Otter Tail (OTTR) 10-Q 10 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1,466,593
Trading Symbol	ottr
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		37,591,785
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets (no

Consolidated Balance Sheets (not audited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents
Accounts Receivable:
Trade - Net	$ 67,315	$ 60,172
Other	18,248	13,179
Inventories	81,803	85,203
Deferred Income Taxes	54,498	49,482
Unbilled Revenues	14,352	17,996
Regulatory Assets	17,736	25,273
Other	8,588	7,187
Assets of Discontinued Operations	133	48,657
Total Current Assets	262,673	307,149
Investments	10,679	8,582
Other Assets	30,827	30,111
Goodwill	31,488	31,488
Other Intangibles - Net	10,863	11,251
Deferred Debits
Unamortized Debt Expense	3,949	4,300
Regulatory Assets	127,475	129,868
Total Deferred Debits	131,424	134,168
Plant
Electric Plant in Service	1,583,169	1,545,112
Nonelectric Operations	180,309	175,159
Construction Work in Progress	269,060	248,677
Total Gross Plant	2,032,538	1,968,948
Less Accumulated Depreciation and Amortization	699,113	700,418
Net Plant	1,333,425	1,268,530
Total Assets	1,811,379	1,791,279
Current Liabilities
Short-Term Debt	43,040	10,854
Current Maturities of Long-Term Debt	207	201
Accounts Payable	101,020	107,013
Accrued Salaries and Wages	14,077	19,256
Accrued Taxes	9,997	13,793
Derivative Liabilities	14,388	14,230
Other Accrued Liabilities	12,099	8,793
Liabilities of Discontinued Operations	3,260	27,559
Total Current Liabilities	198,088	201,699
Pensions Benefit Liability	93,545	102,711
Other Postretirement Benefits Liability	54,357	53,638
Other Noncurrent Liabilities	$ 24,319	$ 26,794
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	$ 248,581	$ 230,810
Deferred Tax Credits	25,445	26,384
Regulatory Liabilities	77,972	77,013
Other	977	975
Total Deferred Credits	352,975	335,182
Capitalization
Long-Term Debt, Net of Current Maturities	498,384	498,489
Common Shares, Par Value $5 Per Share-Authorized, 50,000,000 Shares; Outstanding, 2015-37,565,590 Shares; 2014-37,218,053 Shares	187,828	186,090
Premium on Common Shares	287,066	278,436
Retained Earnings	119,239	112,903
Accumulated Other Comprehensive Loss	(4,422)	(4,663)
Total Common Equity	589,711	572,766
Total Capitalization	1,088,095	1,071,255
Total Liabilities and Equity	$ 1,811,379	$ 1,791,279
Cumulative Preferred Shares
Capitalization
Cumulative Shares
Cumulative Preference Shares
Capitalization
Cumulative Shares

Consolidated Balance Sheets (n3

Consolidated Balance Sheets (not audited) (Parentheticals) - $ / shares	Jun. 30, 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	37,565,590	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 Inco

Consolidated Statements of Income (not audited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating Revenues
Electric	$ 90,927	$ 92,903	$ 204,460	$ 211,951
Product Sales	97,226	101,461	186,534	197,379
Total Operating Revenues	188,153	194,364	390,994	409,330
Operating Expenses
Production Fuel - Electric	4,183	12,603	18,782	34,633
Purchased Power - Electric System Use	19,684	16,476	43,376	38,261
Electric Operation and Maintenance Expenses	37,754	39,774	75,281	74,396
Cost of Products Sold (depreciation included below)	74,986	80,178	146,484	154,117
Other Nonelectric Expenses	8,823	12,722	21,286	22,673
Depreciation and Amortization	14,661	14,472	29,196	28,739
Property Taxes - Electric	3,262	3,387	6,764	6,358
Total Operating Expenses	163,353	179,612	341,169	359,177
Operating Income	24,800	14,752	49,825	50,153
Interest Charges	7,702	7,626	15,445	14,221
Other Income	567	844	1,139	2,379
Income Before Income Taxes - Continuing Operations	17,665	7,970	35,519	38,311
Income Tax Expense - Continuing Operations	4,008	84	8,081	8,646
Net Income from Continuing Operations	13,657	7,886	27,438	29,665
Discontinued Operations
(Loss) Income - net of Income Tax (Benefit) Expense of ($1,329), $1,402, ($2,705) and $1,177 for the Respective Periods	(1,992)	2,107	(4,064)	1,758
Impairment Loss - net of Income Tax Benefit of $0 for the Six Months ended June 30, 2015			(1,000)
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of ($280) and $4,536 for the three and six months ended June 30, 2015	(229)		6,997
Net (Loss) Income from Discontinued Operations	(2,221)	2,107	1,933	1,758
Net Income	$ 11,436	$ 9,993	$ 29,371	$ 31,423
Average Number of Common Shares Outstanding-Basic (in shares)	37,433,318	36,409,753	37,338,218	36,325,052
Average Number of Common Shares Outstanding-Diluted (in shares)	37,653,203	36,652,684	37,558,103	36,568,030
Basic Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$ 0.37	$ 0.21	$ 0.74	$ 0.82
Discontinued Operations (in dollars per share)	(0.06)	0.06	0.05	0.05
Earnings Per Share, Basic, Total (in dollars per share)	0.31	0.27	0.79	0.87
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	0.36	0.21	0.73	0.81
Discontinued Operations (in dollars per share)	(0.06)	0.06	0.05	0.05
Earnings Per Share, Diluted, Total (in dollars per share)	0.30	0.27	0.78	0.86
Dividends Declared Per Common Share (in dollars per share)	$ 0.3075	$ 0.3025	$ 0.6150	$ 0.6050

Consolidated Statements of Inc5

Consolidated Statements of Income (not audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement [Abstract]
Income tax expense (benefit) on income (loss) from discontinued operation	$ (1,329)	$ 1,402	$ (2,705)	$ 1,177
Income tax (benefit) expense on impairment			0
Income tax (benefit) expense on gain (loss) from disposition	$ (280)		$ 4,536

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (not audited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 11,436	$ 9,993	$ 29,371	$ 31,423
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)
(Losses) Gains Arising During Period	(37)	36	(5)	19
Income Tax Benefit (Expense)	13	(13)	3	(1)
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	(24)	23	(5)	1
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	207	51	411	101
Income Tax Expense	(83)	(20)	(165)	(40)
Pension and Postretirement Benefit Plans - net-of-tax	124	31	246	61
Total Other Comprehensive Income	100	54	241	62
Total Comprehensive Income	$ 11,536	$ 10,047	$ 29,612	$ 31,485

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (not audited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash Flows from Operating Activities
Net Income	$ 29,371	$ 31,423
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations	(6,997)
Net Loss (Income) from Discontinued Operations	5,064	(1,758)
Depreciation and Amortization	29,196	28,739
Deferred Tax Credits	(939)	(907)
Deferred Income Taxes	12,707	13,402
Change in Deferred Debits and Other Assets	11,470	129
Discretionary Contribution to Pension Plan	(10,000)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	4,025	(936)
Allowance for Equity/Other Funds Used During Construction	(576)	(759)
Change in Derivatives Net of Regulatory Deferral	(123)	95
Stock Compensation Expense - Equity Awards	1,126	736
Other - Net	200	193
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(5,918)	(15,736)
Change in Inventories	3,400	(10,070)
Change in Other Current Assets	1,913	1,523
Change in Payables and Other Current Liabilities	(21,294)	(8,208)
Change in Interest and Income Taxes Receivable/Payable	96	2,664
Net Cash Provided by Continuing Operations	52,721	20,530
Net Cash Used in Discontinued Operations	(10,966)	(16,359)
Net Cash Provided by Operating Activities	41,755	4,171
Cash Flows from Investing Activities
Capital Expenditures	(83,418)	(79,574)
Net Proceeds from Disposal of Noncurrent Assets	2,628	1,386
Net Increase in Other Investments	(5,763)	(1,639)
Net Cash Used in Investing Activities - Continuing Operations	(86,553)	(79,827)
Net Proceeds from Sale of Discontinued Operations	32,765
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations	(1,770)	630
Net Cash Used in Investing Activities	(55,558)	(79,197)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(947)	2,014
Net Short-Term Borrowings (Repayments)	32,186	(23,051)
Proceeds from Issuance of Common Stock	7,096	8,452
Common Stock Issuance Expenses	(248)	(310)
Payments for Retirement of Capital Stock	(1,421)	(459)
Proceeds from Issuance of Long-Term Debt		150,000
Short-Term and Long-Term Debt Issuance Expenses	(4)	(516)
Payments for Retirement of Long-Term Debt	(99)	(40,993)
Dividends Paid and Other Distributions	(23,035)	(22,029)
Net Cash Provided by Financing Activities - Continuing Operations	13,528	73,108
Net Cash Provided by Financing Activities - Discontinued Operations	322	760
Net Cash Provided by Financing Activities	13,850	73,868
Net Change in Cash and Cash Equivalents - Discontinued Operations	$ (47)	(849)
Net Change in Cash and Cash Equivalents		(2,007)
Cash and Cash Equivalents at Beginning of Period		$ 2,007
Cash and Cash Equivalents at End of Period

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 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. Provisions for sales returns 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 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 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 June 30, 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 , 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 June 30, 2015 and December 31, 2014: June 30, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Forward Energy Contracts $ -- $ -- $ 194 Investments: Money Market Deposit Escrow Account – AEV, Inc. and Foley Company Sales 2,500 Corporate Debt Securities – Held by Captive Insurance Company 6,679 U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,221 Other Assets: Money Market and Mutual Funds - Nonqualified Retirement Savings Plan 273 Total Assets $ 2,773 $ 7,900 $ 194 Liabilities: Derivative Liabilities - Forward Gasoline Purchase Contracts $ -- $ 219 $ -- Derivative Liabilities - Forward Energy Contracts 14,169 Total Liabilities $ -- $ 219 $ 14,169 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 Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company 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 June 30, 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 June 30, 2015 Level 3 forward electric basis spreads ranged from $3.17 to $7.00 per megawatt-hour under the active trading hub price. The weighted average price was $32.71 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 June 30, 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 or six month periods ended June 30, 2015 and 2014. The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the six month periods ended June 30, 2015 and 2014: Six Months Ended June 30, (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 4,302 1,161 Net Changes in Fair Value of Contracts Entered into in Prior Periods (3,732 ) 7,400 Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period (13,061 ) (2,780 ) Net Loss Recognized as Regulatory Assets on Contracts Entered into in Period (914 ) -- Forward Energy Contracts - Net Derivative Liability Fair Values End of Period $ (13,975 ) $ (2,780 ) Inventories Inventories consist of the following: June 30, December 31, (in thousands) 2015 2014 Finished Goods $ 23,276 $ 27,998 Work in Process 10,877 10,628 Raw Material, Fuel and Supplies 47,650 46,577 Total Inventories $ 81,803 $ 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 in excess of their respective book values and not impaired. The following table summarizes goodwill by business segment indicating no changes to the carrying amounts in the first six months of 2015: (in thousands) Gross Balance Accumulated Impairments Balance (net of impairments) Adjustments to Goodwill in 2015 Balance (net of impairments) 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 June 30, 2015 (in thousands) Gross Carrying Accumulated Net Carrying Amount Remaining Amortizable Intangible Assets: Customer Relationships $ 16,811 $ 6,208 $ 10,603 54-154 months Other Intangible Assets Including Contracts 639 479 160 15 months Emission Allowances 100 NA 100 Expensed as used Total $ 17,550 $ 6,687 $ 10,863 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 Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Amortization Expense – Intangible Assets $ 244 $ 244 $ 488 $ 488 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 six month period ended June 30, 2015: Six Months Ended (in thousands) June 30, 2015 Emission Allowances Beginning Balance $ -- Allowances Purchased 168 Allowances Used (68 ) Emission Allowances Ending Balance $ 100 Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2015 2014 Noncash Investing Activities: Accounts Payable Outstanding Related to Capital Additions 1 $ 31,455 $ 21,992 Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions 2 $ 4,188 $ 4,373 1 2 Coyote Station Lignite Supply Agreement – Variable Interest Entity 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 initial delivery of coal to Coyote Station (anticipated in 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, among other things, that during any period between December 31, 2016 and any subsequent date on which CCMC makes initial delivery of coal, 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 the 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 June 30, 2015 is $35.9 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2015 could be as high as $35.9 million. New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (ASC 606) ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in July 2015, the FASB voted to approve a one year deferral of the effective date. The deferral permits 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. 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. The Company does not plan to adopt the updated standards prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ASU 2015-05 Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40): Customers Accounting for Fees Paid in a Cloud Computing Arrangement ASU 2015-07— Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory,

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 United States of America 97.3 % 95.3 % 96.8 % 96.3 % Mexico 1.2 % 3.2 % 2.2 % 2.7 % Canada 1.3 % 1.4 % 1.0 % 0.9 % All Other Countries (none greater than 0.07%) 0.2 % 0.1 % 0.0 % 0.1 % The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three and six months ended June 30, 2015 and 2014 and total assets by business segment as of June 30, 2015 and December 31, 2014 are presented in the following tables: Operating Revenue Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Electric $ 90,964 $ 92,911 $ 204,511 $ 211,999 Manufacturing 51,273 53,370 108,032 108,805 Plastics 45,954 48,090 78,506 88,573 Intersegment Eliminations (38 ) (7 ) (55 ) (47 ) Total $ 188,153 $ 194,364 $ 390,994 $ 409,330 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 6,083 $ 6,059 $ 12,204 $ 11,138 Manufacturing 846 813 1,678 1,621 Plastics 279 274 525 521 Corporate and Intersegment Eliminations 494 480 1,038 941 Total $ 7,702 $ 7,626 $ 15,445 $ 14,221 Income Taxes Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 1,013 $ (992 ) $ 5,234 $ 4,758 Manufacturing 1,157 1,336 1,661 3,007 Plastics 2,689 2,114 3,953 4,247 Corporate (851 ) (2,374 ) (2,767 ) (3,366 ) Total $ 4,008 $ 84 $ 8,081 $ 8,646 Net Income Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 8,252 $ 5,242 $ 21,430 $ 21,895 Manufacturing 1,912 2,300 3,096 5,196 Plastics 4,265 3,433 6,385 6,893 Corporate (772 ) (3,089 ) (3,473 ) (4,319 ) Discontinued Operations (2,221 ) 2,107 1,933 1,758 Total $ 11,436 $ 9,993 $ 29,371 $ 31,423 Identifiable Assets June 30, December 31, (in thousands) 2015 2014 Electric $ 1,504,369 $ 1,472,647 Manufacturing 137,735 130,701 Plastics 92,700 87,356 Corporate 76,442 51,918 Assets of Discontinued Operations 133 48,657 Total $ 1,811,379 $ 1,791,279

Rate and Regulatory Matters

Rate and Regulatory Matters	6 Months Ended
	Jun. 30, 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) 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 December 2015. OTP’s share of AQCS construction expenditures incurred through June 30, 2015 is $193.4 million, excluding Allowance for Funds Used During Construction (AFUDC). Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project) Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project) The Big Stone South – Brookings MVP and CapX2020 Project The Big Stone South – Ellendale MVP 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 through May 2021 when Hoot Lake Plant is expected to be retired, $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 Minnesota Conservation Improvement Programs (MNCIP) Based on results from the 2014 MNCIP program year, OTP estimated a financial incentive for 2014 of $3.0 million 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 saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge to be effective October 1, 2015. Transmission Cost Recovery Rider Environmental Cost Recovery (ECR) Rider Reagent Costs and Emission Allowances North Dakota General Rates Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances South Dakota 2010 General Rate Case Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances 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 and six month periods ended June 30, 2015 and 2014: Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2015 2014 2015 2014 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 1,610 $ 1,471 $ 3,538 $ 2,992 Transmission Cost Recovery 1,212 1,776 2,827 4,080 Environmental Cost Recovery 2,600 1,703 5,157 3,466 North Dakota Renewable Resource Adjustment 1,942 2,013 3,825 3,448 Transmission Cost Recovery 1,411 1,707 3,347 3,221 Environmental Cost Recovery 2,765 1,452 4,921 2,974 Big Stone II Project Costs -- -- -- 361 South Dakota Transmission Cost Recovery 281 364 644 710 Environmental Cost Recovery 519 -- 1,023 -- 1 FERC Multi-Value Transmission Projects 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 to begin August 17, 2015 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. The FERC issued an order on June 18, 2015 setting the complaint for hearing to begin on February 16, 2016. A FERC decision is not expected until 2017. OTP recorded reductions in revenue of $0.6 million in the first quarter of 2015 and $0.2 million in the second quarter of 2015 and has a $0.8 million liability as of June 30, 2015 representing its 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 Liabiliti

Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 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 June 30, 2015 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,464 $ 97,840 $ 105,304 see below Deferred Marked-to-Market Losses 1 2,098 12,071 14,169 66 months Conservation Improvement Program Costs and Incentives 2 2,550 4,065 6,615 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 -- 5,421 5,421 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 610 2,963 3,573 90 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,153 950 3,103 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 1,642 475 2,117 24 months Debt Reacquisition Premiums 1 351 1,715 2,066 207 months Deferred Income Taxes 1 -- 835 835 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 693 793 95 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 594 -- 594 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 -- 379 379 21 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 174 -- 174 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 -- 68 68 see below Total Regulatory Assets $ 17,736 $ 127,475 $ 145,211 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ -- $ 75,355 $ 75,355 asset lives Refundable Fuel Clause Adjustment Revenues 2,605 -- 2,605 12 months Deferred Income Taxes -- 1,346 1,346 asset lives North Dakota Renewable Resource Rider Accrued Refund 1,333 -- 1,333 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 1,031 1,031 see below Minnesota Environmental Cost Recovery Rider Accrued Refund 391 -- 391 12 months Deferred Marked-to-Market Gains 51 143 194 31 months Deferred Gain on Sale of Utility Property – Minnesota Portion 6 97 103 222 months Big Stone II Over Recovered Project Costs – North Dakota 74 -- 74 6 months South Dakota Environmental Cost Recovery Rider Accrued Refund 40 -- 40 12 months South Dakota Transmission Cost Recovery Rider Accrued Refund 30 -- 30 12 months Total Regulatory Liabilities $ 4,530 $ 77,972 $ 82,502 Net Regulatory Asset Position $ 13,206 $ 49,503 $ 62,709 1 2 December 31, 2014 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,464 $ 101,526 $ 108,990 see below Deferred Marked-to-Market Losses 1 4,492 9,396 13,888 72 months Conservation Improvement Program Costs and Incentives 2 5,843 2,500 8,343 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 -- 5,190 5,190 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 592 3,207 3,799 96 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 943 2,455 3,398 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 2,585 807 3,392 24 months Debt Reacquisition Premiums 1 351 1,890 2,241 213 months Deferred Income Taxes 1 -- 2,086 2,086 asset lives Recoverable Fuel and Purchased Power Costs 1 1,114 -- 1,114 12 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 859 -- 859 12 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 743 843 101 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 706 -- 706 12 months Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 186 -- 186 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 -- 68 68 see below South Dakota Environmental Cost Recovery Rider Accrued Revenues 2 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 1 2 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 All Deferred Marked-to-Market Gains and Losses recorded as of June 30, 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. 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. 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 June 30, 2015. 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 207 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 Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project and Hoot Lake Plant MATS project costs, net of amounts billed under the rider. 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 June 30, 2015. 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 June 30, 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. 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 June 30, 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 June 30, 2015. Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of . 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 June 30, 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 June 30, 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 expense or income item in the period in which the application of guidance under ASC 980 ceases.

Forward Contracts Classified as

Forward Contracts Classified as Derivatives	6 Months Ended
	Jun. 30, 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 June 30, 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 June 30, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to June 30, 2015 and December 31, 2013 to June 30, 2014: (in thousands) June 30, 2015 December 31, 2014 Current Asset – Marked-to-Market Gain $ 194 $ 257 Regulatory Asset – Current Deferred Marked-to-Market Loss 2,098 4,492 Regulatory Asset – Long-Term Deferred Marked-to-Market Loss 12,071 9,396 Total Assets 14,363 14,145 Current Liability – Marked-to-Market Loss (14,169 ) (13,888 ) Regulatory Liability – Current Deferred Marked-to-Market Gain (51 ) -- Regulatory Liability – Long-Term Deferred Marked-to-Market Gain (143 ) (257 ) Total Liabilities (14,363 ) (14,145 ) Net Fair Value of Marked-to-Market Energy Contracts $ -- $ -- (in thousands) Year-to-Date Year-to-Date 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 -- -- Cumulative Fair Value Adjustments Included in Earnings - End of Period $ -- $ -- The following realized and unrealized net losses on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Net Losses on Forward Electric Energy Contracts $ -- $ (9 ) $ -- $ (13 ) 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 June 30, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts. I ndividual 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 June 30, 2015 and December 31, 2014 are indicated in the following table: (in thousands) June 30, 2015 December 31, 2014 Derivative assets subject to legally enforceable netting arrangements $ 194 $ 257 Derivative liabilities subject to legally enforceable netting arrangements (14,388 ) (14,230 ) Net balance subject to legally enforceable netting arrangements $ (14,194 ) $ (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 June 30, 2015 and December 31, 2014: Current Liability – Marked-to-Market Loss (in thousands) June 30 , 2015 December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 219 $ 45 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,169 13,888 Loss Contracts with No Ratings Triggers or Deposit Requirements -- 297 Total Current Liability – Marked-to-Market Loss $ 14,388 $ 14,230 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,169 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (194 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,975 $ 13,631

Reconciliation of Common Shareh

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share	6 Months Ended
	Jun. 30, 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 Balance, December 31, 2014 $ 186,090 $ 278,436 $ 112,903 $ (4,663 ) $ 572,766 Common Stock Issuances, Net of Expenses 1,962 8,673 10,635 Common Stock Retirements (224 ) (1,197 ) (1,421 ) Net Income 29,371 29,371 Other Comprehensive Income 241 241 Tax Benefit – Stock Compensation 28 28 Employee Stock Incentive Plans Expense 1,126 1,126 Common Dividends ($0.615 per share) (23,035 ) (23,035 ) Balance, June 30, 2015 $ 187,828 $ 287,066 $ 119,239 $ (4,422 ) $ 589,711 Shelf Registration On May 11, 2015, the Company filed a shelf registration statement with the U.S. Securities and Exchange Commission (SEC) 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. On May 11, 2015, 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 June 30, 2015: Common Shares Outstanding, December 31, 2014 37,218,053 Issuances: Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 93,855 Cash Invested 43,724 Executive Stock Performance Awards (for 2012 grants) 89,991 At-the-Market Offering 38,160 Directors Deferred Compensation 36,828 Employee Stock Purchase Plan: Cash Invested 19,993 Dividends Reinvested 13,036 Employee Stock Ownership Plan 21,137 Restricted Stock Issued to Directors 15,200 Stock Options Exercised 10,250 Vesting of Restricted Stock Units 10,200 Retirements: Shares Withheld for Individual Income Tax Requirements (44,837 ) Common Shares Outstanding, June 30, 2015 37,565,590 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three and six month periods ended June 30, 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 Three Months ended Six Months ended 2015 2014 2015 2014 Weighted Average Common Shares Outstanding – Basic 37,433,318 36,409,753 37,338,218 36,325,052 Plus: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers 235,900 225,800 235,900 225,800 Nonvested Restricted Shares 51,798 90,110 51,798 90,110 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 75,100 47,650 75,100 47,650 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,676 39,257 3,676 39,257 Potentially Dilutive Stock Options -- 14,400 -- 14,400 Less: Shares Equivalent of Tax Savings from Issuance of Dilutive Shares (146,589 ) (161,954 ) (146,589 ) (161,986 ) Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options -- (12,332 ) -- (12,253 ) Total Dilutive Shares 219,885 242,931 219,885 242,978 Weighted Average Common Shares Outstanding – Diluted 37,653,203 36,652,684 37,558,103 36,568,030 The effect of dilutive shares on earnings per share for the three and six month periods ended June 30, 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 any period.

Share-Based Payments

Share-Based Payments	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Share-Based Payments	7. Share-Based Payments Stock Incentive Awards On February 6, 2015 and April 13, 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 Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted to Executive Officers 84,300 $ 26.99 December 31, 2017 Restricted Stock Units Granted to Executive Officers: Graded Vesting 22,700 $ 31.68 25% per year through February 6, 2019 Cliff Vesting 6,400 $ 31.675 100% on February 6, 2020 On April 13, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors and key employees under the 2014 Stock Incentive Plan: Award Shares/Units Granted Grant-Date Fair Value per Award Vesting Restricted Stock Granted to Nonemployee Directors 15,200 $ 31.775 25% per year through April 8, 2019 Restricted Stock Units Granted to Key Employees 11,900 $ 27.05 100% on April 8, 2019 Under the performance share award agreements the aggregate award for performance at target is 84,300 shares. For target performance the Company’s executive officers would earn an aggregate of 56,200 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2015 through December 31, 2017. The Company’s executive officers would also earn an aggregate of 28,100 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 126,450 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, 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 the target amount 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 restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted stock unit granted to executive officers and of each share of restricted stock granted to nonemployee directors was the average of the high and low market price per share on the dates of grant. The grant date fair value of each restricted stock unit granted to a key employee that is not an executive officer of the Company was based on the market value of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the four-year vesting period. Under the terms of the restricted stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement. As of June 30, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.2 million (before income taxes) which will be amortized over a weighted-average period of 2.7 years. Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Employee Stock Purchase Plan (15% discount) $ 45 $ 45 $ 94 $ 87 Restricted Stock Granted to Directors 106 98 204 221 Restricted Stock Granted to Executive Officers 144 207 301 342 Restricted Stock Units Granted to Nonexecutive Employees 81 28 147 86 Restricted Stock Units Granted to Executive Officers 127 -- 380 -- Stock Performance Awards Granted to Executive Officers 37 518 1,057 1,044 Totals $ 540 $ 896 $ 2,183 $ 1,780

Retained Earnings Restriction

Retained Earnings Restriction	6 Months Ended
	Jun. 30, 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 on 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 June 30, 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 46.9% and 57.3%. OTP’s equity to total capitalization ratio including short-term debt was 52.1% as of June 30, 2015. Total capitalization for OTP cannot currently exceed $1,056,300,000.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 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 June 30, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $94.3 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 June 2015, OTP entered into energy purchase agreements for the purchase of electricity in July of 2015 to make up for reduced generation at Big Stone Plant and Coyote Station. A scheduled maintenance outage at Big Stone Plant was extended through the beginning of August 2015 due to unanticipated turbine repairs. Coyote Station continues to make repairs related to damage caused by a boiler feed pump failure and ensuing fire that occurred in December 2014. The total cost for the replacement power was approximately $4.0 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 June 30, 2015 was 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. The remaining commitment under this contract as of June 30, 2015 was approximately $2.6 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 $2.7 million. OTP recorded reductions in revenue of $0.6 million in the first quarter of 2015 and $0.2 million in the second quarter of 2015 and has a $0.8 million liability as of June 30, 2015 representing its 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 December 19, 2014, the EPA announced a rule regulating coal combustion residuals (CCR) as a non-hazardous solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA). The rule was published on April 17, 2015, which triggered a 90-day period within which petitions for judicial review could be filed. Before the challenge period expired on July 16, 2015, several parties filed petitions for judicial review in the United States Court of Appeals for the District of Columbia Circuit. The United States House of Representatives also passed a bill on July 22, 2015, to delay the effective date of certain portions of the CCR rule (the regulation of CCR under Subtitle D of RCRA). The bill would also eliminate some portions of the CCR rule, such as restrictions on how close existing CCR containment sites may be to the uppermost aquifer. The bill would also authorize states to enforce CCR standards, using the federal rule as minimum standards. Finally, the bill would prohibit the EPA from regulating CCR as a hazardous waste under Subtitle C of RCRA. The United States Senate is considering a similar bill. The Obama Administration has threatened to veto legislation designed to alter the CCR rule. The outcome of these judicial challenges and legislative actions cannot be predicted. Thus, uncertainty regarding the status of the CCR rule is likely to continue for a period of time. The CCR 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. Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. In the second quarter of 2015, subsequent to the publishing of the CCR rule, OTP completed an assessment of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it has no immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but is likely to discontinue the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally, OTP has identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the costs to reclaim the area have always been included in Big Stone Plant’s estimated removal costs currently being recovered as a component of depreciation expense. Therefore, the establishment of the ARO will have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when incurred, will be charged against, and reduce, the accumulated ARO liability. Other The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of June 30, 2015 will not be material.

Short-Term and Long-Term Borrow

Short-Term and Long-Term Borrowings	6 Months Ended
	Jun. 30, 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 June 30, 2015 and December 31, 2014: (in thousands) Line Limit In Use on June 30, 2015 Restricted due to Outstanding Letters of Credit Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ 38,494 $ 150 $ 111,356 $ 138,872 OTP Credit Agreement 170,000 4,546 310 165,144 169,440 Total $ 320,000 $ 43,040 $ 460 $ 276,500 $ 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 June 30, 2015 and December 31, 2014: June 30, 2015 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 4,546 $ 38,494 $ 43,040 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 -- 219 219 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 -- 1,042 1,042 Total $ 445,000 $ 53,591 $ 498,591 Less: Current Maturities -- 207 207 Total Long-Term Debt $ 445,000 $ 53,384 $ 498,384 Total Short-Term and Long-Term Debt (with current maturities) $ 449,546 $ 92,085 $ 541,631 December 31, 2014 (in thousands) OTP Otter Tail Otter Tail 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, 2.54%, due March 18, 2021 -- 1,105 1,105 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 Postreti

Pension Plan and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Pension Plan and Other Postretirement Benefits	11. Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 1,530 $ 1,174 $ 3,030 $ 2,349 Interest Cost on Projected Benefit Obligation 3,347 3,285 6,672 6,570 Expected Return on Assets (4,592 ) (4,186 ) (9,192 ) (8,373 ) Amortization of Prior-Service Cost: From Regulatory Asset 47 65 94 129 From Other Comprehensive Income 1 1 1 2 3 Amortization of Net Actuarial Loss: From Regulatory Asset 1,705 868 3,338 1,736 From Other Comprehensive Income 1 46 23 86 46 Net Periodic Pension Cost $ 2,084 $ 1,230 $ 4,030 $ 2,460 1 Corporate cost included in Other Nonelectric Expenses. Cash flows Executive Survivor and Supplemental Retirement Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 47 $ 12 $ 94 $ 25 Interest Cost on Projected Benefit Obligation 381 380 762 760 Amortization of Prior-Service Cost: From Regulatory Asset 4 6 8 11 From Other Comprehensive Income 1 9 13 19 26 Amortization of Net Actuarial Loss: From Regulatory Asset 84 36 167 71 From Other Comprehensive Income 2 150 11 301 23 Net Periodic Pension Cost $ 675 $ 458 $ 1,351 $ 916 1 Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 5 $ 8 $ 10 Other Nonelectric Expenses 5 8 11 16 2 Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 77 $ 33 $ 155 $ 66 Other Nonelectric Expenses 73 (22 ) 146 (43 ) Postretirement Benefits Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 273 $ 213 $ 648 $ 528 Interest Cost on Projected Benefit Obligation 499 542 1,049 1,100 Amortization of Prior-Service Cost: From Regulatory Asset 51 51 102 102 From Other Comprehensive Income 1 2 2 3 3 Amortization of Net Actuarial Loss: From Regulatory Asset (48 ) -- -- -- From Other Comprehensive Income 1 (1 ) -- -- -- Net Periodic Postretirement Benefit Cost $ 776 $ 808 $ 1,802 $ 1,733 Effect of Medicare Part D Subsidy $ (293 ) $ (166 ) $ (743 ) $ (474 ) 1

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 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: Short-Term Debt Long-Term Debt including Current Maturities June 30, 2015 December 31, 2014 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt $ (43,040 ) $ (43,040 ) $ (10,854 ) $ (10,854 ) Long-Term Debt including Current Maturities (498,591 ) (554,434 ) (498,690 ) (600,828 )

Income Tax Expense Continuing O

Income Tax Expense Continuing Operations	6 Months Ended
	Jun. 30, 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 and six month periods ended June 30, 2015 and 2014: Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Income Before Income Taxes – Continuing Operations $ 17,665 $ 7,970 $ 35,519 $ 38,311 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 6,889 3,108 13,852 14,941 Increases (Decreases) in Tax from: Federal Production Tax Credits (PTCs) (1,656 ) (1,864 ) (3,710 ) (4,116 ) Section 199 Domestic Production Activities Deduction (363 ) (349 ) (725 ) (707 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (213 ) (212 ) (425 ) (425 ) Employee Stock Ownership Plan Dividend Deduction (171 ) (189 ) (343 ) (379 ) Investment Tax Credits (143 ) (127 ) (286 ) (254 ) AFUDC Equity (125 ) (164 ) (225 ) (297 ) Other Items – Net (210 ) (119 ) (57 ) (117 ) Income Tax Expense – Continuing Operations $ 4,008 $ 84 $ 8,081 $ 8,646 Effective Income Tax Rate – Continuing Operations 22.7 % 1.1 % 22.8 % 22.6 % 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 86 -- Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 308 $ 4,376 The balance of unrecognized tax benefits as of June 30, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 30, 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 June 30, 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 June 30, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2012 for federal income taxes and for tax years prior to 2011 for Minnesota and North Dakota state income taxes.

Discontinued Operations

Discontinued Operations	6 Months Ended
	Jun. 30, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	16. Discontinued Operations 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 an estimated $5.7 million adjustment for working capital and other related items, which is expected to be finalized within 120 days of the April 30, 2015 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 the sale will not be known until the adjustments for working capital and other related items have been determined. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets, which are expected to be finalized before the end of the third quarter of 2015. The Company recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. For the Three Months Ended For the Six Months Ended (in thousands) 2015 2014 2015 2014 Operating Revenues $ 5,899 $ 40,247 $ 24,623 $ 65,753 Operating Expenses 9,209 36,751 31,350 63,119 Goodwill Impairment Charge -- -- 1,000 -- Operating (Loss) Income (3,310 ) 3,496 (7,727 ) 2,634 Interest Charges -- 1 -- 1 Other (Deductions) Income (11 ) 14 (42 ) 302 Income Tax (Benefit) Expense (1,329 ) 1,402 (2,705 ) 1,177 Net (Loss) Income from Operations (1,992 ) 2,107 (5,064 ) 1,758 (Loss) Gain on Disposition Before Taxes (509 ) -- 11,533 -- Income Tax (Benefit) Expense on Disposition (280 ) -- 4,536 -- Net (Loss) Gain on Disposition (229 ) -- 6,997 -- Net Income (Loss) $ (2,221 ) $ 2,107 $ 1,933 $ 1,758 The above results for the three months ended June 30, 2015 include net losses from operations of $1.5 million from Foley and $0.5 million from the Company’s former waterfront equipment manufacturer related to a settlement of a warranty claim. Included in net income from operations for the three months ended June 30, 2014 are $1.1 million from Foley and $1.0 million from AEV, Inc. The above results for the six months ended June 30, 2015 include net losses from operations of $3.9 million from Foley, $0.8 million from AEV, Inc. and $0.5 million from the Company’s former waterfront equipment manufacturer related to the settlement of a warranty claim in the second quarter of 2015 and net income of $0.1 million from the Company’s former wind tower manufacturer related to a reduction in warranty reserves for expired warranties. The above results for the six months ended June 30, 2014 include net income from operations of $1.2 million from Foley and 0.5 million from AEV, Inc. Foley and AEV, Inc. 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. Following are summary presentations of the major components of assets and liabilities of discontinued operations as of June 30, 2015 and December 31, 2014: (in thousands) June 30, December 31, Current Assets $ 133 $ 35,174 Goodwill and Intangibles -- 2,814 Net Plant -- 10,669 Assets of Discontinued Operations $ 133 $ 48,657 Current Liabilities $ 3,260 $ 22,864 Deferred Income Taxes -- 4,695 Liabilities of Discontinued Operations $ 3,260 $ 27,559 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 (115 ) (5 ) Decrease in Warranty Estimates for Prior Years -- (133 ) Warranty Reserve Balance, June 30 $ 2,412 $ 2,949 The warranty reserve balances as of June 30, 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.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 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. Provisions for sales returns 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 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 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 June 30, 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 , 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 June 30, 2015 and December 31, 2014: June 30, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Forward Energy Contracts $ -- $ -- $ 194 Investments: Money Market Deposit Escrow Account – AEV, Inc. and Foley Company Sales 2,500 Corporate Debt Securities – Held by Captive Insurance Company 6,679 U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,221 Other Assets: Money Market and Mutual Funds - Nonqualified Retirement Savings Plan 273 Total Assets $ 2,773 $ 7,900 $ 194 Liabilities: Derivative Liabilities - Forward Gasoline Purchase Contracts $ -- $ 219 $ -- Derivative Liabilities - Forward Energy Contracts 14,169 Total Liabilities $ -- $ 219 $ 14,169 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 Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company 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 June 30, 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 June 30, 2015 Level 3 forward electric basis spreads ranged from $3.17 to $7.00 per megawatt-hour under the active trading hub price. The weighted average price was $32.71 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 June 30, 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 or six month periods ended June 30, 2015 and 2014. The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the six month periods ended June 30, 2015 and 2014: Six Months Ended June 30, (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 4,302 1,161 Net Changes in Fair Value of Contracts Entered into in Prior Periods (3,732 ) 7,400 Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period (13,061 ) (2,780 ) Net Loss Recognized as Regulatory Assets on Contracts Entered into in Period (914 ) -- Forward Energy Contracts - Net Derivative Liability Fair Values End of Period $ (13,975 ) $ (2,780 )
Inventories	Inventories Inventories consist of the following: June 30, December 31, (in thousands) 2015 2014 Finished Goods $ 23,276 $ 27,998 Work in Process 10,877 10,628 Raw Material, Fuel and Supplies 47,650 46,577 Total Inventories $ 81,803 $ 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 in excess of their respective book values and not impaired. The following table summarizes goodwill by business segment indicating no changes to the carrying amounts in the first six months of 2015: (in thousands) Gross Balance Accumulated Impairments Balance (net of impairments) Adjustments to Goodwill in 2015 Balance (net of impairments) 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 June 30, 2015 (in thousands) Gross Carrying Accumulated Net Carrying Amount Remaining Amortizable Intangible Assets: Customer Relationships $ 16,811 $ 6,208 $ 10,603 54-154 months Other Intangible Assets Including Contracts 639 479 160 15 months Emission Allowances 100 NA 100 Expensed as used Total $ 17,550 $ 6,687 $ 10,863 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 Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Amortization Expense – Intangible Assets $ 244 $ 244 $ 488 $ 488 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 six month period ended June 30, 2015: Six Months Ended (in thousands) June 30, 2015 Emission Allowances Beginning Balance $ -- Allowances Purchased 168 Allowances Used (68 ) Emission Allowances Ending Balance $ 100
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2015 2014 Noncash Investing Activities: Accounts Payable Outstanding Related to Capital Additions 1 $ 31,455 $ 21,992 Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions 2 $ 4,188 $ 4,373 1 2
Coyote Station Lignite Supply Agreement - Variable Interest Entity	Coyote Station Lignite Supply Agreement – Variable Interest Entity 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 initial delivery of coal to Coyote Station (anticipated in 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, among other things, that during any period between December 31, 2016 and any subsequent date on which CCMC makes initial delivery of coal, 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 the 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 June 30, 2015 is $35.9 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2015 could be as high as $35.9 million.
New Accounting Standards	New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (ASC 606) ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in July 2015, the FASB voted to approve a one year deferral of the effective date. The deferral permits 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. 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. The Company does not plan to adopt the updated standards prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ASU 2015-05 Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40): Customers Accounting for Fees Paid in a Cloud Computing Arrangement ASU 2015-07— Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory,

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Schedule of assets and liabilities that are measured at fair value on a recurring basis	June 30, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Forward Energy Contracts $ -- $ -- $ 194 Investments: Money Market Deposit Escrow Account – AEV, Inc. and Foley Company Sales 2,500 Corporate Debt Securities – Held by Captive Insurance Company 6,679 U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,221 Other Assets: Money Market and Mutual Funds - Nonqualified Retirement Savings Plan 273 Total Assets $ 2,773 $ 7,900 $ 194 Liabilities: Derivative Liabilities - Forward Gasoline Purchase Contracts $ -- $ 219 $ -- Derivative Liabilities - Forward Energy Contracts 14,169 Total Liabilities $ -- $ 219 $ 14,169 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	Six Months Ended June 30, (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 4,302 1,161 Net Changes in Fair Value of Contracts Entered into in Prior Periods (3,732 ) 7,400 Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period (13,061 ) (2,780 ) Net Loss Recognized as Regulatory Assets on Contracts Entered into in Period (914 ) -- Forward Energy Contracts - Net Derivative Liability Fair Values End of Period $ (13,975 ) $ (2,780 )
Schedule of inventories	June 30, December 31, (in thousands) 2015 2014 Finished Goods $ 23,276 $ 27,998 Work in Process 10,877 10,628 Raw Material, Fuel and Supplies 47,650 46,577 Total Inventories $ 81,803 $ 85,203
Schedule of changes to goodwill by business segment	(in thousands) Gross Balance Accumulated Impairments Balance (net of impairments) Adjustments to Goodwill in 2015 Balance (net of impairments) 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	Gross Carrying Accumulated Net Carrying Amount Remaining Amortizable Intangible Assets: Customer Relationships $ 16,811 $ 6,208 $ 10,603 54-154 months Other Intangible Assets Including Contracts 639 479 160 15 months Emission Allowances 100 NA 100 Expensed as used Total $ 17,550 $ 6,687 $ 10,863 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	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Amortization Expense – Intangible Assets $ 244 $ 244 $ 488 $ 488
Schedule of estimated annual amortization expense for intangible assets	(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	Six Months Ended (in thousands) June 30, 2015 Emission Allowances Beginning Balance $ -- Allowances Purchased 168 Allowances Used (68 ) Emission Allowances Ending Balance $ 100
Schedule of supplemental disclosure of cash flow information	As of June 30, (in thousands) 2015 2014 Noncash Investing Activities: Accounts Payable Outstanding Related to Capital Additions 1 $ 31,455 $ 21,992 Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions 2 $ 4,188 $ 4,373 1 2

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Schedule of percent of consolidated sales revenue by country	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 United States of America 97.3 % 95.3 % 96.8 % 96.3 % Mexico 1.2 % 3.2 % 2.2 % 2.7 % Canada 1.3 % 1.4 % 1.0 % 0.9 % All Other Countries (none greater than 0.07%) 0.2 % 0.1 % 0.0 % 0.1 %
Schedule of information by business segments	Operating Revenue Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Electric $ 90,964 $ 92,911 $ 204,511 $ 211,999 Manufacturing 51,273 53,370 108,032 108,805 Plastics 45,954 48,090 78,506 88,573 Intersegment Eliminations (38 ) (7 ) (55 ) (47 ) Total $ 188,153 $ 194,364 $ 390,994 $ 409,330 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 6,083 $ 6,059 $ 12,204 $ 11,138 Manufacturing 846 813 1,678 1,621 Plastics 279 274 525 521 Corporate and Intersegment Eliminations 494 480 1,038 941 Total $ 7,702 $ 7,626 $ 15,445 $ 14,221 Income Taxes Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 1,013 $ (992 ) $ 5,234 $ 4,758 Manufacturing 1,157 1,336 1,661 3,007 Plastics 2,689 2,114 3,953 4,247 Corporate (851 ) (2,374 ) (2,767 ) (3,366 ) Total $ 4,008 $ 84 $ 8,081 $ 8,646 Net Income Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Electric $ 8,252 $ 5,242 $ 21,430 $ 21,895 Manufacturing 1,912 2,300 3,096 5,196 Plastics 4,265 3,433 6,385 6,893 Corporate (772 ) (3,089 ) (3,473 ) (4,319 ) Discontinued Operations (2,221 ) 2,107 1,933 1,758 Total $ 11,436 $ 9,993 $ 29,371 $ 31,423 Identifiable Assets June 30, December 31, (in thousands) 2015 2014 Electric $ 1,504,369 $ 1,472,647 Manufacturing 137,735 130,701 Plastics 92,700 87,356 Corporate 76,442 51,918 Assets of Discontinued Operations 133 48,657 Total $ 1,811,379 $ 1,791,279

Rate and Regulatory Matters (Ta

Rate and Regulatory Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Rate and Regulatory Matters [Abstract]
Schedule of revenues recorded under rate riders	Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2015 2014 2015 2014 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 1,610 $ 1,471 $ 3,538 $ 2,992 Transmission Cost Recovery 1,212 1,776 2,827 4,080 Environmental Cost Recovery 2,600 1,703 5,157 3,466 North Dakota Renewable Resource Adjustment 1,942 2,013 3,825 3,448 Transmission Cost Recovery 1,411 1,707 3,347 3,221 Environmental Cost Recovery 2,765 1,452 4,921 2,974 Big Stone II Project Costs -- -- -- 361 South Dakota Transmission Cost Recovery 281 364 644 710 Environmental Cost Recovery 519 -- 1,023 -- 1

Regulatory Assets and Liabili26

Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of amount of regulatory assets and liabilities	June 30, 2015 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,464 $ 97,840 $ 105,304 see below Deferred Marked-to-Market Losses 1 2,098 12,071 14,169 66 months Conservation Improvement Program Costs and Incentives 2 2,550 4,065 6,615 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 -- 5,421 5,421 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 610 2,963 3,573 90 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,153 950 3,103 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 1,642 475 2,117 24 months Debt Reacquisition Premiums 1 351 1,715 2,066 207 months Deferred Income Taxes 1 -- 835 835 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 693 793 95 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 594 -- 594 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 -- 379 379 21 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 174 -- 174 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 -- 68 68 see below Total Regulatory Assets $ 17,736 $ 127,475 $ 145,211 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ -- $ 75,355 $ 75,355 asset lives Refundable Fuel Clause Adjustment Revenues 2,605 -- 2,605 12 months Deferred Income Taxes -- 1,346 1,346 asset lives North Dakota Renewable Resource Rider Accrued Refund 1,333 -- 1,333 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 1,031 1,031 see below Minnesota Environmental Cost Recovery Rider Accrued Refund 391 -- 391 12 months Deferred Marked-to-Market Gains 51 143 194 31 months Deferred Gain on Sale of Utility Property – Minnesota Portion 6 97 103 222 months Big Stone II Over Recovered Project Costs – North Dakota 74 -- 74 6 months South Dakota Environmental Cost Recovery Rider Accrued Refund 40 -- 40 12 months South Dakota Transmission Cost Recovery Rider Accrued Refund 30 -- 30 12 months Total Regulatory Liabilities $ 4,530 $ 77,972 $ 82,502 Net Regulatory Asset Position $ 13,206 $ 49,503 $ 62,709 1 2 December 31, 2014 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,464 $ 101,526 $ 108,990 see below Deferred Marked-to-Market Losses 1 4,492 9,396 13,888 72 months Conservation Improvement Program Costs and Incentives 2 5,843 2,500 8,343 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 -- 5,190 5,190 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 592 3,207 3,799 96 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 943 2,455 3,398 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 2,585 807 3,392 24 months Debt Reacquisition Premiums 1 351 1,890 2,241 213 months Deferred Income Taxes 1 -- 2,086 2,086 asset lives Recoverable Fuel and Purchased Power Costs 1 1,114 -- 1,114 12 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 859 -- 859 12 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 743 843 101 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 706 -- 706 12 months Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 186 -- 186 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 -- 68 68 see below South Dakota Environmental Cost Recovery Rider Accrued Revenues 2 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 1 2

Forward Contracts Classified 27

Forward Contracts Classified as Derivatives (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule for effect of marking to market OTP's forward contracts for the purchase of electricity and its location	(in thousands) June 30, 2015 December 31, 2014 Current Asset – Marked-to-Market Gain $ 194 $ 257 Regulatory Asset – Current Deferred Marked-to-Market Loss 2,098 4,492 Regulatory Asset – Long-Term Deferred Marked-to-Market Loss 12,071 9,396 Total Assets 14,363 14,145 Current Liability – Marked-to-Market Loss (14,169 ) (13,888 ) Regulatory Liability – Current Deferred Marked-to-Market Gain (51 ) -- Regulatory Liability – Long-Term Deferred Marked-to-Market Gain (143 ) (257 ) Total Liabilities (14,363 ) (14,145 ) Net Fair Value of Marked-to-Market Energy Contracts $ -- $ --
Schedule for cumulative fair value adjustments of derivatives included in earnings	(in thousands) Year-to-Date Year-to-Date 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 -- -- Cumulative Fair Value Adjustments Included in Earnings - End of Period $ -- $ --
Schedule of realized and unrealized net loss on forward energy contracts	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2015 2014 2015 2014 Net Losses on Forward Electric Energy Contracts $ -- $ (9 ) $ -- $ (13 )
Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements	(in thousands) June 30, 2015 December 31, 2014 Derivative assets subject to legally enforceable netting arrangements $ 194 $ 257 Derivative liabilities subject to legally enforceable netting arrangements (14,388 ) (14,230 ) Net balance subject to legally enforceable netting arrangements $ (14,194 ) $ (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) June 30 , 2015 December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 219 $ 45 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,169 13,888 Loss Contracts with No Ratings Triggers or Deposit Requirements -- 297 Total Current Liability – Marked-to-Market Loss $ 14,388 $ 14,230 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,169 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (194 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,975 $ 13,631

Reconciliation of Common Shar28

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Schedule of reconciliation of common shareholders' equity	(in thousands) Par Value, Premium Retained Accumulated Total Balance, December 31, 2014 $ 186,090 $ 278,436 $ 112,903 $ (4,663 ) $ 572,766 Common Stock Issuances, Net of Expenses 1,962 8,673 10,635 Common Stock Retirements (224 ) (1,197 ) (1,421 ) Net Income 29,371 29,371 Other Comprehensive Income 241 241 Tax Benefit – Stock Compensation 28 28 Employee Stock Incentive Plans Expense 1,126 1,126 Common Dividends ($0.615 per share) (23,035 ) (23,035 ) Balance, June 30, 2015 $ 187,828 $ 287,066 $ 119,239 $ (4,422 ) $ 589,711
Schedule of common shares outstanding from December 31, 2014 through March 31, 2015	Common Shares Outstanding, December 31, 2014 37,218,053 Issuances: Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 93,855 Cash Invested 43,724 Executive Stock Performance Awards (for 2012 grants) 89,991 At-the-Market Offering 38,160 Directors Deferred Compensation 36,828 Employee Stock Purchase Plan: Cash Invested 19,993 Dividends Reinvested 13,036 Employee Stock Ownership Plan 21,137 Restricted Stock Issued to Directors 15,200 Stock Options Exercised 10,250 Vesting of Restricted Stock Units 10,200 Retirements: Shares Withheld for Individual Income Tax Requirements (44,837 ) Common Shares Outstanding, June 30, 2015 37,565,590
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted	Three Months ended Six Months ended 2015 2014 2015 2014 Weighted Average Common Shares Outstanding – Basic 37,433,318 36,409,753 37,338,218 36,325,052 Plus: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers 235,900 225,800 235,900 225,800 Nonvested Restricted Shares 51,798 90,110 51,798 90,110 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 75,100 47,650 75,100 47,650 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,676 39,257 3,676 39,257 Potentially Dilutive Stock Options -- 14,400 -- 14,400 Less: Shares Equivalent of Tax Savings from Issuance of Dilutive Shares (146,589 ) (161,954 ) (146,589 ) (161,986 ) Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options -- (12,332 ) -- (12,253 ) Total Dilutive Shares 219,885 242,931 219,885 242,978 Weighted Average Common Shares Outstanding – Diluted 37,653,203 36,652,684 37,558,103 36,568,030

Share-Based Payments (Tables)

Share-Based Payments (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Schedule of stock incentive awards granted	On February 6, 2015 and April 13, 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 Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted to Executive Officers 84,300 $ 26.99 December 31, 2017 Restricted Stock Units Granted to Executive Officers: Graded Vesting 22,700 $ 31.68 25% per year through February 6, 2019 Cliff Vesting 6,400 $ 31.675 100% on February 6, 2020 On April 13, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors and key employees under the 2014 Stock Incentive Plan: Award Shares/Units Granted Grant-Date Fair Value per Award Vesting Restricted Stock Granted to Nonemployee Directors 15,200 $ 31.775 25% per year through April 8, 2019 Restricted Stock Units Granted to Key Employees 11,900 $ 27.05 100% on April 8, 2019
Schedule of compensation expense under stock-based payment programs	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Employee Stock Purchase Plan (15% discount) $ 45 $ 45 $ 94 $ 87 Restricted Stock Granted to Directors 106 98 204 221 Restricted Stock Granted to Executive Officers 144 207 301 342 Restricted Stock Units Granted to Nonexecutive Employees 81 28 147 86 Restricted Stock Units Granted to Executive Officers 127 -- 380 -- Stock Performance Awards Granted to Executive Officers 37 518 1,057 1,044 Totals $ 540 $ 896 $ 2,183 $ 1,780

Short-Term and Long-Term Borr30

Short-Term and Long-Term Borrowings (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of lines of credit	(in thousands) Line Limit In Use on June 30, 2015 Restricted due to Outstanding Letters of Credit Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ 38,494 $ 150 $ 111,356 $ 138,872 OTP Credit Agreement 170,000 4,546 310 165,144 169,440 Total $ 320,000 $ 43,040 $ 460 $ 276,500 $ 308,312
Schedule of short-term and long-term debt outstanding	June 30, 2015 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 4,546 $ 38,494 $ 43,040 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 -- 219 219 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 -- 1,042 1,042 Total $ 445,000 $ 53,591 $ 498,591 Less: Current Maturities -- 207 207 Total Long-Term Debt $ 445,000 $ 53,384 $ 498,384 Total Short-Term and Long-Term Debt (with current maturities) $ 449,546 $ 92,085 $ 541,631 December 31, 2014 (in thousands) OTP Otter Tail Otter Tail 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, 2.54%, due March 18, 2021 -- 1,105 1,105 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 Postre31

Pension Plan and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2015
Pension Plan
Schedule of components of net periodic postretirement benefit cost	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 1,530 $ 1,174 $ 3,030 $ 2,349 Interest Cost on Projected Benefit Obligation 3,347 3,285 6,672 6,570 Expected Return on Assets (4,592 ) (4,186 ) (9,192 ) (8,373 ) Amortization of Prior-Service Cost: From Regulatory Asset 47 65 94 129 From Other Comprehensive Income 1 1 1 2 3 Amortization of Net Actuarial Loss: From Regulatory Asset 1,705 868 3,338 1,736 From Other Comprehensive Income 1 46 23 86 46 Net Periodic Pension Cost $ 2,084 $ 1,230 $ 4,030 $ 2,460 1 Corporate cost included in Other Nonelectric Expenses.
Executive Survivor and Supplemental Retirement Plan
Schedule of components of net periodic postretirement benefit cost	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 47 $ 12 $ 94 $ 25 Interest Cost on Projected Benefit Obligation 381 380 762 760 Amortization of Prior-Service Cost: From Regulatory Asset 4 6 8 11 From Other Comprehensive Income 1 9 13 19 26 Amortization of Net Actuarial Loss: From Regulatory Asset 84 36 167 71 From Other Comprehensive Income 2 150 11 301 23 Net Periodic Pension Cost $ 675 $ 458 $ 1,351 $ 916 1 Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 5 $ 8 $ 10 Other Nonelectric Expenses 5 8 11 16 2 Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 77 $ 33 $ 155 $ 66 Other Nonelectric Expenses 73 (22 ) 146 (43 )
Postretirement Benefits
Schedule of components of net periodic postretirement benefit cost	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2015 2014 2015 2014 Service Cost—Benefit Earned During the Period $ 273 $ 213 $ 648 $ 528 Interest Cost on Projected Benefit Obligation 499 542 1,049 1,100 Amortization of Prior-Service Cost: From Regulatory Asset 51 51 102 102 From Other Comprehensive Income 1 2 2 3 3 Amortization of Net Actuarial Loss: From Regulatory Asset (48 ) -- -- -- From Other Comprehensive Income 1 (1 ) -- -- -- Net Periodic Postretirement Benefit Cost $ 776 $ 808 $ 1,802 $ 1,733 Effect of Medicare Part D Subsidy $ (293 ) $ (166 ) $ (743 ) $ (474 ) 1

Fair Value of Financial Instr32

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of long-term debt including current maturities	June 30, 2015 December 31, 2014 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt $ (43,040 ) $ (43,040 ) $ (10,854 ) $ (10,854 ) Long-Term Debt including Current Maturities (498,591 ) (554,434 ) (498,690 ) (600,828 )

Income Tax Expense - Continuing

Income Tax Expense - Continuing Operations (Tables)	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Schedule of income from continuing operations before income taxes and income tax expense	Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Income Before Income Taxes – Continuing Operations $ 17,665 $ 7,970 $ 35,519 $ 38,311 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 6,889 3,108 13,852 14,941 Increases (Decreases) in Tax from: Federal Production Tax Credits (PTCs) (1,656 ) (1,864 ) (3,710 ) (4,116 ) Section 199 Domestic Production Activities Deduction (363 ) (349 ) (725 ) (707 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (213 ) (212 ) (425 ) (425 ) Employee Stock Ownership Plan Dividend Deduction (171 ) (189 ) (343 ) (379 ) Investment Tax Credits (143 ) (127 ) (286 ) (254 ) AFUDC Equity (125 ) (164 ) (225 ) (297 ) Other Items – Net (210 ) (119 ) (57 ) (117 ) Income Tax Expense – Continuing Operations $ 4,008 $ 84 $ 8,081 $ 8,646 Effective Income Tax Rate – Continuing Operations 22.7 % 1.1 % 22.8 % 22.6 %
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 86 -- Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 308 $ 4,376

Discontinued Operations (Tables

Discontinued Operations (Tables)	6 Months Ended
	Jun. 30, 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	The following summary presentations of the results of discontinued operations for the three and six month periods ended June 30, 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 For the Six Months Ended (in thousands) 2015 2014 2015 2014 Operating Revenues $ 5,899 $ 40,247 $ 24,623 $ 65,753 Operating Expenses 9,209 36,751 31,350 63,119 Goodwill Impairment Charge -- -- 1,000 -- Operating (Loss) Income (3,310 ) 3,496 (7,727 ) 2,634 Interest Charges -- 1 -- 1 Other (Deductions) Income (11 ) 14 (42 ) 302 Income Tax (Benefit) Expense (1,329 ) 1,402 (2,705 ) 1,177 Net (Loss) Income from Operations (1,992 ) 2,107 (5,064 ) 1,758 (Loss) Gain on Disposition Before Taxes (509 ) -- 11,533 -- Income Tax (Benefit) Expense on Disposition (280 ) -- 4,536 -- Net (Loss) Gain on Disposition (229 ) -- 6,997 -- Net Income (Loss) $ (2,221 ) $ 2,107 $ 1,933 $ 1,758 Following are summary presentations of the major components of assets and liabilities of discontinued operations as of June 30, 2015 and December 31, 2014: (in thousands) June 30, December 31, Current Assets $ 133 $ 35,174 Goodwill and Intangibles -- 2,814 Net Plant -- 10,669 Assets of Discontinued Operations $ 133 $ 48,657 Current Liabilities $ 3,260 $ 22,864 Deferred Income Taxes -- 4,695 Liabilities of Discontinued Operations $ 3,260 $ 27,559
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 (115 ) (5 ) Decrease in Warranty Estimates for Prior Years -- (133 ) Warranty Reserve Balance, June 30 $ 2,412 $ 2,949

Summary of Significant Accoun35

Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Level 1
Assets:
Total Assets	$ 2,773	$ 713
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Total Assets
Liabilities:
Derivative Liabilities
Level 1 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. and Foley Company Sales	$ 2,500
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	$ 273	593
Level 2
Assets:
Total Assets	7,900	8,014
Liabilities:
Total Liabilities	$ 219	$ 342
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets
Total Assets
Level 2 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. and Foley Company Sales
Level 2 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities	$ 219	$ 342
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	6,679	6,761
Level 2 | U.S. Government-Sponsored Enterprises' Debt Securities
Assets:
Investments - Held by Captive Insurance Company	1,221	1,253
Level 3
Assets:
Total Assets	194	257
Liabilities:
Total Liabilities	14,169	13,888
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	194	257
Liabilities:
Derivative Liabilities	$ 14,169	$ 13,888
Level 3 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. and Foley Company Sales
Level 3 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities

Summary of Significant Accoun36

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 ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
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	4,302	1,161
Net Changes in Fair Value of Contracts Entered into in Prior Periods	(3,732)	7,400
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	(13,061)	$ (2,780)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period	(914)
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$ (13,975)	$ (2,780)

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Inventories (Details 2) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Finished Goods	$ 23,276	$ 27,998
Work in Process	10,877	10,628
Raw Material, Fuel and Supplies	47,650	46,577
Total Inventories	$ 81,803	$ 85,203

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 3) - Jun. 30, 2015 - USD ($) $ in Thousands	Total
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) June 30, 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) June 30, 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) June 30, 2015	$ 19,302

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Components of intangible assets (Details 4) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Amortizable Intangible Assets:
Gross Carrying Amount	$ 17,550	$ 17,450
Accumulated Amortization	6,687	6,199
Net Carrying Amount	10,863	11,251
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	6,208	5,784
Net Carrying Amount	$ 10,603	$ 11,027
Customer Relationships | Minimum
Amortizable Intangible Assets:
Remaining Amortization Periods	54 months	60 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Remaining Amortization Periods	154 months	160 months
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Gross Carrying Amount	$ 639	$ 639
Accumulated Amortization	479	415
Net Carrying Amount	$ 160	$ 224
Remaining Amortization Periods	15 months	21 months
Emission Allowances
Amortizable Intangible Assets:
Gross Carrying Amount	$ 100
Net Carrying Amount	$ 100

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 5) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 244	$ 244	$ 488	$ 488

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 6) $ in Thousands	Jun. 30, 2015USD ($)
Accounting Policies [Abstract]
2,015	$ 977
2,016	945
2,017	849
2,018	849
2,019	$ 849

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Reconciliation of OTP's emission allowances (Details 7) $ in Thousands	6 Months Ended
	Jun. 30, 2015USD ($)
Intangible Assets [Line Items]
Emission Allowances Beginning Balance	$ 11,251
Emission Allowances Ending Balance	10,863
Emission Allowances
Intangible Assets [Line Items]
Allowances Purchased	168
Allowances Used	(68)
Emission Allowances Ending Balance	$ 100

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 8) - USD ($) $ in Thousands		Jun. 30, 2015	Jun. 30, 2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	[1]	$ 31,455	$ 21,992
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	[2]	$ 4,188	$ 4,373
[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.

Summary of Significant Accoun44

Summary of Significant Accounting Policies (Detail Textuals) - Jun. 30, 2015 $ in Thousands	USD ($)$ / MWh
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	3.17
Electric inputs maximum deviation below active trading hub price per megawatt-hour	7
Electric inputs weighted average price per megawatt-hour	32.71
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

Summary of Significant Accoun45

Summary of Significant Accounting Policies (Detail Textuals 1) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Significant Accounting Policies [Line Items]
Reductions in long term assets and debt	$ 2.4
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	$ 35.9
Maximum exposure to loss as a result of involvement with CCMC	$ 35.9

Segment Information - Percent o

Segment Information - Percent of sales revenue by country (Details) - Sales	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	97.30%	95.30%	96.80%	96.30%
Mexico
Segment Reporting Information [Line Items]
Percentage of sales revenue	1.20%	3.20%	2.20%	2.70%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	1.30%	1.40%	1.00%	0.90%
All Other Countries (none greater than 0.07%)
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.20%	0.10%	0.00%	0.10%

Segment Information - Informati

Segment Information - Information on continuing operations for business segments (Details 1) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Operating Revenue	$ 188,153	$ 194,364	$ 390,994	$ 409,330
Interest Charges	7,702	7,626	15,445	14,221
Income Taxes	4,008	84	8,081	8,646
Net Income	11,436	9,993	29,371	31,423
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(38)	(7)	(55)	(47)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	494	480	1,038	941
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(851)	(2,374)	(2,767)	(3,366)
Net Income	(772)	(3,089)	(3,473)	(4,319)
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income	(2,221)	2,107	1,933	1,758
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	90,964	92,911	204,511	211,999
Interest Charges	6,083	6,059	12,204	11,138
Income Taxes	1,013	(992)	5,234	4,758
Net Income	8,252	5,242	21,430	21,895
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	51,273	53,370	108,032	108,805
Interest Charges	846	813	1,678	1,621
Income Taxes	1,157	1,336	1,661	3,007
Net Income	1,912	2,300	3,096	5,196
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	45,954	48,090	78,506	88,573
Interest Charges	279	274	525	521
Income Taxes	2,689	2,114	3,953	4,247
Net Income	$ 4,265	$ 3,433	$ 6,385	$ 6,893

Segment Information - Total ass

Segment Information - Total assets by business segment (Details 2) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Assets	$ 1,811,379	$ 1,791,279
Corporate
Segment Reporting Information [Line Items]
Assets	76,442	51,918
Discontinued Operations
Segment Reporting Information [Line Items]
Assets	133	48,657
Electric | Operating Segments
Segment Reporting Information [Line Items]
Assets	1,504,369	1,472,647
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Assets	137,735	130,701
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Assets	$ 92,700	$ 87,356

Segment Information (Detail Tex

Segment Information (Detail Textuals)	6 Months Ended
	Jun. 30, 2015Segment
Segment Reporting [Abstract]
Number of reportable segments	3

Rate and Regulatory Matters - S

Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 1) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Regulatory Matters [Line Items]
Revenues recorded under rate riders		$ 188,153	$ 194,364	$ 390,994	$ 409,330
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenues recorded under rate riders	[1]	1,610	1,471	3,538	2,992
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,212	1,776	2,827	4,080
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		2,600	1,703	5,157	3,466
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,942	2,013	3,825	3,448
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,411	1,707	3,347	3,221
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		$ 2,765	$ 1,452	$ 4,921	2,974
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		$ 281	$ 364	$ 644	$ 710
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		$ 519		$ 1,023
[1]	Includes MNCIP costs recovered in base rates.

Rate and Regulatory Matters (De

Rate and Regulatory Matters (Detail Textuals) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)kVmi	Dec. 31, 2011kVmi
Otter Tail Power Company
Regulatory Matters [Line Items]
Increase In reagent costs and emission allowances	$ 4.1
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 | kV		345
Extended distance of transmission line | mi		70
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Expanded capacity of projects | kV		345
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Minimum
Regulatory Matters [Line Items]
Extended distance of transmission line | mi		160
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Maximum
Regulatory Matters [Line Items]
Extended distance of transmission line | mi		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	$ 193.4
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest	$ 25.7
Percentage of ownership interest acquired in transmission line	4.10%
Distance of transmission line | mi	250
Expanded capacity of projects | kV	345
Capacity Expansion 2020 | Otter Tail Power Company | Fargo-Monticello Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest	$ 80.6
Percentage of ownership interest acquired in transmission line	13.00%
Distance of transmission line | mi	240
Expanded capacity of projects | kV	345

Rate and Regulatory Matters (52

Rate and Regulatory Matters (Detail Textuals 1) - Jointly Owned Utility Plant [Domain] $ in Thousands	Feb. 07, 2013Project	Dec. 31, 2014USD ($)	Jul. 31, 2014USD ($)	Jul. 30, 2014USD ($)	Apr. 25, 2011USD ($)	Jun. 30, 2015USD ($)$ / kWh	Sep. 26, 2014USD ($)
2014 Conservation Improvement Program | Fiscal Year 2014
Regulatory Matters [Line Items]
Financial incentives recognized during period						$ 3,000
Otter Tail Power Company | Minnesota Public Utilities Commission | 2014 Conservation Improvement Program | Fiscal Year 2013
Regulatory Matters [Line Items]
Financial incentive request approved							$ 4,000
Otter Tail Power Company | Minnesota Public Utilities Commission | 2014 Conservation Improvement Program | Fiscal Year 2013 To 2015
Regulatory Matters [Line Items]
Lower Estimated Incentives | $ / kWh						0.09
Otter Tail Power Company | Minnesota Public Utilities Commission | 2014 Conservation Improvement Program | Fiscal Year 2014 To 2016
Regulatory Matters [Line Items]
Lower Estimated Incentives | $ / kWh						0.07
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Number of additional projects approved | Project	3
Otter Tail Power Company | Minnesota Public Utilities Commission | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Annual revenue requirement		$ 9,800	$ 10,200	$ 6,100
Annual increase in revenue requirement			$ 4,100
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved					$ 5,000
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 (53

Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - USD ($) $ in Thousands	Jul. 01, 2015	Mar. 12, 2014	Aug. 29, 2014	Mar. 31, 2014	Jun. 30, 2015	Nov. 25, 2009
Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Over collection of Big stone II abandoned plant costs			$ 100
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				4.319%	7.531%
Environmental Cost Recovery Rider | Maximum
Regulatory Matters [Line Items]
Percentage of ECR rider rate					7.531%
Environmental Cost Recovery Rider | Maximum | Subsequent Event
Regulatory Matters [Line Items]
Percentage of ECR rider rate	9.193%
2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority						$ 3,600
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 (54

Rate and Regulatory Matters (Detail Textuals 3) - Otter Tail Power Company - USD ($)	Feb. 12, 2015	Nov. 12, 2013	Apr. 21, 2011	Jun. 30, 2015	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%
Reductions in revenue				$ 200,000	$ 600,000
Estimated liability of refund obligation				$ 800,000
Current return on equity used in transmission rates		12.38%

Regulatory Assets and Liabili55

Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		$ 17,736	$ 25,273
Regulatory Liability - Current		4,530	1,158
Net Regulatory Assets Position - Current		13,206	24,115
Regulatory Assets - Long-Term		127,475	129,868
Regulatory Liabilities - Long-Term		77,972	77,013
Net Regulatory Assets (Liability) Position - Long-Term		49,503	52,855
Regulatory Assets - Total		145,211	155,141
Regulatory Liabilities - Total		82,502	78,171
Net Regulatory Asset Position - Total		62,709	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	[1]	7,464	7,464
Regulatory Assets - Long-Term	[1]	97,840	101,526
Regulatory Assets - Total	[1]	$ 105,304	$ 108,990
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Deferred Marked-to-Market Loss
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 2,098	$ 4,492
Regulatory Assets - Long-Term	[1]	12,071	9,396
Regulatory Assets - Total	[1]	$ 14,169	$ 13,888
Regulatory Assets - Remaining Recovery/Refund Period	[1]	66 months	72 months
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 2,550	$ 5,843
Regulatory Assets - Long-Term	[2]	4,065	2,500
Regulatory Assets - Total	[2]	$ 6,615	$ 8,343
Regulatory Assets - Remaining Recovery/Refund Period	[2]	24 months	18 months
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]
Regulatory Assets - Long-Term	[1]	$ 5,421	$ 5,190
Regulatory Assets - Total	[1]	$ 5,421	$ 5,190
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 610	$ 592
Regulatory Assets - Long-Term	[1]	2,963	3,207
Regulatory Assets - Total	[1]	$ 3,573	$ 3,799
Regulatory Assets - Remaining Recovery/Refund Period	[1]	90 months	96 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 2,153	$ 943
Regulatory Assets - Long-Term	[2]	950	2,455
Regulatory Assets - Total	[2]	$ 3,103	$ 3,398
Regulatory Assets - Remaining Recovery/Refund Period	[2]	24 months	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 1,642	$ 2,585
Regulatory Assets - Long-Term	[1]	475	807
Regulatory Assets - Total	[1]	$ 2,117	$ 3,392
Regulatory Assets - Remaining Recovery/Refund Period	[1]	24 months	24 months
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 351	$ 351
Regulatory Assets - Long-Term	[1]	1,715	1,890
Regulatory Assets - Total	[1]	$ 2,066	$ 2,241
Regulatory Assets - Remaining Recovery/Refund Period	[1]	207 months	213 months
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	[1]	$ 835	$ 2,086
Regulatory Liabilities - Long-Term		1,346	1,550
Regulatory Assets - Total	[1]	835	2,086
Regulatory Liabilities - Total		$ 1,346	$ 1,550
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 100	$ 100
Regulatory Assets - Long-Term	[2]	693	743
Regulatory Assets - Total	[2]	$ 793	$ 843
Regulatory Assets - Remaining Recovery/Refund Period	[2]	95 months	101 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 594	$ 706
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]	$ 594	$ 706
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months	12 months
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]
Regulatory Assets - Long-Term	[2]	$ 379
Regulatory Assets - Total	[2]	$ 379
Regulatory Assets - Remaining Recovery/Refund Period	[2]	21 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 174	$ 859
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]	$ 174	$ 859
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months	12 months
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]
Regulatory Assets - Long-Term	[2]	$ 68	$ 68
Regulatory Assets - Total	[2]	$ 68	$ 68
Regulatory Assets - Remaining Recovery/Refund Period	[2]	see below	see below
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term		$ 75,355	$ 74,237
Regulatory Liabilities - Total		$ 75,355	$ 74,237
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 2,605
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 2,605
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 1,333	$ 933
Regulatory Liabilities - Long-Term			85
Regulatory Liabilities - Total		$ 1,333	$ 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		$ 1,031	$ 784
Regulatory Liabilities - Total		$ 1,031	$ 784
Regulatory Liabilities - Remaining Recovery/Refund Period		see below	see below
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 391
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 391
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
Deferred Marked-to-Market Gains
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 51
Regulatory Liabilities - Long-Term		143	$ 257
Regulatory Liabilities - Total		$ 194	$ 257
Regulatory Liabilities - Remaining Recovery/Refund Period		31 months	67 months
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		97	100
Regulatory Liabilities - Total		$ 103	$ 106
Regulatory Liabilities - Remaining Recovery/Refund Period		222 months	228 months
Big Stone II Over Recovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 74	$ 147
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 74	$ 147
Regulatory Liabilities - Remaining Recovery/Refund Period		6 months	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 40
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 40
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 30	$ 48
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 30	$ 48
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]		$ 186
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]		$ 186
Regulatory Assets - Remaining Recovery/Refund Period	[2]		12 months
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]		$ 1,114
Regulatory Assets - Long-Term	[1]
Regulatory Assets - Total	[1]		$ 1,114
Regulatory Assets - Remaining Recovery/Refund Period			12 months
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
South Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]		$ 38
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]		$ 38
Regulatory Assets - 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 Liabili56

Regulatory Assets and Liabilities (Detail Textuals)	6 Months Ended
	Jun. 30, 2015
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	207 months

Forward Contracts Classified 57

Forward Contracts Classified as Derivatives - Effect of marking to market forward contracts for purchase and sale of electricity and location and fair value amounts of related derivatives (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$ 17,736	$ 25,273
Regulatory Assets - Long-Term	127,475	129,868
Current Liability - Marked-to-Market Loss	(14,388)	(14,230)
Regulatory Liability - Current	(4,530)	(1,158)
Regulatory Liabilities - Long-Term	(77,972)	(77,013)
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Current Asset - Marked-to-Market Gain	194	257
Total Assets	14,363	14,145
Current Liability - Marked-to-Market Loss	(14,169)	(13,888)
Total Liabilities	$ (14,363)	$ (14,145)
Net Fair Value of Marked-to-Market Energy Contracts				$ 115
Forward Electricity Contracts | Deferred Marked-to-Market Loss
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$ 2,098	$ 4,492
Regulatory Assets - Long-Term	12,071	$ 9,396
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current	(51)
Regulatory Liabilities - Long-Term	$ (143)	$ (257)

Forward Contracts Classified 58

Forward Contracts Classified as Derivatives - Change in consolidated balance sheet location and fair values of forward contracts for purchase and sale of electricity (Details 1) - Forward Electricity Contracts - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
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
Cumulative Fair Value Adjustments Included in Earnings - End of Period

Forward Contracts Classified 59

Forward Contracts Classified as Derivatives - Realized and unrealized net (losses)/gains on forward energy contracts included in electric operating revenues (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Losses on Forward Electric Energy Contracts		$ (9)		$ (13)

Forward Contracts Classified 60

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 ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative assets subject to legally enforceable netting arrangements	$ 194	$ 257
Derivative liabilities subject to legally enforceable netting arrangements	(14,388)	(14,230)
Net balance subject to legally enforceable netting arrangements	$ (14,194)	$ (13,973)

Forward Contracts Classified 61

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 ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit		$ 219	$ 45
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 14,169	13,888
Loss Contracts with No Ratings Triggers or Deposit Requirements			297
Total Current Liability - Marked-to-Market Loss		$ 14,388	$ 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 $ 14,169 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (194) (257) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,975 $ 13,631

Forward Contracts Classified 62

Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parenthetical) (Details) - Otter Tail Power Company - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 14,169	$ 13,888
Offsetting Gains with Counterparties under Master Netting Agreements		(194)	(257)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$ 13,975	$ 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 $ 14,169 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (194) (257) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,975 $ 13,631

Reconciliation of Common Shar63

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period			$ 572,766
Common Stock Issuances, Net of Expenses			10,635
Common Stock Retirements			(1,421)
Net Income	$ 11,436	$ 9,993	29,371	$ 31,423
Other Comprehensive Income			241
Tax Benefit - Stock Compensation			28
Employee Stock Incentive Plans Expense			1,126
Common Dividends ($0.615 per share)			(23,035)
Balance, End of Period	589,711		589,711
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period			186,090
Common Stock Issuances, Net of Expenses			1,962
Common Stock Retirements			(224)
Balance, End of Period	187,828		187,828
Premium on Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period			278,436
Common Stock Issuances, Net of Expenses			8,673
Common Stock Retirements			(1,197)
Tax Benefit - Stock Compensation			28
Employee Stock Incentive Plans Expense			1,126
Balance, End of Period	287,066		287,066
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period			112,903
Net Income			29,371
Common Dividends ($0.615 per share)			(23,035)
Balance, End of Period	119,239		119,239
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period			(4,663)
Other Comprehensive Income			241
Balance, End of Period	$ (4,422)		$ (4,422)

Reconciliation of Common Shar64

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$ 0.3075	$ 0.3025	$ 0.6150	$ 0.6050

Reconciliation of Common Shar65

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1)	6 Months Ended
	Jun. 30, 2015shares
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares Outstanding, December 31, 2014	37,218,053
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	93,855
Cash Invested	43,724
Executive Stock Performance Awards (for 2012 grants)	89,991
At-the-Market Offering	38,160
Directors Deferred Compensation	36,828
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	13,036
Employee Stock Ownership Plan	21,137
Restricted Stock Issued to Directors	15,200
Stock Options Exercised	10,250
Vesting of Restricted Stock Units	10,200
Retirements:
Shares Withheld for Individual Income Tax Requirements	(44,837)
Common Shares Outstanding, June 30, 2015	37,565,590

Reconciliation of Common Shar66

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) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	37,433,318	36,409,753	37,338,218	36,325,052
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers	235,900	225,800	235,900	225,800
Nonvested Restricted Shares	51,798	90,110	51,798	90,110
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	75,100	47,650	75,100	47,650
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	3,676	39,257	3,676	39,257
Potentially Dilutive Stock Options		14,400		14,400
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares	(146,589)	(161,954)	(146,589)	(161,986)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(12,332)		(12,253)
Total Dilutive Shares	219,885	242,931	219,885	242,978
Weighted Average Common Shares Outstanding - Diluted	37,653,203	36,652,684	37,558,103	36,568,030

Reconciliation of Common Shar67

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	May. 11, 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	$ 0.01	$ 0.01	$ 0.01
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS)
Stockholders Equity Note [Line Items]
Agreement To Sell Shares Value					$ 75

Share-Based Payments - Stock in

Share-Based Payments - Stock incentive awards to executive officers (Details) - 2 months ended Apr. 13, 2015 - Executive Officers - $ / shares	Total
Stock Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Grant-Date Fair Value per Award	$ 26.99
Vesting Date	December 31, 2017
Restricted Stock Units | Graded Vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	22,700
Weighted Average Grant-Date Fair Value per Award	$ 31.68
Vesting Percentage	25.00%
Vesting Date	February 6, 2019
Restricted Stock Units | Cliff Vesting
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	February 6, 2020

Share-Based Payments - Stock 69

Share-Based Payments - Stock incentive awards to non-employee directors and key employees (Details 1) - 2 months ended Apr. 13, 2015 - 2014 Stock Incentive Plan - $ / shares	Total
Restricted Stock | Nonemployee Directors
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Shares/Units Granted	15,200
Grant-Date Fair Value per Award	$ 31.775
Vesting Percentage	25.00%
Vesting Date	April 8, 2019
Restricted Stock Units (RSUs) | Employees
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Shares/Units Granted	11,900
Grant-Date Fair Value per Award	$ 27.05
Vesting Percentage	100.00%
Vesting Date	April 8, 2019

Share-Based Payments - Amounts

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 540	$ 896	$ 2,183	$ 1,780
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	45	45	94	87
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	106	98	204	221
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	144	207	301	342
Restricted Stock Units (RSUs) | Nonexecutive Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	81	$ 28	147	$ 86
Restricted Stock Units (RSUs) | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	127		380
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 37	$ 518	$ 1,057	$ 1,044

Share-Based Payments - Amount71

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details 2)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense, discount rate	15.00%	15.00%	15.00%	15.00%

Share-Based Payments (Detail Te

Share-Based Payments (Detail Textuals) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to stock-based compensation	$ 4.2
Weighted-average period of amortization	2 years 8 months 12 days
Stock Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award	84,300
Stock Performance Awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate common shares award	126,450
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	0.00%
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award total shareholder return component	56,200
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award return on equity component	28,100
Period specified for average adjusted return	3 years

Retained Earnings Restriction (

Retained Earnings Restriction (Detail Textuals) - USD ($)	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Retained Earnings Restriction [Line Items]
Total Capitalization	$ 1,088,095,000	$ 1,071,255,000
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	52.10%
OTP | Minimum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	46.90%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	57.30%
Total Capitalization	$ 1,056,300,000

Commitments and Contingencies (

Commitments and Contingencies (Detail Textuals) - Otter Tail Power Company - USD ($) $ in Millions	3 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Line Items]
Operating lease term			36 months
Loss contingency, range of possible loss, maximum	$ 2.7		$ 2.7
Asset Retirement Obligation (ARO) liability			0.5
Federal Energy Regulatory Commission
Commitments and Contingencies Disclosure [Line Items]
Reductions in revenue	0.2	$ 0.6
Estimated liability of refund obligation	$ 0.8		0.8
Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Additional commitments under contracts			$ 4
Contracts expiration year			2,039
Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Additional commitments under contracts			$ 10
Contracts expiration year			2015, 2016, 2017 and 2040
Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount			$ 94.3	$ 106.6
Operating lease
Commitments and Contingencies Disclosure [Line Items]
Additional commitments under contracts			$ 2.6

Short-Term and Long-Term Borr75

Short-Term and Long-Term Borrowings - Status of lines of credit (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Line Limit	$ 320,000
In Use	43,040
Restricted due to Outstanding Letters of Credit	460
Available	276,500	$ 308,312
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	38,494
Restricted due to Outstanding Letters of Credit	150
Available	111,356	138,872
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	4,546
Restricted due to Outstanding Letters of Credit	310
Available	$ 165,144	$ 169,440

Short-Term and Long-Term Borr76

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Short-Term Debt	$ 43,040	$ 10,854
Long-Term Debt	498,591	498,691
Less: Current Maturities	207	201
Unamortized Debt Discount		1
Total Long-Term Debt	498,384	498,489
Total Short-Term and Long-Term Debt (with current maturities)	541,631	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	219	256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	1,042	$ 1,105
OTP
Debt Instrument [Line Items]
Short-Term Debt	4,546
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)	449,546	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	38,494	10,854
Long-Term Debt	53,591	53,691
Less: Current Maturities	207	201
Unamortized Debt Discount		1
Total Long-Term Debt	53,384	53,489
Total Short-Term and Long-Term Debt (with current maturities)	92,085	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	219	256
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 1,042	$ 1,105

Short-Term and Long-Term Borr77

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 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	Dec. 15, 2016	Dec. 15, 2016
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 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	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 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	Feb. 27, 2044	Feb. 27, 2044
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	Apr. 1, 2018	Apr. 1, 2018
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	Mar. 18, 2021	Mar. 18, 2021
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
OTP | 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	Feb. 27, 2029	Feb. 27, 2029
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
OTP | 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	Feb. 27, 2044	Feb. 27, 2044
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%
Long-Term Debt, Due Date	Dec. 15, 2016	Dec. 15, 2016
Otter Tail Corporation | 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	Apr. 1, 2018	Apr. 1, 2018
Otter Tail Corporation | 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	Mar. 18, 2021	Mar. 18, 2021

Pension Plan and Other Postre78

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		$ 1,530	$ 1,174	$ 3,030	$ 2,349
Interest Cost on Projected Benefit Obligation		3,347	3,285	6,672	6,570
Expected Return on Assets		(4,592)	(4,186)	(9,192)	(8,373)
Amortization of Prior-Service Cost:
From Regulatory Asset		47	65	94	129
From Other Comprehensive Income	[1]	1	1	2	3
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,705	868	3,338	1,736
From Other Comprehensive Income	[1]	46	23	86	46
Net Periodic Pension Cost		2,084	1,230	4,030	2,460
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		47	12	94	25
Interest Cost on Projected Benefit Obligation		381	380	762	760
Amortization of Prior-Service Cost:
From Regulatory Asset		4	6	8	11
From Other Comprehensive Income	[2]	9	13	19	26
Amortization of Net Actuarial Loss:
From Regulatory Asset		84	36	167	71
From Other Comprehensive Income	[3]	150	11	301	23
Net Periodic Pension Cost		675	458	1,351	916
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		273	213	648	528
Interest Cost on Projected Benefit Obligation		499	542	1,049	1,100
Amortization of Prior-Service Cost:
From Regulatory Asset		51	51	102	102
From Other Comprehensive Income	[1]	2	$ 2	$ 3	$ 3
Amortization of Net Actuarial Loss:
From Regulatory Asset		(48)
From Other Comprehensive Income	[1]	(1)
Net Periodic Pension Cost		776	$ 808	$ 1,802	$ 1,733
Effect of Medicare Part D Subsidy		$ (293)	$ (166)	$ (743)	$ (474)
[1]	Corporate cost included in Other Nonelectric Expenses.
[2]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 5 $ 8 $ 10 Other Nonelectric Expenses 5 8 11 16
[3]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 77 $ 33 $ 155 $ 66 Other Nonelectric Expenses 73 (22) 146 (43)

Pension Plan and Other Postre79

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) - Executive Survivor and Supplemental Retirement Plan - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	[1]	$ 9	$ 13	$ 19	$ 26
Amortization of Net Actuarial Loss - From Other Comprehensive Income	[2]	150	11	301	23
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income		4	5	8	10
Amortization of Net Actuarial Loss - From Other Comprehensive Income		77	33	155	66
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income		5	8	11	16
Amortization of Net Actuarial Loss - From Other Comprehensive Income		$ 73	$ (22)	$ 146	$ (43)
[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 5 $ 8 $ 10 Other Nonelectric Expenses 5 8 11 16
[2]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 77 $ 33 $ 155 $ 66 Other Nonelectric Expenses 73 (22) 146 (43)

Pension Plan and Other Postre80

Pension Plan and Other Postretirement Benefits (Detail Textuals) - 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 Instr81

Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	$ (43,040)	$ (10,854)
Long-Term Debt including Current Maturities	(498,591)	(498,690)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	(43,040)	(10,854)
Long-Term Debt including Current Maturities	$ (554,434)	$ (600,828)

Fair Value of Financial Instr82

Fair Value of Financial Instruments (Detail Textuals)	6 Months Ended	12 Months Ended
	Jun. 30, 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 - Continui83

Income Tax Expense - Continuing operations effective income tax rate (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 17,665	$ 7,970	$ 35,519	$ 38,311
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	6,889	3,108	13,852	14,941
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)	(1,656)	(1,864)	(3,710)	(4,116)
Section 199 Domestic Production Activities Deduction	(363)	(349)	(725)	(707)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(213)	(212)	(425)	(425)
Employee Stock Ownership Plan Dividend Deduction	(171)	(189)	(343)	(379)
Investment Tax Credits	(143)	(127)	(286)	(254)
AFUDC Equity	(125)	(164)	(225)	(297)
Other Items - Net	(210)	(119)	(57)	(117)
Income Tax Expense - Continuing Operations	$ 4,008	$ 84	$ 8,081	$ 8,646
Effective Income Tax Rate - Continuing Operations	22.70%	1.10%	22.80%	22.60%

Income Tax Expense - Continui84

Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%	39.00%	39.00%

Income Tax Expense - Continui85

Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 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	$ 86
Uncertain Positions Resolved During Year
Balance on June 31	$ 308	$ 4,376

Discontinued Operations - Resul

Discontinued Operations - Results of discontinued operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net (Loss) Income from Operations			$ (5,064)	$ 1,758
Income Tax (Benefit) Expense on Disposition	$ (280)		4,536
Net (Loss) Gain on Disposition	(229)		6,997
Net Income (Loss)	(2,221)	$ 2,107	1,933	1,758
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	5,899	40,247	24,623	65,753
Operating Expenses	$ 9,209	$ 36,751	31,350	$ 63,119
Goodwill Impairment Charge			1,000
Operating (Loss) Income	$ (3,310)	$ 3,496	$ (7,727)	$ 2,634
Interest Charges		1		1
Other (Deductions) Income	$ (11)	14	$ (42)	302
Income Tax (Benefit) Expense	(1,329)	1,402	(2,705)	1,177
Net (Loss) Income from Operations	(1,992)	$ 2,107	(5,064)	$ 1,758
(Loss) Gain on Disposition Before Taxes	(509)		11,533
Income Tax (Benefit) Expense on Disposition	(280)		4,536
Net (Loss) Gain on Disposition	(229)		6,997
Net Income (Loss)	$ (2,221)	$ 2,107	$ 1,933	$ 1,758

Discontinued Operations - Major

Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets of Discontinued Operations	$ 133	$ 48,657
Liabilities of Discontinued Operations	3,260	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	$ 133	35,174
Goodwill and Intangibles		2,814
Net Plant		10,669
Assets of Discontinued Operations	$ 133	48,657
Current Liabilities	$ 3,260	22,864
Deferred Income Taxes		4,695
Liabilities of Discontinued Operations	$ 3,260	$ 27,559

Discontinued Operations - Warra

Discontinued Operations - Warranty Reserves (Details 2) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 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	$ (115)	$ (5)
Decrease in Warranty Estimates for Prior Years		(133)
Warranty Reserve Balance, June 30	$ 2,412	$ 2,949

Discontinued Operations (Detail

Discontinued Operations (Detail Textuals) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended			6 Months Ended		12 Months Ended
	Apr. 30, 2015	Feb. 28, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations						$ 32,765
Gain (loss) on disposition, net of tax			$ (229)			6,997
Net (Loss) Income from Operations						(5,064)	$ 1,758
Waterfront equipment manufacturer
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net (Loss) Income from Operations			(500)			(500)
Wind tower manufacturer
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net (Loss) Income from Operations						100
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
Amount of working capital		900
Gain (loss) on disposition, net of tax		$ 7,200
Net (Loss) Income from Operations					$ 1,000	(800)	500
Foley
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of discontinued operations	$ 12,000
Amount of working capital	$ 5,700
Cost estimates pretax charges			2,100			4,400
Net (Loss) Income from Operations			$ (1,500)		$ 1,100	$ (3,900)	$ 1,200
Goodwill Impairment Charge				$ 1,000				$ 5,600