Otter Tail (OTTR) 10-Q 9 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1,466,593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		38,772,031
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets (no

Consolidated Balance Sheets (not audited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents
Accounts Receivable:
Trade-Net	78,677	62,974
Other	7,144	9,073
Inventories	81,396	85,416
Unbilled Revenues	15,909	17,869
Income Taxes Receivable		4,000
Regulatory Assets	17,205	18,904
Other	14,065	8,453
Total Current Assets	214,396	206,689
Investments	8,413	8,284
Other Assets	33,605	32,784
Goodwill	37,572	39,732
Other Intangibles-Net	15,639	15,673
Regulatory Assets	123,706	127,707
Plant
Electric Plant in Service	1,834,157	1,820,763
Nonelectric Operations	218,007	201,343
Construction Work in Progress	116,848	79,612
Total Gross Plant	2,169,012	2,101,718
Less Accumulated Depreciation and Amortization	740,440	713,904
Net Plant	1,428,572	1,387,814
Total Assets	1,861,903	1,818,683
Current Liabilities
Short-Term Debt	49,274	80,672
Current Maturities of Long-Term Debt	52,497	52,422
Accounts Payable	86,210	89,499
Accrued Salaries and Wages	14,774	16,182
Accrued Taxes	10,562	14,827
Other Accrued Liabilities	17,951	15,416
Liabilities of Discontinued Operations	1,868	2,098
Total Current Liabilities	233,136	271,116
Pensions Benefit Liability	95,520	104,912
Other Postretirement Benefits Liability	49,659	48,730
Other Noncurrent Liabilities	24,980	23,854
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	217,523	207,669
Deferred Tax Credits	23,678	24,506
Regulatory Liabilities	77,915	77,432
Other	9,580	11,595
Total Deferred Credits	328,696	321,202
Capitalization
Long-Term Debt-Net	493,804	443,846
Common Shares, Par Value $5 Per Share-Authorized, 50,000,000 Shares; Outstanding, 2016 - 38,703,277 Shares; 2015 - 37,857,186 Shares	193,516	189,286
Premium on Common Shares	313,839	293,610
Retained Earnings	132,401	126,025
Accumulated Other Comprehensive Loss	(3,648)	(3,898)
Total Common Equity	636,108	605,023
Total Capitalization	1,129,912	1,048,869
Total Liabilities and Equity	1,861,903	1,818,683
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, 2016	Dec. 31, 2015
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	38,703,277	37,857,186
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding	0	0
Cumulative Preference Shares
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding	0	0

Consolidated Statements of Inco

Consolidated Statements of Income (not audited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Revenues
Electric	$ 97,918	$ 90,927	$ 210,903	$ 204,460
Product Sales	105,564	97,226	198,821	186,534
Total Operating Revenues	203,482	188,153	409,724	390,994
Operating Expenses
Production Fuel - Electric	9,990	4,183	25,690	18,782
Purchased Power - Electric System Use	15,127	19,684	32,013	43,376
Electric Operation and Maintenance Expenses	38,981	37,754	78,999	75,281
Cost of Products Sold (depreciation included below)	80,949	74,986	153,588	146,484
Other Nonelectric Expenses	9,238	8,823	20,693	21,286
Depreciation and Amortization	18,525	14,661	36,814	29,196
Property Taxes - Electric	3,589	3,262	7,268	6,764
Total Operating Expenses	176,399	163,353	355,065	341,169
Operating Income	27,083	24,800	54,659	49,825
Interest Charges	7,976	7,702	15,970	15,445
Other Income	1,532	567	1,932	1,139
Income Before Income Taxes - Continuing Operations	20,639	17,665	40,621	35,519
Income Tax Expense - Continuing Operations	5,083	4,008	10,575	8,081
Net Income from Continuing Operations	15,556	13,657	30,046	27,438
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $80, ($1,329), $100 and ($2,705) for the respective periods	119	(1,992)	149	(4,064)
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 Income (Loss) from Discontinued Operations	119	(2,221)	149	1,933
Net Income	$ 15,675	$ 11,436	$ 30,195	$ 29,371
Average Number of Common Shares Outstanding - Basic	38,179,371	37,433,318	38,058,157	37,338,218
Average Number of Common Shares Outstanding - Diluted	38,321,289	37,653,203	38,183,249	37,558,103
Basic Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$ 0.41	$ 0.37	$ 0.79	$ 0.74
Discontinued Operations (in dollars per share)		(0.06)		0.05
Earnings Per Share, Basic, Total (in dollars per share)	0.41	0.31	0.79	0.79
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	0.41	0.36	0.79	0.73
Discontinued Operations (in dollars per share)		(0.06)		0.05
Earnings Per Share, Diluted, Total (in dollars per share)	0.41	0.30	0.79	0.78
Dividends Declared Per Common Share (in dollars per share)	$ 0.3125	$ 0.3075	$ 0.625	$ 0.6150

Consolidated Statements of Inc5

Consolidated Statements of Income (not audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Income tax expense (benefit) on income (loss) from discontinued operation	$ 80	$ (1,329)	$ 100	$ (2,705)
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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 15,675	$ 11,436	$ 30,195	$ 29,371
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)
Gains (Losses) Arising During Period	27	(37)	100	(5)
Income Tax (Expense) Benefit	(9)	13	(35)	3
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	18	(24)	65	(5)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	155	207	309	411
Income Tax Expense	(63)	(83)	(124)	(165)
Pension and Postretirement Benefit Plans - net-of-tax	92	124	185	246
Total Other Comprehensive Income	110	100	250	241
Total Comprehensive Income	$ 15,785	$ 11,536	$ 30,445	$ 29,612

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (not audited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Flows from Operating Activities
Net Income	$ 30,195	$ 29,371
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		(6,997)
Net (Income) Loss from Discontinued Operations	(149)	5,064
Depreciation and Amortization	36,814	29,196
Deferred Tax Credits	(828)	(939)
Deferred Income Taxes	9,679	12,707
Change in Deferred Debits and Other Assets	2,680	11,470
Discretionary Contribution to Pension Plan	(10,000)	(10,000)
Change in Noncurrent Liabilities and Deferred Credits	6,404	4,025
Allowance for Equity/Other Funds Used During Construction	(475)	(576)
Change in Derivatives Net of Regulatory Deferral		(123)
Stock Compensation Expense - Equity Awards	828	1,126
Other - Net	(76)	200
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(12,673)	(5,918)
Change in Inventories	4,218	3,400
Change in Other Current Assets	(1,043)	1,913
Change in Payables and Other Current Liabilities	(5,441)	(21,294)
Change in Interest and Income Taxes Receivable/Payable	4,018	96
Net Cash Provided by Continuing Operations	64,151	52,721
Net Cash Provided by (Used in) Discontinued Operations	11	(10,966)
Net Cash Provided by Operating Activities	64,162	41,755
Cash Flows from Investing Activities
Capital Expenditures	(79,158)	(83,418)
Net Proceeds from Disposal of Noncurrent Assets	1,080	2,628
Final Purchase Price Adjustment - BTD-Georgia Acquisition	1,500
Cash Used for Investments and Other Assets	(1,719)	(5,763)
Net Cash Used in Investing Activities - Continuing Operations	(78,297)	(86,553)
Net Proceeds from Sale of Discontinued Operations		32,765
Net Cash Used in Investing Activities - Discontinued Operations		(1,770)
Net Cash Used in Investing Activities	(78,297)	(55,558)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(2,024)	(947)
Net Short-Term Debt (Repayments) Borrowings	(31,398)	32,186
Proceeds from Issuance of Common Stock - net of Issuance Expenses	21,645	6,848
Payments for Retirement of Capital Stock	(104)	(1,421)
Proceeds from Issuance of Long-Term Debt	50,000
Short-Term and Long-Term Debt Issuance Expenses	(59)	(4)
Payments for Retirement of Long-Term Debt	(106)	(99)
Dividends Paid and Other Distributions	(23,819)	(23,035)
Net Cash Provided by Financing Activities - Continuing Operations	14,135	13,528
Net Cash Provided by Financing Activities - Discontinued Operations		322
Net Cash Provided by Financing Activities	14,135	13,850
Net Change in Cash and Cash Equivalents - Discontinued Operations		(47)
Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2016
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, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company’s (OTP) 2015 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. Agreements Subject to Legally Enforceable Netting Arrangements The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. 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, 2016 and December 31, 2015: June 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,169 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,067 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 835 Total Assets $ 2,835 $ 8,236 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 87 Total Liabilities $ 87 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Forward Gasoline Purchase Contracts Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company Inventories Inventories consist of the following: June 30, December 31, (in thousands) 2016 2015 Finished Goods $ 22,978 $ 25,971 Work in Process 12,133 12,821 Raw Material, Fuel and Supplies 46,285 46,624 Total Inventories $ 81,396 $ 85,416 Goodwill and Other Intangible Assets On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The newly acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2015 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table summarizes changes to goodwill by business segment during 2016: (in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572 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 The following table summarizes the components of the Company’s intangible assets at June 30, 2016 and December 31, 2015: June 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,310 $ 15,181 42-230 months Covenant not to Compete 590 164 426 26 months Other Intangible Assets 639 607 32 3 months Emission Allowances — NA — Expensed as used Total $ 23,720 $ 8,081 $ 15,639 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 398 $ 244 $ 755 $ 488 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099 Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 17,837 $ 27,267 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 commenced with the initial delivery of coal to Coyote Station 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. 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. Coyote Station started taking delivery of coal and paying for coal and the accumulated development fees and capital charges under the LSA in May 2016. OTP’s 35% share of the unrecovered development period costs, development fees and capital charges incurred by CCMC through June 30, 2016 is $62.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2016 could be as high as $62.5 million. New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. 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 guidance prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table: (in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683 ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, ASU 2016-02 Leases (Topic 842) leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous leases guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019. ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , but does not expect it to be material.

