LongTerm_Borrowi2

Short-Term and Long-Term Borrowings - Status of lines of credit (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Line of Credit Facility [Line Items]
Line Limit	$320,000
In Use	48,652
Restricted due to Outstanding Letters of Credit	755
Available	270,593	308,312
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	40,846
Restricted due to Outstanding Letters of Credit	195
Available	108,959	138,872
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	7,806
Restricted due to Outstanding Letters of Credit	560
Available	$161,634	$169,440

ShortTerm_and_LongTerm_Borrowi3

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Short-Term Debt	$48,652	$10,854
Long-Term Debt	498,641	498,691
Less: Current Maturities	204	201
Unamortized Debt Discount		1
Total Long-Term Debt	498,437	498,489
Total Short-Term and Long-Term Debt (with current maturities)	547,293	509,544
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	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	90,000
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	237	256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	1,074	1,105
OTP
Debt Instrument [Line Items]
Short-Term Debt	7,806
Long-Term Debt	445,000	445,000
Less: Current Maturities
Unamortized Debt Discount
Total Long-Term Debt	445,000	445,000
Total Short-Term and Long-Term Debt (with current maturities)	452,806	445,000
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	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	90,000
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	40,846	10,854
Long-Term Debt	53,641	53,691
Less: Current Maturities	204	201
Unamortized Debt Discount		1
Total Long-Term Debt	53,437	53,489
Total Short-Term and Long-Term Debt (with current maturities)	94,487	64,544
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	237	256
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$1,074	$1,105

ShortTerm_and_LongTerm_Borrowi4

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, 2015	Dec. 31, 2014
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	15-Dec-16	15-Dec-16
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	15-Dec-16	15-Dec-16
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	20-Aug-17	20-Aug-17
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	20-Aug-17	20-Aug-17
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	1-Dec-21	1-Dec-21
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	1-Dec-21	1-Dec-21
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	20-Aug-22	20-Aug-22
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	20-Aug-22	20-Aug-22
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	20-Aug-27	20-Aug-27
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	20-Aug-27	20-Aug-27
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	27-Feb-29	27-Feb-29
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	27-Feb-29	27-Feb-29
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	20-Aug-37	20-Aug-37
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	20-Aug-37	20-Aug-37
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	27-Feb-44	27-Feb-44
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	27-Feb-44	27-Feb-44
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	1-Apr-18	1-Apr-18
North Dakota Development Note, 3.95%, due April 1, 2018 | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	1-Apr-18	1-Apr-18
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	18-Mar-21	18-Mar-21
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	18-Mar-21	18-Mar-21

Pension_Plan_and_Other_Postret2

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	$1,500		$1,175
Interest Cost on Projected Benefit Obligation	3,325		3,285
Expected Return on Assets	-4,600		-4,187
Amortization of Prior-Service Cost:
From Regulatory Asset	47		64
From Other Comprehensive Income	1	[1]	2	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	1,633		868
From Other Comprehensive Income	40	[1]	23	[1]
Net Periodic Pension Cost	1,946		1,230
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	47		13
Interest Cost on Projected Benefit Obligation	381		380
Amortization of Prior-Service Cost:
From Regulatory Asset	4		5
From Other Comprehensive Income	10	[2]	13	[2]
Amortization of Net Actuarial Loss:
From Regulatory Asset	83		35
From Other Comprehensive Income	151	[3]	12	[3]
Net Periodic Pension Cost	676		458
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	375		315
Interest Cost on Projected Benefit Obligation	550		558
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	48
From Other Comprehensive Income	1	[1]		[1]
Net Periodic Pension Cost	1,026		925
Effect of Medicare Part D Subsidy	($450)		($308)
[1]	Corporate cost included in Other Nonelectric Expenses.
[2]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8
[3]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 )

Pension_Plan_and_Other_Postret3

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	$10	[1]	$13	[1]
Amortization of Net Actuarial Loss - From Other Comprehensive Income	151	[2]	12	[2]
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	4		5
Amortization of Net Actuarial Loss - From Other Comprehensive Income	78		33
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	6		8
Amortization of Net Actuarial Loss - From Other Comprehensive Income	$73		($21)
[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8
[2]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 )

Pension_Plan_and_Other_Postret4

Pension Plan and Other Postretirement Benefits (Detail Textuals) (Pension Plan, USD $)	1 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discretionary plan contributions	$10,000,000	$20,000,000

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$157
Short-Term Debt	-48,652	-10,854
Long-Term Debt including Current Maturities	-498,641	-498,690
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	157
Short-Term Debt	-48,652	-10,854
Long-Term Debt including Current Maturities	($571,801)	($600,828)