Business Combinations and Segme

Business Combinations and Segment Information	6 Months Ended
	Jun. 30, 2016
Acquisition And Segment Information [Abstract]
Business Combinations and Segment Information	2. Business Combinations and Segment Information Business Combinations On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company. Below is condensed balance sheet information disclosing the final allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia: (in thousands) Assets: Current Assets $ 4,906 Goodwill 6,083 Other Intangible Assets 6,270 Other Amortizable Assets 1,380 Fixed Assets 13,649 Total Assets $ 32,288 Liabilities: Current Liabilities $ 2,971 Lease Obligation 11 Total Liabilities $ 2,982 Cash Paid $ 29,306 The assignment of asset values is based on the final purchase price. In the fourth quarter of 2015, the Company elected to early adopt ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, 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. Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a 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, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, 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 2015. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5% and 97.3% of its operating revenues for the respective three-month periods ended June 30, 2016 and 2015, and 98.7% and 96.8% of its operating revenues for the respective six-month periods ended June 30, 2016 and 2015. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and six-month periods ended June 30, 2016 and 2015 and total assets by business segment as of June 30, 2016 and December 31, 2015 are presented in the following tables: Operating Revenue Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 97,925 $ 90,964 $ 210,919 $ 204,511 Manufacturing 58,452 51,273 118,272 108,032 Plastics 47,112 45,954 80,549 78,506 Intersegment Eliminations (7 ) (38 ) (16 ) (55 ) Total $ 203,482 $ 188,153 $ 409,724 $ 390,994 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 6,156 $ 6,083 $ 12,440 $ 12,204 Manufacturing 1,006 846 1,998 1,678 Plastics 279 279 523 525 Corporate and Intersegment Eliminations 535 494 1,009 1,038 Total $ 7,976 $ 7,702 $ 15,970 $ 15,445 Income Tax Expense—Continuing Operations Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 1,920 $ 1,013 $ 6,532 $ 5,234 Manufacturing 1,791 1,157 2,810 1,661 Plastics 2,262 2,689 3,629 3,953 Corporate (890 ) (851 ) (2,396 ) (2,767 ) Total $ 5,083 $ 4,008 $ 10,575 $ 8,081 Net Income (Loss) Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 9,148 $ 8,252 $ 21,686 $ 21,430 Manufacturing 3,009 1,912 4,862 3,096 Plastics 3,485 4,265 5,637 6,385 Corporate (86 ) (772 ) (2,139 ) (3,473 ) Discontinued Operations 119 (2,221 ) 149 1,933 Total $ 15,675 $ 11,436 $ 30,195 $ 29,371 Identifiable Assets June 30, December 31, (in thousands) 2016 2015 Electric $ 1,553,563 $ 1,520,887 Manufacturing 179,971 173,860 Plastics 89,058 81,624 Corporate 39,311 42,312 Total $ 1,861,903 $ 1,818,683

Rate and Regulatory Matters

Rate and Regulatory Matters	6 Months Ended
	Jun. 30, 2016
Rate and Regulatory Matters [Abstract]
Rate and Regulatory Matters	3. Rate and Regulatory Matters Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2016 and 2015. Major Capital Expenditure Projects Big Stone Plant Air Quality Control System (AQCS) Fargo–Monticello 345 kiloVolt ( kV Capacity Expansion 2020 (CapX2020) Project (the Fargo Project) Brookings–Southeast Twin Cities 345 kV CapX2020 MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff ( MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation of MVP’s is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. The Big Stone South–Brookings MVP and CapX2020 with obligations to have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP MISO Tariff OTP’s capitalized cost of this project as of June 30, 2016 was approximately $43.0 million, which includes assets that are 100% owned by OTP. The Big Stone South–Ellendale MVP with obligations of having equal ownership interest in the transmission line portion of the project. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized cost of this project as of June 30, 2016 was approximately $29.8 million, which includes assets that are 100% owned by OTP. Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota 2016 General Rate Case Annualized or Actual Through June 30, 2016 ($ in thousands) Test Year 3 Months Ended 6 Months Ended Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 2,850 $ 2,850 The major components of the requested rate increase are summarized below: Revenue Requirement Deficiency Cost Factors (in thousands) 2016 Test Year Increased Rate Base $ 10,000 Increased Expenses 7,700 Other 1,596 Total Requested Revenue Increase $ 19,296 Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset (2,480 ) Approved Interim Revenue Increase (subject to refund) $ 16,816 Expected dates for next steps in the procedural schedule: · Intervenor direct testimony ─ due August 16, 2016 · Public hearings ─ August 24 and 25, 2016 · Evidentiary hearings ─ October 13-17, 2016 · Report of administrative law judge (ALJ) ─ January 5, 2017 · Final order ─ March 16, 2017 2010 General Rate Case Minnesota Conservation Improvement Programs (MNCIP) On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015. Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million in 2015. The 2015 MNCIP program resulted in approximately a 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016. The MNDOC has proposed changes to the MNCIP financial incentive mechanism. On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. The MNDOC opened an additional docket to investigate how investor-owned utilities calculate their avoided costs pertaining to generation capacity, energy, transmission and distribution. Avoided costs are the basis of MNCIP program benefits which going forward will establish OTP’s financial incentive. On May 23, 2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but is requiring Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019 with results to be submitted to the MNDOC by January 31, 2017. Transmission Cost Recovery Rider — The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016. OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. The proposed rate changes were to be effective on September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The MPUC granted an extension to file initial comments in this docket until November 1, 2016. Environmental Cost Recovery Rider —On December 18, 2013 the MPUC granted approval of OTP’s Minnesota Environmental Cost Recovery (ECR) rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s most recent general rate case. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and granted an extension to file initial comments in this docket until November 1, 2016. North Dakota General Rates Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%. Renewable Resource Adjustment On March 25, 2015 the NDPSC approved OTP’s 2014 annual update to the NDRRA rider, including a change in rate design from an amount per kilowatt-hour consumed to a percentage of a customer’s bill, with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 . The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. Transmission Cost Recovery Rider The NDPSC approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. Environmental Cost Recovery Rider On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project costs. Reagent Costs and Emission Allowances South Dakota 2010 General Rate Case Transmission Cost Recovery Rider This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. Environmental Cost Recovery Rider —On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. 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: Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2016 2015 2016 2015 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,209 $ 1,610 $ 4,715 $ 3,538 Transmission Cost Recovery 1,133 1,212 3,409 2,827 Environmental Cost Recovery 3,153 2,600 6,235 5,157 North Dakota Renewable Resource Adjustment 1,922 1,942 3,981 3,825 Transmission Cost Recovery 1,969 1,411 4,205 3,347 Environmental Cost Recovery 2,771 2,765 5,582 4,921 South Dakota Transmission Cost Recovery 411 281 1,062 644 Environmental Cost Recovery 627 519 1,260 1,023 Conservation Improvement Program Costs and Incentives 124 90 283 230 1 FERC Multi-Value Transmission Projects On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP. On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the 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 12.38% ROE used in MISO’s transmission rates over a 15-month period ending in February 2015 to a proposed 9.15%. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%. The FERC is expected to issue its order later in 2016. 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 FERC issues its order in the ROE complaint proceeding. On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67% over a 15-month period ending in May 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearing and hearings were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. The FERC is expected to issue its order in the spring of 2017. Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded reductions in revenue of $1.0 million and $0.2 million in the three-month periods ended June 30, 2016 and 2015, respectively, and $1.3 million and $0.8 million in the six-month periods ended June 30, 2016 and 2015, respectively, and has a $2.4 million liability on its balance sheet as of June 30, 2016, representing OTP’s best estimate of a refund obligation that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, if FERC orders a reduction in the ROE component of the MISO Tariff.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 2016
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, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 96,523 $ 103,962 see below Deferred Marked-to-Market Losses 1 4,063 8,499 12,562 54 months Conservation Improvement Program Costs and Incentives 2 1,313 6,016 7,329 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,911 5,911 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 648 2,646 3,294 58 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,894 684 2,578 21 months Debt Reacquisition Premiums 1 351 1,364 1,715 195 months Deferred Income Taxes 1 — 1,247 1,247 asset lives MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 616 166 782 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 593 693 83 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 458 — 458 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 323 — 323 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 57 57 15 months Total Regulatory Assets $ 17,205 $ 123,706 $ 140,911 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 76,196 76,196 asset lives Refundable Fuel Clause Adjustment Revenues 2,619 — 2,619 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 712 563 1,275 22 months Deferred Income Taxes — 978 978 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 700 — 700 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 644 — 644 12 months Minnesota Transmission Cost Recovery Rider Accrued Refund 642 — 642 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 609 — 609 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 334 — 334 12 months Other 31 92 123 210 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 86 86 24 months Total Regulatory Liabilities $ 6,291 $ 77,915 $ 84,206 Net Regulatory Asset Position $ 10,914 $ 45,791 $ 56,705 1 2 December 31, 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 $ 7,439 $ 99,293 $ 106,732 see below Deferred Marked-to-Market Losses 1 4,063 10,530 14,593 60 months Conservation Improvement Program Costs and Incentives 2 4,411 4,266 8,677 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,672 5,672 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 942 2,620 3,562 84 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Deferred Income Taxes 1 — 1,455 1,455 asset lives North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Total Regulatory Assets $ 18,904 $ 127,707 $ 146,611 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 74,948 $ 74,948 asset lives Refundable Fuel Clause Adjustment Revenues 1,834 — 1,834 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota — 1,279 1,279 see below Deferred Income Taxes — 1,110 1,110 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Renewable Resource Rider Accrued Refund 68 — 68 12 months Total Regulatory Liabilities $ 3,322 $ 77,432 $ 80,754 Net Regulatory Asset Position $ 15,582 $ 50,275 $ 65,857 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 Losses recorded as of June 30, 2016 relate 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 project. 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, 2016. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 195 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 MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include 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. 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 project. Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016. The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of June 30, 2016. 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 rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates 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 over a 24-month period beginning with the establishment of interim rates in April 2016. The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of June 30, 2016. 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, 2016. The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of June 30, 2016. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of June 30, 2016. 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, 2016. 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.

Open Contract Positions Subject

Open Contract Positions Subject to Legally Enforceable Netting Arrangements	6 Months Ended
	Jun. 30, 2016
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]
Open Contract Positions Subject to Legally Enforceable Netting Arrangements	5. Open Contract Positions Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows forward contract fair value positions subject to legally enforceable netting arrangements as of June 30, 2016 and December 31, 2015: (in thousands) June 30, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (14,419 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (14,419 ) $ (16,070 ) The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in loss positions as of June 30, 2016 and December 31, 2015: Loss Position (in thousands) June 30 , 2016 December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 87 $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,332 15,871 Loss Contracts with No Ratings Triggers or Deposit Requirements — — Loss Position $ 14,419 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,332 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 14,332 $ 15,871

Reconciliation of Common Shareh

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share	6 Months Ended
	Jun. 30, 2016
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, 2015 $ 189,286 $ 293,610 $ 126,025 $ (3,898 ) $ 605,023 Common Stock Issuances, Net of Expenses 4,249 19,486 23,735 Common Stock Retirements (19 ) (85 ) (104 ) Net Income 30,195 30,195 Other Comprehensive Income 250 250 Employee Stock Incentive Plans Expense 828 828 Common Dividends ($0.625 per share) (23,819 ) (23,819 ) Balance, June 30, 2016 $ 193,516 $ 313,839 $ 132,401 $ (3,648 ) $ 636,108 Shelf Registration The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018. 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, 2015 through June 30, 2016: Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 510,139 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 93,171 Cash Invested 69,740 Executive Stock Performance Awards (2013 and 2014 shares earned) 54,700 Employee Stock Purchase Plan: Cash Invested 39,938 Dividends Reinvested 13,467 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,025 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, June 30, 2016 38,703,277 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, 2016 and 2015. 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: Three Months ended Six Months ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 38,179,371 37,433,318 38,058,157 37,338,218 Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance 91,381 141,540 69,133 141,540 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 39,374 45,060 39,608 45,060 Nonvested Restricted Shares 7,862 31,079 12,819 31,079 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,301 2,206 3,532 2,206 Total Dilutive Shares 141,918 219,885 125,092 219,885 Weighted Average Common Shares Outstanding – Diluted 38,321,289 37,653,203 38,183,249 37,558,103 The effect of dilutive shares on earnings per share for the three- and six-month periods ended June 30, 2016 and 2015, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

Share-Based Payments

Share-Based Payments	6 Months Ended
	Jun. 30, 2016
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Share-Based Payments	7. Share-Based Payments Stock Incentive Awards On February 4, 2016 the following stock incentive awards were granted to the Company’s executive officers under the 2014 Stock Incentive Plan: Award Shares/ Grant-Date Vesting Stock Performance Awards Granted to Executive Officers 81,500 $ 24.03 December 31, 2018 Restricted Stock Units Granted to Executive Officers 22,000 $ 28.915 25% per year through February 6, 2020 On April 11, 2016 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/ Grant-Date Vesting Restricted Stock Granted to Nonemployee Directors 23,200 $ 28.66 25% per year through April 8, 2020 Restricted Stock Units Granted to Key Employees 15,800 $ 24.00 100% on April 8, 2020 Under the 2016 performance share award agreements, the aggregate award for performance at target is 81,500 shares. For target performance the Company’s executive officers would earn an aggregate of 54,333 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, 2016 through December 31, 2018, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2016 and the average closing price for the 20 trading days immediately preceding January 1, 2019, respectively. The Company’s executive officers would also earn an aggregate of 27,167 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 an aggregate of 122,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement 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 2016 performance share 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 these performance share award agreements is accelerated and paid out at target in the event of a change in control, disability or death (and on retirement at or after the age of 62 for certain officers who are parties to executive employment agreements with the Company). The restricted stock units and shares of restricted stock vest 25% per year from the date of grant, and vesting is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price per share on the date 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. 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 share was based on the market value of one share of the Company’s common stock on the date of grant. The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of June 30, 2016 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.9 million (before income taxes) which will be amortized over a weighted-average period of 2.7 years. Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three- and six-month periods ended June 30, 2016 and 2015 are presented in the table below: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Stock Performance Awards Granted to Executive Officers $ 304 $ 37 $ 841 $ 1,057 Restricted Stock Units Granted to Executive Officers 64 127 309 380 Restricted Stock Granted to Executive Officers 22 144 51 301 Restricted Stock Granted to Directors 128 106 235 204 Restricted Stock Units Granted to Nonexecutive Employees 81 81 145 147 Employee Stock Purchase Plan (15% discount) 44 45 88 94 Totals $ 643 $ 540 $ 1,669 $ 2,183

Retained Earnings Restriction

Retained Earnings Restriction	6 Months Ended
	Jun. 30, 2016
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, 2016 the Company was in compliance with these financial covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2015 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 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. OTP’s equity to total capitalization ratio including short-term debt was 52.6% as of June 30, 2016. Total capitalization for OTP cannot currently exceed $1,123,168,000.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	9. Commitments and Contingencies Construction and Other Purchase Commitments At December 31, 2015 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $89.6 million. At June 30, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $123.1 million. Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. In May 2016, OTP entered into a $3.5 million electric generating capacity purchase agreement for the period June 2017 through May 2019. OTP has commitments under contracts providing for the purchase and delivery of a significant portion of its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040, respectively. In January 2016, OTP entered into an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant for the period of January 1, 2016 through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement. Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. 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 $1.0 million. Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP has recorded a $2.4 million liability on its balance sheet as of June 30, 2016, representing OTP’s best estimate of a refund obligation that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, if FERC orders a reduction in ROE component of the MISO Tariff. In 2014, the Environmental Protection Agency (EPA) published proposed standards of performance for CO2 emissions from new fossil fuel-fired power plants, proposed CO2 emission guidelines for existing fossil fuel-fired power plants and proposed CO2 standards of performance for CO2 emissions from reconstructed and modified fossil fuel-fired power plants under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. All of these rules have been challenged on legal grounds and are currently pending in the D.C. Circuit. On February 9, 2016 the U.S. Supreme Court granted a stay of the CO2 emission guidelines for existing fossil fuel-fired power plants, pending disposition of petitions for review in the D.C. Circuit and disposition of a petition for a writ of certiorari seeking review by the U.S. Supreme Court, if such a writ is sought. Oral argument before all the judges of the D.C. Circuit (en banc review) is scheduled for September 2016. Uncertainty regarding the status of the rules will likely continue for some time. OTP is actively engaged with the stakeholder processes in each of its states that have continued to move forward with planning efforts during the stay. Other The Company is a party to litigation and regulatory enforcement matters 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, 2016 will not be material.

Short-Term and Long-Term Borrow

Short-Term and Long-Term Borrowings	6 Months Ended
	Jun. 30, 2016
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, 2016 and December 31, 2015: (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ 19,289 $ — $ 130,711 $ 90,334 OTP Credit Agreement 170,000 29,985 50 139,965 148,694 Total $ 320,000 $ 49,274 $ 50 $ 270,676 $ 239,028 Debt Issuances and Retirements On February 5, 2016 the Company entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A., as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company’s election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018. The Term Loan Agreement contains a number of restrictions on the Company, Varistar and certain subsidiaries of Varistar, including restrictions on their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, and certain financial covenants. Specifically, the Company must not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the Term Loan Agreement. The Term Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries. On February 5, 2016 the Company borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia. 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, 2016 and December 31, 2015: June 30, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 29,985 $ 19,289 $ 49,274 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 Term Loan, LIBOR plus 0.90%, due February 5, 2018 50,000 50,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 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 145 145 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 908 908 Total $ 445,000 $ 103,383 $ 548,383 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,497 52,497 Unamortized Long-Term Debt Issuance Costs 1,980 102 2,082 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 443,020 $ 50,784 $ 493,804 Total Short-Term and Long-Term Debt (with current maturities) $ 473,005 $ 122,570 $ 595,575 December 31, 2015 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 21,006 $ 59,666 $ 80,672 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 182 182 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 977 977 Total $ 445,000 $ 53,489 $ 498,489 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,422 52,422 Unamortized Long-Term Debt Issuance Costs 2,099 122 2,221 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 442,901 $ 945 $ 443,846 Total Short-Term and Long-Term Debt (with current maturities) $ 463,907 $ 113,033 $ 576,940

Pension Plan and Other Postreti

Pension Plan and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2016
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) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 1,381 $ 1,530 $ 2,763 $ 3,030 Interest Cost on Projected Benefit Obligation 3,521 3,347 7,043 6,672 Expected Return on Assets (4,866 ) (4,592 ) (9,733 ) (9,192 ) Amortization of Prior-Service Cost: From Regulatory Asset 47 47 94 94 From Other Comprehensive Income 1 1 1 2 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,227 1,705 2,454 3,338 From Other Comprehensive Income 1 32 46 63 86 Net Periodic Pension Cost $ 1,343 $ 2,084 $ 2,686 $ 4,030 1 Cash flows Executive Survivor and Supplemental Retirement Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 63 $ 47 $ 126 $ 94 Interest Cost on Projected Benefit Obligation 417 381 834 762 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 10 9 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 73 84 146 167 From Other Comprehensive Income 2 111 150 223 301 Net Periodic Pension Cost $ 678 $ 675 $ 1,356 $ 1,351 1 Electric Operation and Maintenance Expenses $ 4 $ 4 $ 8 $ 8 Other Nonelectric Expenses 6 5 11 11 2 Electric Operation and Maintenance Expenses $ 68 $ 77 $ 136 $ 155 Other Nonelectric Expenses 43 73 87 146 Postretirement Benefits Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 305 $ 273 $ 611 $ 648 Interest Cost on Projected Benefit Obligation 542 499 1,083 1,049 Amortization of Prior-Service Cost: From Regulatory Asset 33 51 66 102 From Other Comprehensive Income 1 1 2 2 3 Amortization of Net Actuarial Loss: From Regulatory Asset — (48 ) — — From Other Comprehensive Income 1 — (1 ) — — Net Periodic Postretirement Benefit Cost $ 881 $ 776 $ 1,762 $ 1,802 Effect of Medicare Part D Subsidy $ (258 ) $ (293 ) $ (515 ) $ (743 ) 1

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2016
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, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (49,274 ) (49,274 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (546,301 ) (641,722 ) (496,268 ) (561,245 )

Income Tax Expense Continuing

Income Tax Expense Continuing Operations	6 Months Ended
	Jun. 30, 2016
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: Three Months Ended Six Months Ended (in thousands) 2016 2015 2016 2015 Income Before Income Taxes – Continuing Operations $ 20,639 $ 17,665 $ 40,621 $ 35,519 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 8,049 6,889 15,842 13,852 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,885 ) (1,656 ) (3,571 ) (3,710 ) Corporate Owned Life Insurance (350 ) (40 ) (414 ) (120 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (213 ) (213 ) (425 ) (425 ) Employee Stock Ownership Plan Dividend Deduction (157 ) (171 ) (315 ) (343 ) AFUDC Equity (150 ) (125 ) (187 ) (225 ) Section 199 Domestic Production Activities Deduction (94 ) (363 ) (198 ) (725 ) Investment Tax Credits (87 ) (143 ) (175 ) (286 ) Other Items – Net (30 ) (170 ) 18 63 Income Tax Expense – Continuing Operations $ 5,083 $ 4,008 $ 10,575 $ 8,081 Effective Income Tax Rate – Continuing Operations 24.6 % 22.7 % 26.0 % 22.8 % The following table summarizes the activity related to our unrecognized tax benefits: (in thousands) 2016 2015 Balance on January 1 $ 468 $ 222 Increases Related to Tax Positions for Prior Years — — Increases Related to Tax Positions for Current Year 26 86 Uncertain Positions Resolved During Year — — Balance on June 30 $ 494 $ 308 The balance of unrecognized tax benefits as of June 30, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 30, 2016 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of June 30, 2016. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of June 30, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2012 for federal and North Dakota state income taxes and for tax years prior to 2013 for Minnesota state income taxes.

Discontinued Operations

Discontinued Operations	6 Months Ended
	Jun. 30, 2016
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	16. Discontinued Operations On April 30, 2015 the Company sold Foley Company (Foley), its On February 28, 2015 the Company sold the assets of AEV, Inc. its . On February 8, 2013 the Company completed the sale of substantially all the assets of its former dock and boatlift company and on November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing business. The Company’s Construction and Wind Energy segments were eliminated as a result of the sales of Foley, AEV, Inc. and its former wind tower manufacturing business. The financial position, results of operations and cash flows of Foley, AEV, Inc., the Company’s former dock and boatlift company and its former wind tower manufacturing business are reported as discontinued operations in the Company’s consolidated financial statements. Following are summary presentations of the results of discontinued operations: For the Three Months Ended For the Six Months Ended (in thousands) 2016 2015 2016 2015 Operating Revenues $ — $ 5,899 $ — $ 24,623 Operating Expenses (199 ) 9,209 (249 ) 31,350 Goodwill Impairment Charge — — — 1,000 Operating Income (Loss) 199 (3,310 ) 249 (7,727 ) Other Deductions — (11 ) — (42 ) Income Tax Expense (Benefit) 80 (1,329 ) 100 (2,705 ) Net Income (Loss) from Operations 119 (1,992 ) 149 (5,064 ) (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) $ 119 $ (2,221 ) $ 149 $ 1,933 Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $2.1 million and $4.4 million in the three- and six-month periods ended June 30, 2015, respectively. Following are summary presentations of the major components of liabilities of discontinued operations as of June 30, 2016 and December 31, 2015: (in thousands) June, December 31, Current Liabilities $ 1,868 $ 2,098 Liabilities of Discontinued Operations $ 1,868 $ 2,098 Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow: (in thousands) 2016 2015 Warranty Reserve Balance, January 1 $ 2,103 $ 2,527 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year — (115 ) Decrease in Warranty Estimates for Prior Years (230 ) — Warranty Reserve Balance, June 30 $ 1,873 $ 2,412 The warranty reserve balances as of June 30, 2016 relate entirely to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried one to fifteen year warranties. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
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, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company’s (OTP) 2015 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.
Agreements Subject to Legally Enforceable Netting Arrangements	Agreements Subject to Legally Enforceable Netting Arrangements The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.
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, 2016 and December 31, 2015: June 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,169 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,067 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 835 Total Assets $ 2,835 $ 8,236 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 87 Total Liabilities $ 87 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Forward Gasoline Purchase Contracts Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company
Inventories	Inventories Inventories consist of the following: June 30, December 31, (in thousands) 2016 2015 Finished Goods $ 22,978 $ 25,971 Work in Process 12,133 12,821 Raw Material, Fuel and Supplies 46,285 46,624 Total Inventories $ 81,396 $ 85,416
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The newly acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2015 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table summarizes changes to goodwill by business segment during 2016: (in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572 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 The following table summarizes the components of the Company’s intangible assets at June 30, 2016 and December 31, 2015: June 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,310 $ 15,181 42-230 months Covenant not to Compete 590 164 426 26 months Other Intangible Assets 639 607 32 3 months Emission Allowances — NA — Expensed as used Total $ 23,720 $ 8,081 $ 15,639 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 398 $ 244 $ 755 $ 488 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 17,837 $ 27,267
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 commenced with the initial delivery of coal to Coyote Station 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. 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. Coyote Station started taking delivery of coal and paying for coal and the accumulated development fees and capital charges under the LSA in May 2016. OTP’s 35% share of the unrecovered development period costs, development fees and capital charges incurred by CCMC through June 30, 2016 is $62.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2016 could be as high as $62.5 million.
New Accounting Standards	New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. 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 guidance prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table: (in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683 ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, ASU 2016-02 Leases (Topic 842) leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous leases guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019. ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , but does not expect it to be material.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Schedule of assets and liabilities that are measured at fair value on a recurring basis	June 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,169 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,067 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 835 Total Assets $ 2,835 $ 8,236 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 87 Total Liabilities $ 87 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199
Schedule of inventories	June 30, December 31, (in thousands) 2016 2015 Finished Goods $ 22,978 $ 25,971 Work in Process 12,133 12,821 Raw Material, Fuel and Supplies 46,285 46,624 Total Inventories $ 81,396 $ 85,416
Schedule of changes to goodwill by business segment	(in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572
Schedule of components of intangible assets	June 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,310 $ 15,181 42-230 months Covenant not to Compete 590 164 426 26 months Other Intangible Assets 639 607 32 3 months Emission Allowances — NA — Expensed as used Total $ 23,720 $ 8,081 $ 15,639 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673
Schedule of amortization expense for intangible assets	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 398 $ 244 $ 755 $ 488
Schedule of estimated annual amortization expense for intangible assets	(in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099
Schedule of supplemental disclosure of cash flow information	As of June 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 17,837 $ 27,267
Schedule of effects of applying the guidance and reclassification of unamortized line of credit issuance costs	(in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683

Business Combinations and Seg24

Business Combinations and Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Acquisition And Segment Information [Abstract]
Schedule of business combination disclosing the final allocation of purchase price to each major asset and liability	(in thousands) Assets: Current Assets $ 4,906 Goodwill 6,083 Other Intangible Assets 6,270 Other Amortizable Assets 1,380 Fixed Assets 13,649 Total Assets $ 32,288 Liabilities: Current Liabilities $ 2,971 Lease Obligation 11 Total Liabilities $ 2,982 Cash Paid $ 29,306
Schedule of information by business segments	Operating Revenue Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 97,925 $ 90,964 $ 210,919 $ 204,511 Manufacturing 58,452 51,273 118,272 108,032 Plastics 47,112 45,954 80,549 78,506 Intersegment Eliminations (7 ) (38 ) (16 ) (55 ) Total $ 203,482 $ 188,153 $ 409,724 $ 390,994 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 6,156 $ 6,083 $ 12,440 $ 12,204 Manufacturing 1,006 846 1,998 1,678 Plastics 279 279 523 525 Corporate and Intersegment Eliminations 535 494 1,009 1,038 Total $ 7,976 $ 7,702 $ 15,970 $ 15,445 Income Tax Expense—Continuing Operations Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 1,920 $ 1,013 $ 6,532 $ 5,234 Manufacturing 1,791 1,157 2,810 1,661 Plastics 2,262 2,689 3,629 3,953 Corporate (890 ) (851 ) (2,396 ) (2,767 ) Total $ 5,083 $ 4,008 $ 10,575 $ 8,081 Net Income (Loss) Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2016 2015 2016 2015 Electric $ 9,148 $ 8,252 $ 21,686 $ 21,430 Manufacturing 3,009 1,912 4,862 3,096 Plastics 3,485 4,265 5,637 6,385 Corporate (86 ) (772 ) (2,139 ) (3,473 ) Discontinued Operations 119 (2,221 ) 149 1,933 Total $ 15,675 $ 11,436 $ 30,195 $ 29,371 Identifiable Assets June 30, December 31, (in thousands) 2016 2015 Electric $ 1,553,563 $ 1,520,887 Manufacturing 179,971 173,860 Plastics 89,058 81,624 Corporate 39,311 42,312 Total $ 1,861,903 $ 1,818,683

Rate and Regulatory Matters (Ta

Rate and Regulatory Matters (Tables)	6 Months Ended
	Jun. 30, 2016
Rate and Regulatory Matters [Abstract]
Schedule of request and interim rate information	The request and interim rate information is detailed in the table below: Annualized or Actual Through June 30, 2016 ($ in thousands) Test Year 3 Months Ended 6 Months Ended Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 2,850 $ 2,850 The major components of the requested rate increase are summarized below: Revenue Requirement Deficiency Cost Factors (in thousands) 2016 Test Year Increased Rate Base $ 10,000 Increased Expenses 7,700 Other 1,596 Total Requested Revenue Increase $ 19,296 Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset (2,480 ) Approved Interim Revenue Increase (subject to refund) $ 16,816
Schedule of revenues recorded under rate riders	Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2016 2015 2016 2015 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,209 $ 1,610 $ 4,715 $ 3,538 Transmission Cost Recovery 1,133 1,212 3,409 2,827 Environmental Cost Recovery 3,153 2,600 6,235 5,157 North Dakota Renewable Resource Adjustment 1,922 1,942 3,981 3,825 Transmission Cost Recovery 1,969 1,411 4,205 3,347 Environmental Cost Recovery 2,771 2,765 5,582 4,921 South Dakota Transmission Cost Recovery 411 281 1,062 644 Environmental Cost Recovery 627 519 1,260 1,023 Conservation Improvement Program Costs and Incentives 124 90 283 230 1

Regulatory Assets and Liabili26

Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of amount of regulatory assets and liabilities	June 30, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 96,523 $ 103,962 see below Deferred Marked-to-Market Losses 1 4,063 8,499 12,562 54 months Conservation Improvement Program Costs and Incentives 2 1,313 6,016 7,329 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,911 5,911 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 648 2,646 3,294 58 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,894 684 2,578 21 months Debt Reacquisition Premiums 1 351 1,364 1,715 195 months Deferred Income Taxes 1 — 1,247 1,247 asset lives MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 616 166 782 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 593 693 83 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 458 — 458 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 323 — 323 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 57 57 15 months Total Regulatory Assets $ 17,205 $ 123,706 $ 140,911 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 76,196 76,196 asset lives Refundable Fuel Clause Adjustment Revenues 2,619 — 2,619 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 712 563 1,275 22 months Deferred Income Taxes — 978 978 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 700 — 700 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 644 — 644 12 months Minnesota Transmission Cost Recovery Rider Accrued Refund 642 — 642 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 609 — 609 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 334 — 334 12 months Other 31 92 123 210 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 86 86 24 months Total Regulatory Liabilities $ 6,291 $ 77,915 $ 84,206 Net Regulatory Asset Position $ 10,914 $ 45,791 $ 56,705 1 2 December 31, 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 $ 7,439 $ 99,293 $ 106,732 see below Deferred Marked-to-Market Losses 1 4,063 10,530 14,593 60 months Conservation Improvement Program Costs and Incentives 2 4,411 4,266 8,677 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,672 5,672 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 942 2,620 3,562 84 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Deferred Income Taxes 1 — 1,455 1,455 asset lives North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Total Regulatory Assets $ 18,904 $ 127,707 $ 146,611 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 74,948 $ 74,948 asset lives Refundable Fuel Clause Adjustment Revenues 1,834 — 1,834 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota — 1,279 1,279 see below Deferred Income Taxes — 1,110 1,110 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Renewable Resource Rider Accrued Refund 68 — 68 12 months Total Regulatory Liabilities $ 3,322 $ 77,432 $ 80,754 Net Regulatory Asset Position $ 15,582 $ 50,275 $ 65,857 1 2

Open Contract Positions Subje27

Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables)	6 Months Ended
	Jun. 30, 2016
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]
Schedule of derivative asset and liability balances subject to legally enforceable netting arrangements	(in thousands) June 30, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (14,419 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (14,419 ) $ (16,070 )
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions	Loss Position (in thousands) June 30 , 2016 December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 87 $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,332 15,871 Loss Contracts with No Ratings Triggers or Deposit Requirements — — Loss Position $ 14,419 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,332 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 14,332 $ 15,871

Reconciliation of Common Shar28

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2016
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, 2015 $ 189,286 $ 293,610 $ 126,025 $ (3,898 ) $ 605,023 Common Stock Issuances, Net of Expenses 4,249 19,486 23,735 Common Stock Retirements (19 ) (85 ) (104 ) Net Income 30,195 30,195 Other Comprehensive Income 250 250 Employee Stock Incentive Plans Expense 828 828 Common Dividends ($0.625 per share) (23,819 ) (23,819 ) Balance, June 30, 2016 $ 193,516 $ 313,839 $ 132,401 $ (3,648 ) $ 636,108
Schedule of common shares outstanding from December 31, 2015 through March 31, 2016	Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 510,139 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 93,171 Cash Invested 69,740 Executive Stock Performance Awards (2013 and 2014 shares earned) 54,700 Employee Stock Purchase Plan: Cash Invested 39,938 Dividends Reinvested 13,467 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,025 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, June 30, 2016 38,703,277
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted	Three Months ended Six Months ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 38,179,371 37,433,318 38,058,157 37,338,218 Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance 91,381 141,540 69,133 141,540 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 39,374 45,060 39,608 45,060 Nonvested Restricted Shares 7,862 31,079 12,819 31,079 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,301 2,206 3,532 2,206 Total Dilutive Shares 141,918 219,885 125,092 219,885 Weighted Average Common Shares Outstanding – Diluted 38,321,289 37,653,203 38,183,249 37,558,103

Share-Based Payments (Tables)

Share-Based Payments (Tables)	6 Months Ended
	Jun. 30, 2016
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Schedule of stock incentive awards granted	Award Shares/ Grant-Date Vesting Stock Performance Awards Granted to Executive Officers 81,500 $ 24.03 December 31, 2018 Restricted Stock Units Granted to Executive Officers 22,000 $ 28.915 25% per year through February 6, 2020 Award Shares/ Grant-Date Vesting Restricted Stock Granted to Nonemployee Directors 23,200 $ 28.66 25% per year through April 8, 2020 Restricted Stock Units Granted to Key Employees 15,800 $ 24.00 100% on April 8, 2020
Schedule of compensation expense under stock-based payment programs	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Stock Performance Awards Granted to Executive Officers $ 304 $ 37 $ 841 $ 1,057 Restricted Stock Units Granted to Executive Officers 64 127 309 380 Restricted Stock Granted to Executive Officers 22 144 51 301 Restricted Stock Granted to Directors 128 106 235 204 Restricted Stock Units Granted to Nonexecutive Employees 81 81 145 147 Employee Stock Purchase Plan (15% discount) 44 45 88 94 Totals $ 643 $ 540 $ 1,669 $ 2,183

Short-Term and Long-Term Borr30

Short-Term and Long-Term Borrowings (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of lines of credit	(in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ 19,289 $ — $ 130,711 $ 90,334 OTP Credit Agreement 170,000 29,985 50 139,965 148,694 Total $ 320,000 $ 49,274 $ 50 $ 270,676 $ 239,028
Schedule of short-term and long-term debt outstanding	June 30, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 29,985 $ 19,289 $ 49,274 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 Term Loan, LIBOR plus 0.90%, due February 5, 2018 50,000 50,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 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 145 145 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 908 908 Total $ 445,000 $ 103,383 $ 548,383 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,497 52,497 Unamortized Long-Term Debt Issuance Costs 1,980 102 2,082 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 443,020 $ 50,784 $ 493,804 Total Short-Term and Long-Term Debt (with current maturities) $ 473,005 $ 122,570 $ 595,575 December 31, 2015 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 21,006 $ 59,666 $ 80,672 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 182 182 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 977 977 Total $ 445,000 $ 53,489 $ 498,489 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,422 52,422 Unamortized Long-Term Debt Issuance Costs 2,099 122 2,221 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 442,901 $ 945 $ 443,846 Total Short-Term and Long-Term Debt (with current maturities) $ 463,907 $ 113,033 $ 576,940

Pension Plan and Other Postre31

Pension Plan and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2016
Pension Plan
Schedule of components of net periodic postretirement benefit cost	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 1,381 $ 1,530 $ 2,763 $ 3,030 Interest Cost on Projected Benefit Obligation 3,521 3,347 7,043 6,672 Expected Return on Assets (4,866 ) (4,592 ) (9,733 ) (9,192 ) Amortization of Prior-Service Cost: From Regulatory Asset 47 47 94 94 From Other Comprehensive Income 1 1 1 2 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,227 1,705 2,454 3,338 From Other Comprehensive Income 1 32 46 63 86 Net Periodic Pension Cost $ 1,343 $ 2,084 $ 2,686 $ 4,030 1
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) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 63 $ 47 $ 126 $ 94 Interest Cost on Projected Benefit Obligation 417 381 834 762 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 10 9 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 73 84 146 167 From Other Comprehensive Income 2 111 150 223 301 Net Periodic Pension Cost $ 678 $ 675 $ 1,356 $ 1,351 1 Electric Operation and Maintenance Expenses $ 4 $ 4 $ 8 $ 8 Other Nonelectric Expenses 6 5 11 11 2 Electric Operation and Maintenance Expenses $ 68 $ 77 $ 136 $ 155 Other Nonelectric Expenses 43 73 87 146
Postretirement Benefits
Schedule of components of net periodic postretirement benefit cost	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 305 $ 273 $ 611 $ 648 Interest Cost on Projected Benefit Obligation 542 499 1,083 1,049 Amortization of Prior-Service Cost: From Regulatory Asset 33 51 66 102 From Other Comprehensive Income 1 1 2 2 3 Amortization of Net Actuarial Loss: From Regulatory Asset — (48 ) — — From Other Comprehensive Income 1 — (1 ) — — Net Periodic Postretirement Benefit Cost $ 881 $ 776 $ 1,762 $ 1,802 Effect of Medicare Part D Subsidy $ (258 ) $ (293 ) $ (515 ) $ (743 ) 1

Fair Value of Financial Instr32

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of long-term debt including current maturities	June 30, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (49,274 ) (49,274 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (546,301 ) (641,722 ) (496,268 ) (561,245 )

Income Tax Expense - Continuing

Income Tax Expense - Continuing Operations (Tables)	6 Months Ended
	Jun. 30, 2016
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) 2016 2015 2016 2015 Income Before Income Taxes – Continuing Operations $ 20,639 $ 17,665 $ 40,621 $ 35,519 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 8,049 6,889 15,842 13,852 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,885 ) (1,656 ) (3,571 ) (3,710 ) Corporate Owned Life Insurance (350 ) (40 ) (414 ) (120 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (213 ) (213 ) (425 ) (425 ) Employee Stock Ownership Plan Dividend Deduction (157 ) (171 ) (315 ) (343 ) AFUDC Equity (150 ) (125 ) (187 ) (225 ) Section 199 Domestic Production Activities Deduction (94 ) (363 ) (198 ) (725 ) Investment Tax Credits (87 ) (143 ) (175 ) (286 ) Other Items – Net (30 ) (170 ) 18 63 Income Tax Expense – Continuing Operations $ 5,083 $ 4,008 $ 10,575 $ 8,081 Effective Income Tax Rate – Continuing Operations 24.6 % 22.7 % 26.0 % 22.8 %
Schedule of activity related to unrecognized tax benefits	(in thousands) 2016 2015 Balance on January 1 $ 468 $ 222 Increases Related to Tax Positions for Prior Years — — Increases Related to Tax Positions for Current Year 26 86 Uncertain Positions Resolved During Year — — Balance on June 30 $ 494 $ 308

Discontinued Operations (Tables

Discontinued Operations (Tables)	6 Months Ended
	Jun. 30, 2016
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	Following are summary presentations of the results of discontinued operations: For the Three Months Ended For the Six Months Ended (in thousands) 2016 2015 2016 2015 Operating Revenues $ — $ 5,899 $ — $ 24,623 Operating Expenses (199 ) 9,209 (249 ) 31,350 Goodwill Impairment Charge — — — 1,000 Operating Income (Loss) 199 (3,310 ) 249 (7,727 ) Other Deductions — (11 ) — (42 ) Income Tax Expense (Benefit) 80 (1,329 ) 100 (2,705 ) Net Income (Loss) from Operations 119 (1,992 ) 149 (5,064 ) (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) $ 119 $ (2,221 ) $ 149 $ 1,933 Following are summary presentations of the major components of liabilities of discontinued operations as of June 30, 2016 and December 31, 2015: (in thousands) June, December 31, Current Liabilities $ 1,868 $ 2,098 Liabilities of Discontinued Operations $ 1,868 $ 2,098
Schedule of warranty reserves	(in thousands) 2016 2015 Warranty Reserve Balance, January 1 $ 2,103 $ 2,527 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year — (115 ) Decrease in Warranty Estimates for Prior Years (230 ) — Warranty Reserve Balance, June 30 $ 1,873 $ 2,412

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, 2016	Dec. 31, 2015
Level 1
Assets:
Total Assets	$ 2,835	$ 2,196
Level 1 | Money Market Deposit Escrow
Assets:
Money Market Escrow Accounts - AEV, Inc. and Foley Company Sales	2,000	2,000
Level 1 | Money Market and Mutual Funds
Assets:
Other Assets - Nonqualified Retirement Savings Plan	835	196
Level 2
Assets:
Total Assets	8,236	8,093
Liabilities:
Total Liabilities	87	199
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities
Assets:
Investments - Held by Captive Insurance Company	4,067	4,235
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	4,169	3,858
Level 2 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities	$ 87	$ 199

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Inventories (Details 1) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Finished Goods	$ 22,978	$ 25,971
Work in Process	12,133	12,821
Raw Material, Fuel and Supplies	46,285	46,624
Total Inventories	$ 81,396	$ 85,416

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 2) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)
Goodwill [Roll Forward]
Gross Balance December 31, 2015	$ 39,732
Accumulated Impairments
Balance (net of impairments) December 31, 2015	39,732
Adjustments to Goodwill in 2016	(2,160)
Balance (net of impairments) June 30, 2016	37,572
Manufacturing
Goodwill [Roll Forward]
Gross Balance December 31, 2015	20,430
Accumulated Impairments
Balance (net of impairments) December 31, 2015	20,430
Adjustments to Goodwill in 2016	(2,160)
Balance (net of impairments) June 30, 2016	18,270
Plastics
Goodwill [Roll Forward]
Gross Balance December 31, 2015	19,302
Accumulated Impairments
Balance (net of impairments) December 31, 2015	19,302
Adjustments to Goodwill in 2016
Balance (net of impairments) June 30, 2016	$ 19,302

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Components of intangible assets (Details 3) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Amortizable Intangible Assets:
Gross Carrying Amount	$ 23,720	$ 22,999
Accumulated Amortization	8,081	7,326
Net Carrying Amount	15,639	15,673
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	22,491	21,681
Accumulated Amortization	7,310	6,714
Net Carrying Amount	$ 15,181	$ 14,967
Customer Relationships | Minimum
Amortizable Intangible Assets:
Remaining Amortization Periods	42 months	48 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Remaining Amortization Periods	230 months	236 months
Covenant not to Compete
Amortizable Intangible Assets:
Gross Carrying Amount	$ 590	$ 620
Accumulated Amortization	164	69
Net Carrying Amount	$ 426	$ 551
Remaining Amortization Periods	26 months	32 months
Other Intangible Assets
Amortizable Intangible Assets:
Gross Carrying Amount	$ 639	$ 639
Accumulated Amortization	607	543
Net Carrying Amount	$ 32	$ 96
Remaining Amortization Periods	3 months	9 months
Emission Allowances
Amortizable Intangible Assets:
Gross Carrying Amount		$ 59
Accumulated Amortization
Net Carrying Amount		$ 59

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 4) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 398	$ 244	$ 755	$ 488

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 5) $ in Thousands	Jun. 30, 2016USD ($)
Accounting Policies [Abstract]
2,016	$ 1,436
2,017	1,330
2,018	1,264
2,019	1,133
2,020	$ 1,099

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 6) - USD ($) $ in Thousands	Jun. 30, 2016	Jun. 30, 2015
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$ 17,837	$ 27,267

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Effect of applying the guidance in ASU 2015-17 retrospectively to consolidated balance sheet (Details 7) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Assets	$ 33,605	$ 32,784
Unamortized Debt Expense
Total Assets	1,861,903	1,818,683
Current Liabilities
Current Maturities of Long-Term Debt	52,497	52,422
Total Current Liabilities	233,136	271,116
Capitalization
Long-Term Debt - Net	493,804	443,846
Total Capitalization	1,129,912	1,048,869
Total Liabilities and Equity	$ 1,861,903	1,818,683
Previously Stated
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Assets		31,108
Unamortized Debt Expense		3,897
Total Assets		1,820,904
Current Liabilities
Current Maturities of Long-Term Debt		52,544
Total Current Liabilities		271,238
Capitalization
Long-Term Debt - Net		445,945
Total Capitalization		1,050,968
Total Liabilities and Equity		1,820,904
Adjustments
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Assets		1,676
Unamortized Debt Expense		(3,897)
Total Assets		(2,221)
Current Liabilities
Current Maturities of Long-Term Debt		(122)
Total Current Liabilities		(122)
Capitalization
Long-Term Debt - Net		(2,099)
Total Capitalization		(2,099)
Total Liabilities and Equity		$ (2,221)

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Detail Textuals) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)
Significant Accounting Policies [Line Items]
Acquired goodwill	$ 8,200
Reduction in goodwill	$ 2,160
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	$ 62,500
Maximum exposure to loss as a result of involvement with CCMC	$ 62,500

Business Combinations and Seg44

Business Combinations and Segment Information - Summary of major asset and liability category of BTD Georgia (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets:
Goodwill	$ 37,572	$ 39,732
BTD-Georgia
Assets:
Current Assets	4,906
Goodwill	6,083
Other Intangible Assets	6,270
Other Amortizable Assets	1,380
Fixed Assets	13,649
Total Assets	32,288
Liabilities:
Current Liabilities	2,971
Lease Obligation	11
Total Liabilities	2,982
Cash Paid	$ 29,306

Business Combinations and Seg45

Business Combinations and Segment Information - Information on continuing operations for business segments (Details 1) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Operating Revenue	$ 203,482	$ 188,153	$ 409,724	$ 390,994
Interest Charges	7,976	7,702	15,970	15,445
Income Tax Expense - Continuing Operations	5,083	4,008	10,575	8,081
Net Income (Loss)	15,675	11,436	30,195	29,371
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(7)	(38)	(16)	(55)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	535	494	1,009	1,038
Corporate
Segment Reporting Information [Line Items]
Income Tax Expense - Continuing Operations	(890)	(851)	(2,396)	(2,767)
Net Income (Loss)	(86)	(772)	(2,139)	(3,473)
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income (Loss)	119	(2,221)	149	1,933
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	97,925	90,964	210,919	204,511
Interest Charges	6,156	6,083	12,440	12,204
Income Tax Expense - Continuing Operations	1,920	1,013	6,532	5,234
Net Income (Loss)	9,148	8,252	21,686	21,430
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	58,452	51,273	118,272	108,032
Interest Charges	1,006	846	1,998	1,678
Income Tax Expense - Continuing Operations	1,791	1,157	2,810	1,661
Net Income (Loss)	3,009	1,912	4,862	3,096
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	47,112	45,954	80,549	78,506
Interest Charges	279	279	523	525
Income Tax Expense - Continuing Operations	2,262	2,689	3,629	3,953
Net Income (Loss)	$ 3,485	$ 4,265	$ 5,637	$ 6,385

Business Combinations and Seg46

Business Combinations and Segment Information - Total assets by business segment (Details 2) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 1,861,903	$ 1,818,683
Corporate
Segment Reporting Information [Line Items]
Assets	39,311	42,312
Electric | Operating Segments
Segment Reporting Information [Line Items]
Assets	1,553,563	1,520,887
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Assets	179,971	173,860
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Assets	$ 89,058	$ 81,624

Business Combinations and Seg47

Business Combinations and Segment Information (Detail Textuals) - USD ($) $ in Thousands	Sep. 01, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Business Acquisition [Line Items]
Cash				$ (1,500)
Reduction in goodwill				$ 2,160
Operating revenues | UNITED STATES
Business Acquisition [Line Items]
Operating revenues, percentage		98.50%	97.30%	98.70%	96.80%
BTD-Georgia
Business Acquisition [Line Items]
Cash	$ 30,800			$ 29,300
Post closing reduction in purchase price				1,500
Reduction in goodwill				2,200
Amount of increase in customer relationships				800
Amount of increase in liabilities				$ 100

Business Combinations and Seg48

Business Combinations and Segment Information (Detail Textuals 1)	6 Months Ended
	Jun. 30, 2016Segment
Acquisition And Segment Information [Abstract]
Number of reportable segments	3

Rate and Regulatory Matters - S

Rate and Regulatory Matters - Summary of interim rate information (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2016
Public Utilities, General Disclosures [Line Items]
Interim Revenue Increase (subject to refund)	$ 2,850	$ 2,850
2016 Test Year Allocation
Public Utilities, General Disclosures [Line Items]
Revenue Increase Requested		$ 19,296
Increase Percentage Requested		9.80%
Jurisdictional Rate Base		$ 483,000
Interim Revenue Increase (subject to refund)		$ 16,816

Rate and Regulatory Matters -50

Rate and Regulatory Matters - Summary components of the requested rate increase (Details 1) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2016
Public Utilities, Rate Matters [Abstract]
Approved Interim Revenue Increase (subject to refund), Amount	$ 2,850	$ 2,850
2016 Test Year Allocation
Public Utilities, Rate Matters [Abstract]
Total Requested Revenue Increase, Amount		19,296
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset, Amount		(2,480)
Approved Interim Revenue Increase (subject to refund), Amount		16,816
2016 Test Year Allocation | Increased Rate Base
Public Utilities, Rate Matters [Abstract]
Total Requested Revenue Increase, Amount		10,000
2016 Test Year Allocation | Increased Expenses
Public Utilities, Rate Matters [Abstract]
Total Requested Revenue Increase, Amount		7,700
2016 Test Year Allocation | Other
Public Utilities, Rate Matters [Abstract]
Total Requested Revenue Increase, Amount		$ 1,596

Rate and Regulatory Matters -51

Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 2) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Regulatory Matters [Line Items]
Revenues recorded under rate riders		$ 203,482	$ 188,153	$ 409,724	$ 390,994
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenues recorded under rate riders	[1]	2,209	1,610	4,715	3,538
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,133	1,212	3,409	2,827
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		3,153	2,600	6,235	5,157
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,922	1,942	3,981	3,825
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		1,969	1,411	4,205	3,347
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		2,771	2,765	5,582	4,921
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenues recorded under rate riders		124	90	283	230
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		411	281	1,062	644
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues recorded under rate riders		$ 627	$ 519	$ 1,260	$ 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
	Jun. 30, 2016USD ($)kVmi
Otter Tail Power Company | Big Stone South - Brookings MVP
Regulatory Matters [Line Items]
Project costs incurred to date | $	$ 43
Percentage of assets of project	100.00%
Expanded capacity of projects | kV	345
Extended distance of transmission line | mi	70
Otter Tail Power Company | Big Stone South - Ellendale MVP | Minimum
Regulatory Matters [Line Items]
Extended distance of transmission line | mi	160
Otter Tail Power Company | Big Stone South - Ellendale MVP | Maximum
Regulatory Matters [Line Items]
Extended distance of transmission line | mi	170
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Project costs incurred to date | $	$ 29.8
Percentage of assets of project	100.00%
Expanded capacity of projects | kV	345
Big Stone AQCS Project BART - compliant AQCS
Regulatory Matters [Line Items]
Project costs incurred to date | $	$ 199
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest | $	$ 26
Percentage of ownership interest acquired in transmission line	4.80%
Distance of transmission line | mi	250
Capacity Expansion 2020 | Otter Tail Power Company | Fargo-Monticello Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest | $	$ 81
Percentage of ownership interest acquired in transmission line	14.20%
Distance of transmission line | mi	240
Percentage of assets of project	100.00%

Rate and Regulatory Matters (53

Rate and Regulatory Matters (Detail Textuals 1) - Otter Tail Power Company - Minnesota Public Utilities Commission - USD ($) $ in Millions	1 Months Ended				12 Months Ended
	Feb. 16, 2016	Dec. 21, 2015	Sep. 30, 2015	Apr. 25, 2011	Dec. 31, 2015	May 25, 2016	Apr. 14, 2016	Apr. 01, 2016	Jul. 09, 2015
Conservation Improvement Program
Regulatory Matters [Line Items]
Financial incentives recognized during period					$ 4.2
Amount of financial incentive requested								$ 4.3
Percentage Increase In Energy Savings					39.00%
Incentives net benefit, 2017						13.50%
Incentives net benefit, 2018						12.00%
Incentives net benefit, 2019						10.00%
Assumed savings of utility						1.70%
Percentage of reduction in financial incentive						50.00%
Conservation Improvement Program | Fiscal Year 2014
Regulatory Matters [Line Items]
Financial incentive request approved									$ 3
Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Seeking revenue recovery		$ 7.2	$ 7.8
2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase requested				$ 5
Percentage of increase in base rate revenue requested				1.60%
Public utilities allowed rate of return on rate base prior to approval of increase in base rate				8.33%
Public utilities allowed rate of return on rate base 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%
2016 General Rate Case
Regulatory Matters [Line Items]
Public Utilities Allowed Rate Of Return On Rate Base	8.07%
Public Utilities Allowed Rate Of Return On Equity Increase In Base Rate	10.40%
Percentage Of Capital	52.50%
Increase to base rate portion of customer bills							9.56%

Rate and Regulatory Matters (54

Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - USD ($) $ in Millions	1 Months Ended			13 Months Ended
	Aug. 31, 2015	Jul. 01, 2015	Mar. 31, 2015	Mar. 31, 2016	Jun. 22, 2016	Nov. 25, 2009
Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Jurisdictional capital and operating costs recovery	$ 8.5
Transmission Cost Recovery Rider | Fiscal Year 2016
Regulatory Matters [Line Items]
Jurisdictional capital and operating costs recovery	$ 10.2
Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Percentage of ECR rider rate		9.193%	7.531%	7.904%
Over collection of Big stone II abandoned plant costs		$ 12.2		$ 10.4
Renewable Resource Adjustment
Regulatory Matters [Line Items]
Percentage of allowed rate of return on equity					10.50%
2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority						$ 3.6
Percentage of increase in base rate revenue requested						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 (55

Rate and Regulatory Matters (Detail Textuals 3) - USD ($) $ in Thousands

Feb. 12, 2015

Nov. 06, 2014

Nov. 12, 2013

Dec. 22, 2015

Aug. 31, 2015

Apr. 21, 2011

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Dec. 31, 2015

Jan. 01, 2012

Regulatory Matters [Line Items]

Regulatory Liabilities

$ 84,206

$ 84,206

$ 80,754

Otter Tail Power Company | South Dakota Public Utilities Commission | Environmental Cost Recovery Rider

Regulatory Matters [Line Items]

Annual revenue requesting recovery

$ 2,700

Otter Tail Power Company | 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 requested

2.32%

Public utilities allowed rate of return on rate base subsequent to approval of increase in base rate

8.50%

Otter Tail Power Company | Federal Energy Regulatory Commission

Regulatory Matters [Line Items]

Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate

100.00%

Current return on equity used in transmission rates

12.38%

10.32%

Proposed reduced return on equity used in transmission rates

8.67%

9.15%

Additional Incentive Basis Point

50-basis points

Reductions in revenue

$ 1,000

$ 200

$ 1,300

$ 800

Expected percentage of return on equity

9.70%

9.70%

Regulatory Liabilities

$ 2,400

$ 2,400

Regulatory Assets and Liabili56

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, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		$ 17,205	$ 18,904
Regulatory Liability - Current		6,291	3,322
Net Regulatory Assets Position - Current		10,914	15,582
Regulatory Assets - Long-Term		123,706	127,707
Regulatory Liabilities - Long-Term		77,915	77,432
Net Regulatory Asset Position - Long-Term		45,791	50,275
Regulatory Assets - Total		140,911	146,611
Regulatory Liabilities - Total		84,206	80,754
Net Regulatory Asset Position - Total		56,705	65,857
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	7,439	7,439
Regulatory Assets - Long-Term	[1]	96,523	99,293
Regulatory Assets - Total	[1]	$ 103,962	$ 106,732
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]	$ 4,063	$ 4,063
Regulatory Assets - Long-Term	[1]	8,499	10,530
Regulatory Assets - Total	[1]	$ 12,562	$ 14,593
Regulatory Assets - Remaining Recovery/Refund Period	[1]	54 months	60 months
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 1,313	$ 4,411
Regulatory Assets - Long-Term	[2]	6,016	4,266
Regulatory Assets - Total	[2]	$ 7,329	$ 8,677
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]	5,911	5,672
Regulatory Assets - Total	[1]	$ 5,911	$ 5,672
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]	$ 648	$ 942
Regulatory Assets - Long-Term	[1]	2,646	2,620
Regulatory Assets - Total	[1]	$ 3,294	$ 3,562
Regulatory Assets - Remaining Recovery/Refund Period	[1]	58 months	84 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]		$ 576
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]		$ 576
Regulatory Assets - Remaining Recovery/Refund Period	[2]		12 months
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 1,894
Regulatory Assets - Long-Term	[2]	684	1,266
Regulatory Assets - Total	[2]	$ 2,578	$ 1,266
Regulatory Assets - Remaining Recovery/Refund Period	[2]	21 months	15 months
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 351	$ 351
Regulatory Assets - Long-Term	[1]	1,364	1,539
Regulatory Assets - Total	[1]	$ 1,715	$ 1,890
Regulatory Assets - Remaining Recovery/Refund Period	[1]	195 months	201 months
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	[1]	1,247	1,455
Regulatory Liabilities - Long-Term		978	1,110
Regulatory Assets - Total	[1]	1,247	1,455
Regulatory Liabilities - Total		$ 978	$ 1,110
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 616	$ 698
Regulatory Liability - Current
Regulatory Assets - Long-Term	[2]	166	355
Regulatory Liabilities - Long-Term		86
Regulatory Assets - Total	[2]	782	$ 1,053
Regulatory Liabilities - Total		$ 86
Regulatory Assets - Remaining Recovery/Refund Period	[2]	24 months	24 months
Regulatory Liabilities - Remaining Recovery/Refund Period		24 months
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]	593	643
Regulatory Assets - Total	[2]	$ 693	$ 743
Regulatory Assets - Remaining Recovery/Refund Period	[2]	83 months	89 months
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 644	$ 777
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 644	$ 777
Regulatory Liabilities - Remaining Recovery/Refund Period		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]	57	68
Regulatory Assets - Total	[2]	$ 57	$ 68
Regulatory Assets - Remaining Recovery/Refund Period	[2]		see below
Regulatory Assets - Remaining Recovery/Refund Period	[2]	15 months
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term		76,196	74,948
Regulatory Liabilities - Total		$ 76,196	$ 74,948
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			$ 68
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			$ 68
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Revenue for Rate Case expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 712
Regulatory Liabilities - Long-Term		563	1,279
Regulatory Liabilities - Total		$ 1,275	$ 1,279
Regulatory Liabilities - Remaining Recovery/Refund Period			see below
Regulatory Liabilities - Remaining Recovery/Refund Period		22 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			$ 5
Regulatory Liabilities - Long-Term			95
Regulatory Liabilities - Total			$ 100
Regulatory Liabilities - Remaining Recovery/Refund Period			216 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 334	$ 185
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 334	$ 185
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
Minnesota Deferred Rate Case Expenses Subject to Recovery
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[1]	$ 458	$ 291
Regulatory Assets - Long-Term	[1]
Regulatory Assets - Total	[1]	$ 458	$ 291
Regulatory Assets - Remaining Recovery/Refund Period	[1]	12 months	12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	[2]	$ 323	$ 33
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]	$ 323	$ 33
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months	12 months
Refundable Fuel Clause Adjustment Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 2,619	$ 1,834
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 2,619	$ 1,834
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 700	$ 132
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 700	$ 132
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 609	$ 321
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 609	$ 321
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
Minnesota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 642
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 642
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
Other
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current		$ 31
Regulatory Liabilities - Long-Term		92
Regulatory Liabilities - Total		$ 123
Regulatory Liabilities - Remaining Recovery/Refund Period		210 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 Liabili57

Regulatory Assets and Liabilities (Detail Textuals)	6 Months Ended
	Jun. 30, 2016
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	195 months

Open Contract Positions Subje58

Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details) - Legally enforceable netting arrangements - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements	(14,419)	(16,070)
Net Balance Subject to Legally Enforceable Netting Arrangements	$ (14,419)	$ (16,070)

Open Contract Positions Subje59

Open Contract Positions Subject to Legally Enforceable Netting Arrangements - 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, 2016	Dec. 31, 2015
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit		$ 87	$ 199
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	14,332	15,871
Loss Contracts with No Ratings Triggers or Deposit Requirements
Loss Position		$ 14,419	$ 16,070
[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 14,332 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered 14,332 15,871

Open Contract Positions Subje60

Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parenthetical) (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 14,332	$ 15,871
Offsetting Gains with Counterparties under Master Netting Agreements
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$ 14,332	$ 15,871
[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 14,332 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered 14,332 15,871

Reconciliation of Common Shar61

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2015			$ 605,023
Common Stock Issuances, Net of Expenses			23,735
Common Stock Retirements			(104)
Net Income	$ 15,675	$ 11,436	30,195	$ 29,371
Other Comprehensive Income			250
Employee Stock Incentive Plans Expense			828
Common Dividends ($0.625 per share)			(23,819)
Balance, June 30, 2016	636,108		636,108
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2015			189,286
Common Stock Issuances, Net of Expenses			4,249
Common Stock Retirements			(19)
Balance, June 30, 2016	193,516		193,516
Premium on Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2015			293,610
Common Stock Issuances, Net of Expenses			19,486
Common Stock Retirements			(85)
Employee Stock Incentive Plans Expense			828
Balance, June 30, 2016	313,839		313,839
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2015			126,025
Net Income			30,195
Common Dividends ($0.625 per share)			(23,819)
Balance, June 30, 2016	132,401		132,401
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2015			(3,898)
Other Comprehensive Income			250
Balance, June 30, 2016	$ (3,648)		$ (3,648)

Reconciliation of Common Shar62

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$ 0.3125	$ 0.3075	$ 0.625	$ 0.6150

Reconciliation of Common Shar63

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1)	6 Months Ended
	Jun. 30, 2016shares
Schedule Of Common Stock Outstanding [Roll Forward]
Common Shares Outstanding, December 31, 2015	37,857,186
Issuances:
At-the-Market Offering	510,139
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	93,171
Cash Invested	69,740
Executive Stock Performance Awards (2013 and 2014 shares earned)	54,700
Employee Stock Purchase Plan:
Cash Invested	39,938
Dividends Reinvested	13,467
Employee Stock Ownership Plan	23,837
Restricted Stock Issued to Directors	23,200
Vesting of Restricted Stock Units	21,025
Directors Deferred Compensation	542
Retirements:
Shares Withheld for Individual Income Tax Requirements	(3,668)
Common Shares Outstanding, June 30, 2016	38,703,277

Reconciliation of Common Shar64

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	38,179,371	37,433,318	38,058,157	37,338,218
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance	91,381	141,540	69,133	141,540
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	39,374	45,060	39,608	45,060
Nonvested Restricted Shares	7,862	31,079	12,819	31,079
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	3,301	2,206	3,532	2,206
Total Dilutive Shares	141,918	219,885	125,092	219,885
Weighted Average Common Shares Outstanding - Diluted	38,321,289	37,653,203	38,183,249	37,558,103

Reconciliation of Common Shar65

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	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)	6 Months Ended
	Jun. 30, 2016$ / sharesshares
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Percentage	25.00%
Restricted Stock Units | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted | shares	22,000
Grant-Date Fair Value per Award | $ / shares	$ 28.915
Vesting Percentage	25.00%
Vesting Date	February 6, 2020
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted | shares	81,500
Grant-Date Fair Value per Award | $ / shares	$ 24.03
Vesting Date	December 31, 2018

Share-Based Payments - Stock 67

Share-Based Payments - Stock incentive awards to non-employee directors and key employees (Details 1)	6 Months Ended
	Jun. 30, 2016$ / sharesshares
Restricted Stock
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Vesting Percentage	25.00%
Restricted Stock | Nonemployee Directors
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Shares/Units Granted | shares	23,200
Grant-Date Fair Value per Award | $ / shares	$ 28.66
Vesting Percentage	25.00%
Vesting Date	April 8, 2020
Restricted Stock Units
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Vesting Percentage	25.00%
Restricted Stock Units | Key Employees
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Shares/Units Granted | shares	15,800
Grant-Date Fair Value per Award | $ / shares	$ 24
Vesting Percentage	100.00%
Vesting Date	April 8, 2020

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 643	$ 540	$ 1,669	$ 2,183
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	304	37	841	1,057
Restricted Stock Units (RSUs) | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	64	127	309	380
Restricted Stock Units (RSUs) | Nonexecutive Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	81	81	145	147
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	22	144	51	301
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	128	106	235	204
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 44	$ 45	$ 88	$ 94

Share-Based Payments - Amount69

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details 2)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
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) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to stock-based compensation | $	$ 4.9
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	81,500
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 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate common shares award	122,250
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate common shares award	81,500
Targeted aggregate common shares award total shareholder return component	54,333
Targeted aggregate common shares award return on equity component	27,167
Period specified for average adjusted return	3 years
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Percentage	25.00%
Restricted Stock Units | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate common shares award	22,000
Vesting Percentage	25.00%
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Percentage	25.00%

Retained Earnings Restriction (

Retained Earnings Restriction (Detail Textuals) - USD ($)	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Retained Earnings Restriction [Line Items]
Total Capitalization	$ 1,129,912,000	$ 1,048,869,000
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	52.60%
OTP | Minimum
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	47.50%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	58.10%
Total Capitalization	$ 1,123,168,000

Commitments and Contingencies (

Commitments and Contingencies (Detail Textuals) - USD ($) $ in Millions	1 Months Ended	6 Months Ended	12 Months Ended
	May 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Line Items]
Loss contingency, range of possible loss, maximum		$ 1
Otter Tail Power Company | Federal Energy Regulatory Commission
Commitments and Contingencies Disclosure [Line Items]
Estimated liability of refund obligation		$ 2.4
Otter Tail Power Company | Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year		2017 and 2040
Otter Tail Power Company | Electric utility capacity
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$ 3.5
Otter Tail Power Company | Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount		$ 123.1	$ 89.6

Short-Term and Long-Term Borr73

Short-Term and Long-Term Borrowings - Status of lines of credit (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Line Limit	$ 320,000
In Use	49,274
Restricted due to Outstanding Letters of Credit	50
Available	270,676	$ 239,028
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	19,289
Restricted due to Outstanding Letters of Credit
Available	130,711	90,334
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	29,985
Restricted due to Outstanding Letters of Credit	50
Available	$ 139,965	$ 148,694

Short-Term and Long-Term Borr74

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, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Short-Term Debt	$ 49,274	$ 80,672
Long-Term Debt	548,383	498,489
Less: Current Maturities net of Unamortized Debt Issuance Costs	52,497	52,422
Unamortized Debt Issuance Costs	2,082	2,221
Long-Term Debt-Net	493,804	443,846
Total Short-Term and Long-Term Debt (with current maturities)	595,575	576,940
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	50,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 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	145	182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	908	977
OTP
Debt Instrument [Line Items]
Short-Term Debt	29,985	21,006
Long-Term Debt	445,000	445,000
Unamortized Debt Issuance Costs	1,980	2,099
Long-Term Debt-Net	443,020	442,901
Total Short-Term and Long-Term Debt (with current maturities)	473,005	463,907
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	19,289	59,666
Long-Term Debt	103,383	53,489
Less: Current Maturities net of Unamortized Debt Issuance Costs	52,497	52,422
Unamortized Debt Issuance Costs	102	122
Long-Term Debt-Net	50,784	945
Total Short-Term and Long-Term Debt (with current maturities)	122,570	113,033
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	50,000
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	145	182
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 908	$ 977

Short-Term and Long-Term Borr75

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details 1)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
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
Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	0.90%
Long-Term Debt, Due Date	Feb. 5, 2018
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 | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	0.90%
Long-Term Debt, Due Date	Feb. 5, 2018
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

Short-Term and Long-Term Borr76

Short-Term and Long-Term Borrowings (Detail Textuals) $ in Thousands	Feb. 05, 2016USD ($)	Jun. 30, 2016USD ($)
Debt Instrument [Line Items]
Aggregate commitment of loan		$ 320,000
Term Loan Agreement | JPMorgan
Debt Instrument [Line Items]
Aggregate commitment of loan	$ 50,000
Minimum increments tranches of term loans	10,000
Maximum amount of debt outstanding	100,000
Borrowed amount	$ 50,000
Interest rate base	LIBOR plus 0.90%
Term Loan Agreement | JPMorgan | LIBOR
Debt Instrument [Line Items]
Line of credit facility, description of variable rate basis	LIBOR
Basis spread on variable rate	0.90%
Term Loan Agreement | JPMorgan | Prime Rate
Debt Instrument [Line Items]
Line of credit facility, description of variable rate basis	Prime Rate
Term Loan Agreement | JPMorgan | Federal Reserve Bank of New York Rate
Debt Instrument [Line Items]
Line of credit facility, description of variable rate basis	Federal Reserve Bank of New York Rate
Basis spread on variable rate	0.50%
Term Loan Agreement | JPMorgan | Statutory Reserve Rate
Debt Instrument [Line Items]
Line of credit facility, description of variable rate basis	LIBOR multiplied by the Statutory Reserve Rate
Basis spread on variable rate	1.00%
Term Loan Agreement | Minimum | JPMorgan
Debt Instrument [Line Items]
Debt to total capitalization ratio	0.60
Interest and dividend coverage ratio	1
Term Loan Agreement | Maximum | JPMorgan
Debt Instrument [Line Items]
Debt to total capitalization ratio	1
Interest and dividend coverage ratio	1.50

Pension Plan and Other Postre77

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, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		$ 1,381	$ 1,530		$ 2,763	$ 3,030
Interest Cost on Projected Benefit Obligation		3,521	3,347		7,043	6,672
Expected Return on Assets		(4,866)	(4,592)		(9,733)	(9,192)
Amortization of Prior-Service Cost:
From Regulatory Asset		47	47		94	94
From Other Comprehensive Income	[1]	1	1		2	2
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,227	1,705		2,454	3,338
From Other Comprehensive Income	[1]	32	46		63	86
Net Periodic Cost		1,343	2,084		2,686	4,030
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		63	47		126	94
Interest Cost on Projected Benefit Obligation		417	381		834	762
Amortization of Prior-Service Cost:
From Regulatory Asset		4	4		8	8
From Other Comprehensive Income	[2]	10	9		19	19
Amortization of Net Actuarial Loss:
From Regulatory Asset		73	84		146	167
From Other Comprehensive Income	[3]	111	150		223	301
Net Periodic Cost		678	675		1,356	1,351
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		305	273		611	648
Interest Cost on Projected Benefit Obligation		542	499		1,083	1,049
Amortization of Prior-Service Cost:
From Regulatory Asset		33	51		66	102
From Other Comprehensive Income	[1]	1	2		2	3
Amortization of Net Actuarial Loss:
From Regulatory Asset			(48)
From Other Comprehensive Income			(1)	[1]
Net Periodic Cost		881	776		1,762	1,802
Effect of Medicare Part D Subsidy		$ (258)	$ (293)		$ (515)	$ (743)
[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 $ 4 $ 8 $ 8 Other Nonelectric Expenses 6 5 11 11
[3]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 68 $ 77 $ 136 $ 155 Other Nonelectric Expenses 43 73 87 146

Pension Plan and Other Postre78

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	[1]	$ 10	$ 9	$ 19	$ 19
Amortization of Net Actuarial Loss - From Other Comprehensive Income	[2]	111	150	223	301
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income		4	4	8	8
Amortization of Net Actuarial Loss - From Other Comprehensive Income		68	77	136	155
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income		6	5	11	11
Amortization of Net Actuarial Loss - From Other Comprehensive Income		$ 43	$ 73	$ 87	$ 146
[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 4 $ 8 $ 8 Other Nonelectric Expenses 6 5 11 11
[2]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 68 $ 77 $ 136 $ 155 Other Nonelectric Expenses 43 73 87 146

Pension Plan and Other Postre79

Pension Plan and Other Postretirement Benefits (Detail Textuals) - USD ($)	1 Months Ended
	Jan. 31, 2016	Jan. 31, 2015
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discretionary plan contributions	$ 10,000,000	$ 10,000,000

Fair Value of Financial Instr80

Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	$ (49,274)	$ (80,672)
Long-Term Debt including Current Maturities	(546,301)	(496,268)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	(49,274)	(80,672)
Long-Term Debt including Current Maturities	$ (641,722)	$ (561,245)

Fair Value of Financial Instr81

Fair Value of Financial Instruments (Detail Textuals)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Otter Tail Corporation Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Line of credit facility, description of variable rate basis	LIBOR	LIBOR
Basis spread on variable rate	1.75%	1.75%
OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Line of credit facility, description of variable rate basis	LIBOR	LIBOR
Basis spread on variable rate	1.25%	1.25%

Income Tax Expense - Continui82

Income Tax Expense - Continuing operations effective income tax rate (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 20,639	$ 17,665	$ 40,621	$ 35,519
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	8,049	6,889	15,842	13,852
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(1,885)	(1,656)	(3,571)	(3,710)
Corporate Owned Life Insurance	(350)	(40)	(414)	(120)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(213)	(213)	(425)	(425)
Employee Stock Ownership Plan Dividend Deduction	(157)	(171)	(315)	(343)
AFUDC Equity	(150)	(125)	(187)	(225)
Section 199 Domestic Production Activities Deduction	(94)	(363)	(198)	(725)
Investment Tax Credits	(87)	(143)	(175)	(286)
Other Items - Net	(30)	(170)	18	63
Income Tax Expense - Continuing Operations	$ 5,083	$ 4,008	$ 10,575	$ 8,081
Effective Income Tax Rate - Continuing Operations	24.60%	22.70%	26.00%	22.80%

Income Tax Expense - Continui83

Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%	39.00%	39.00%

Income Tax Expense - Continui84

Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance on January 1	$ 468	$ 222
Increases Related to Tax Positions for Prior Years
Increases Related to Tax Positions for Current Year	26	86
Uncertain Positions Resolved During Year
Balance on June 30	$ 494	$ 308

Discontinued Operations - Resul

Discontinued Operations - Results of discontinued operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Income (Loss) from Operations			$ 149	$ (5,064)
Income Tax (Benefit) Expense on Disposition		$ (280)		4,536
Net (Loss) Gain on Disposition		(229)		6,997
Net Income (Loss)	$ 119	(2,221)	149	1,933
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		24,623
Operating Expenses	(199)	9,209	(249)	31,350
Goodwill Impairment Charge				1,000
Operating Income (Loss)	199	(3,310)	249	(7,727)
Other Deductions		(11)		(42)
Income Tax Expense (Benefit)	80	(1,329)	100	(2,705)
Net Income (Loss) from Operations	119	(1,992)	149	(5,064)
(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)	$ 119	$ (2,221)	$ 149	$ 1,933

Discontinued Operations - Major

Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Liabilities of Discontinued Operations	$ 1,868	$ 2,098
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 Liabilities	1,868	2,098
Liabilities of Discontinued Operations	$ 1,868	$ 2,098

Discontinued Operations - Warra

Discontinued Operations - Warranty Reserves (Details 2) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Movement in Standard Product Warranty Accrual [Roll Forward]
Warranty Reserve Balance, January 1	$ 2,103	$ 2,527
Additional Provision for Warranties Made During the Year
Settlements Made During the Year		(115)
Decrease in Warranty Estimates for Prior Years	(230)
Warranty Reserve Balance, June 30	$ 1,873	$ 2,412

Discontinued Operations (Detail

Discontinued Operations (Detail Textuals) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Disposal groups held for sale or disposed of by sale | Foley
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cost estimates pretax charges	$ 2.1	$ 4.4