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Detail Textuals)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Otter Tail Corporation Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis	LIBOR
Basis spread on variable rate	1.75%
OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis		LIBOR
Basis spread on variable rate		1.25%

Income_Tax_Expense_Continuing_2

Income Tax Expense - Continuing operations effective income tax rate (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$17,854	$30,341
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	6,963	11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits	2,054	2,252
Section 199 Domestic Production Activities Deduction	-362	-358
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	-212	-212
Employee Stock Ownership Plan Dividend Deduction	-172	-189
AFUDC Equity	-100	-133
Corporate Owned Life Insurance	-80	-112
Other Items - Net	90	-15
Income Tax Expense - Continuing Operations	$4,073	$8,562
Effective Income Tax Rate - Continuing Operations	22.80%	28.20%

Income_Tax_Expense_Continuing_3

Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%

Income_Tax_Expense_Continuing_4

Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Balance on January 1	$222	$4,239
Increases Related to Tax Positions for Prior Years		137
Increases Related to Tax Positions for Current Year	44
Uncertain Positions Resolved During Year
Balance on March 31	$266	$4,376

Discontinued_Operations_Result

Discontinued Operations - Results of discontinued operations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Loss from Operations	($3,072)	($349)
Income Tax Expense on Disposition	4,816
Net Gain on Disposition	7,226
Net Income (Loss)	4,154	-349
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	18,724	25,506
Operating Expenses	22,141	26,368
Goodwill Impairment Charge	1,000
Operating Loss	-4,417	-862
Other (Deductions) Income	-31	288
Income Tax Benefit	-1,376	-225
Net Loss from Operations	-3,072	-349
Gain on Disposition Before Taxes	12,042
Income Tax Expense on Disposition	4,816
Net Gain on Disposition	7,226
Net Income (Loss)	$4,154	($349)

Discontinued_Operations_Major_

Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets of Discontinued Operations	$33,171	$48,657
Liabilities of Discontinued Operations	20,732	27,559
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	26,928	35,174
Goodwill and Intangibles	1,814	2,814
Net Plant	4,429	10,669
Assets of Discontinued Operations	33,171	48,657
Current Liabilities	15,616	22,864
Deferred Income Taxes	5,116	4,695
Liabilities of Discontinued Operations	$20,732	$27,559

Discontinued_Operations_Summar

Discontinued Operations - Summary of costs incurred and billings and estimated earnings recognized on uncompleted contracts (Details 2) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$339,594	$402,332
Less Billings to Date	-354,256	-411,909
Plus Estimated Earnings Recognized	14,458	15,154
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	($204)	$5,577

Discontinued_Operations_Costs_

Discontinued Operations - Costs and estimated earnings in excess of billings that are included in consolidated balance sheets (Details 3) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$3,216	$8,133
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	-3,420	-2,556
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	($204)	$5,577

Discontinued_Operations_Warran

Discontinued Operations - Warranty Reserves (Details 4) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Warranty Reserve Balance, January 1	$2,527	$3,087
Additional Provision for Warranties Made During the Year
Settlements Made During the Year	-6
Decrease in Warranty Estimates for Prior Years		-100
Warranty Reserve Balance, March 31	$2,521	$2,987

Discontinued_Operations_Accoun

Discontinued Operations - Accounts receivable retained by customers pending project completion (Details 5) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Discontinued Operations and Disposal Groups [Abstract]
Accounts Receivable Retained by Customers	$4,018	$6,759

Discontinued_Operations_Detail

Discontinued Operations (Detail Textuals) (USD $)	3 Months Ended	1 Months Ended	3 Months Ended
	Mar. 31, 2015	Feb. 28, 2015	Dec. 31, 2014	Apr. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations	$21,343,000
Net Gain on Disposition	7,226,000
AEV, Inc.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations		22,300,000
Amount of working capital		900,000
Net Gain on Disposition		7,200,000
Foley
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Impairment Charges	1,000,000		5,600,000
Cost estimates pretax charges	2,300,000
Foley | Subsequent event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of Aevenia before working capital and other adjustments				$12,000,000
Consideration for sale of business, description				The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing.

Subsequent_Events_Detail_Textu

Subsequent Events (Detail Textuals) (Subsequent event, Foley, USD $)	3 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2015
Subsequent event | Foley
Subsequent Event [Line Items]
Proceeds from sale of Aevenia before working capital and other adjustments	$12
Consideration for sale of business, description	The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing.