Otter Tail (OTTR) 10-K 22 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 10, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1,466,593
Trading Symbol	ottr
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-Known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		39,410,825
Entity Public Float			$ 1,260,418,253
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents
Accounts Receivable:
Trade (less allowance for doubtful accounts of $1,246 for 2016 and $1,262 for 2015)	68,242	62,974
Other	5,850	9,073
Inventories	83,740	85,416
Unbilled Revenues	20,080	17,869
Income Taxes Receivable	662	4,000
Regulatory Assets	21,297	18,904
Other	8,144	8,453
Total Current Assets	208,015	206,689
Investments	8,417	8,284
Other Assets	34,104	32,784
Goodwill	37,572	39,732
Other Intangibles - Net	14,958	15,673
Regulatory Assets	132,094	127,707
Plant
Electric Plant in Service	1,860,357	1,820,763
Nonelectric Operations	211,826	201,343
Construction Work in Progress	153,261	79,612
Total Gross Plant	2,225,444	2,101,718
Less Accumulated Depreciation and Amortization	748,219	713,904
Net Plant	1,477,225	1,387,814
Total Assets	1,912,385	1,818,683
Current Liabilities
Short-Term Debt	42,883	80,672
Current Maturities of Long-Term Debt	33,201	52,422
Accounts Payable	89,350	89,499
Accrued Salaries and Wages	17,497	16,182
Accrued Taxes	16,000	14,827
Other Accrued Liabilities	15,377	15,416
Liabilities of Discontinued Operations	1,363	2,098
Total Current Liabilities	215,671	271,116
Pensions Benefit Liability	97,627	104,912
Other Postretirement Benefits Liability	62,571	48,730
Other Noncurrent Liabilities	21,706	23,854
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	226,591	207,669
Deferred Tax Credits	22,849	24,506
Regulatory Liabilities	82,433	77,432
Other	7,492	11,595
Total Deferred Credits	339,365	321,202
Capitalization (page 66)
Long-Term Debt - Net	505,341	443,846
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2016 - 39,348,136 Shares; 2015 - 37,857,186 Shares	196,741	189,286
Premium on Common Shares	337,684	293,610
Retained Earnings	139,479	126,025
Accumulated Other Comprehensive Loss	(3,800)	(3,898)
Total Common Equity	670,104	605,023
Total Capitalization	1,175,445	1,048,869
Total Liabilities and Equity	1,912,385	1,818,683
Cumulative Preferred Shares
Capitalization (page 66)
Cumulative Shares
Cumulative Preference Shares
Capitalization (page 66)
Cumulative Shares

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Trade, allowance for doubtful accounts (in dollars)	$ 1,246	$ 1,262
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	39,348,136	37,857,186
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
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)	$ 0	$ 0
Cumulative shares, outstanding	0	0

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Electric	$ 427,349	$ 407,039	$ 407,629
Product Sales	376,190	372,765	391,633
Total Operating Revenues	803,539	779,804	799,262
Operating Expenses
Production Fuel - Electric	54,792	42,744	67,216
Purchased Power - Electric System Use	63,226	78,150	65,848
Electric Operation and Maintenance Expenses	151,225	140,768	141,936
Cost of Products Sold (depreciation included below)	295,222	295,032	308,069
Other Nonelectric Expenses	40,264	40,021	45,981
Depreciation and Amortization	73,445	60,363	58,074
Property Taxes - Electric	14,266	13,512	12,607
Total Operating Expenses	692,440	670,590	699,731
Operating Income	111,099	109,214	99,531
Interest Charges	31,886	31,160	29,648
Other Income	2,905	2,177	3,557
Income Before Income Taxes - Continuing Operations	82,118	80,231	73,440
Income Tax Expense - Continuing Operations	20,081	21,642	16,557
Net Income from Continuing Operations	62,037	58,589	56,883
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $138 in 2016, ($1,539) in 2015 and $3,952 in 2014	284	(5,404)	6,445
Impairment Loss - net of Income Tax (Benefit) of $0 in 2015 and 2014		(1,000)	(5,605)
Gain on Disposition - net of Income Tax Expense of $4,530 in 2015		7,160
Net Income from Discontinued Operations	284	756	840
Total Net Income	$ 62,321	$ 59,345	$ 57,723
Average Number of Common Shares Outstanding - Basic	38,546	37,495	36,514
Average Number of Common Shares Outstanding - Diluted	38,731	37,668	36,753
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 1.61	$ 1.56	$ 1.56
Discontinued Operations (in dollars per share)	0.01	0.02	0.02
Earnings Per Share, Basic, Total (in dollars per share)	1.62	1.58	1.58
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	1.60	1.56	1.55
Discontinued Operations (in dollars per share)	0.01	0.02	0.02
Earnings Per Share, Diluted, Total (in dollars per share)	1.61	1.58	1.57
Dividends Declared Per Common Share (in dollars per share)	$ 1.25	$ 1.23	$ 1.21

Consolidated Statements of Inc5

Consolidated Statements of Income (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Income tax expense (benefit) on income from discontinued operations	$ 138	$ (1,539)	$ 3,952
Income tax (benefit) on impairment loss on discontinued operations		0	$ 0
Income tax expense of (loss) gain on disposition of discontinued operations		$ 4,530

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 62,321	$ 59,345	$ 57,723
Unrealized Loss on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	(3)	(3)	(19)
Losses Arising During Period	(14)	(49)	(14)
Income Tax Benefit	6	18	12
Change in Unrealized Losses on Available-for-Sale Securities - net-of-tax	(11)	(34)	(21)
Pension and Postretirement Benefit Plans:
Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment	(445)	510	(5,048)
Amortization of Unrecognized Postretirement Benefit Costs (note 11)	628	821	192
Income Tax (Expense) Benefit	(74)	(532)	1,942
Pension and Postretirement Benefit Plans - net-of-tax	109	799	(2,914)
Total Other Comprehensive Income (Loss)	98	765	(2,935)
Total Comprehensive Income	$ 62,419	$ 60,110	$ 54,788

Consolidated Statements of Comm

Consolidated Statements of Common Shareholders' Equity - USD ($) $ in Thousands	Common Shares	Premium on Common Shares	Retained Earnings	Accumulated Other Comprehensive Income/(Loss)		Total
Balance at Dec. 31, 2013	$ 181,358	$ 255,759	$ 99,441	$ (1,728)	[1]	$ 534,830
Balance (in shares) at Dec. 31, 2013	36,271,696
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock Issuances, Net of Expenses	$ 4,857	21,057				25,914
Common Stock Issuances, Net of Expenses (in shares)	971,286
Common Stock Retirements	$ (125)	(465)				(590)
Common Stock Retirements (in shares)	(24,929)
Net Income			57,723			57,723
Other Comprehensive Income (Loss)				(2,935)		(2,935)
Tax Benefit - Stock Compensation		302				302
Employee Stock Incentive Plan Expense		1,783				1,783
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)			(44,261)			(44,261)
Balance at Dec. 31, 2014	$ 186,090	278,436	112,903	(4,663)	[1]	572,766
Balance (in shares) at Dec. 31, 2014	37,218,053
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock Issuances, Net of Expenses	$ 3,453	14,715				18,168
Common Stock Issuances, Net of Expenses (in shares)	690,485
Common Stock Retirements	$ (257)	(1,339)				(1,596)
Common Stock Retirements (in shares)	(51,352)
Net Income			59,345			59,345
Other Comprehensive Income (Loss)				765		765
Tax Benefit - Stock Compensation		82				82
Employee Stock Incentive Plan Expense		1,716				1,716
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)			(46,223)			(46,223)
Balance at Dec. 31, 2015	$ 189,286	293,610	126,025	(3,898)	[1]	$ 605,023
Balance (in shares) at Dec. 31, 2015	37,857,186					37,857,186
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock Issuances, Net of Expenses	$ 7,473	38,490				$ 45,963
Common Stock Issuances, Net of Expenses (in shares)	1,494,618
Common Stock Retirements	$ (18)	(86)				(104)
Common Stock Retirements (in shares)	(3,668)
Net Income			62,321			62,321
Other Comprehensive Income (Loss)				98		98
Employee Stock Incentive Plan Expense		3,178				3,178
ASU 2016-09 Adoption at Dec. 31, 2016		2,492	(623)			1,869
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)			(48,244)			(48,244)
Balance at Dec. 31, 2016	$ 196,741	$ 337,684	$ 139,479	$ (3,800)	[1]	$ 670,104
Balance (in shares) at Dec. 31, 2016	39,348,136					39,348,136
[1]	Accumulated Other Comprehensive Loss on December 31 is comprised of the following: (in thousands) 2016 2015 2014 Unrealized (Loss) Gain on Marketable Equity Securities: Before Tax $ (29) $ (12) $ 40 Tax Effect 10 4 (14) Unrealized (Loss) Gain on Marketable Equity Securities net-of-tax (19) (8) 26 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits: Before Tax (6,300) (6,484) (7,815) Tax Effect 2,519 2,594 3,126 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits net-of-tax (3,781) (3,890) (4,689) Accumulated Other Comprehensive Loss: Before Tax (6,329) (6,496) (7,775) Tax Effect 2,529 2,598 3,112 Net Accumulated Other Comprehensive Loss $ (3,800) $ (3,898) $ (4,663) See accompanying notes to consolidated financial statements.

Consolidated Statements of Com8

Consolidated Statements of Common Shareholders' Equity (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	$ (6,329)	$ (6,496)	$ (7,775)
Accumulated Other Comprehensive Income (Loss), Tax Effect	2,529	2,598	3,112
Accumulated Other Comprehensive Income (Loss), net-of-tax	(3,800)	(3,898)	(4,663)
Unrealized (Loss) Gain on Marketable Equity Securities:
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	(29)	(12)	40
Accumulated Other Comprehensive Income (Loss), Tax Effect	10	4	(14)
Accumulated Other Comprehensive Income (Loss), net-of-tax	(19)	(8)	26
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	(6,300)	(6,484)	(7,815)
Accumulated Other Comprehensive Income (Loss), Tax Effect	2,519	2,594	3,126
Accumulated Other Comprehensive Income (Loss), net-of-tax	$ (3,781)	$ (3,890)	$ (4,689)

Consolidated Statements of Com9

Consolidated Statements of Common Shareholders' Equity (Parentheticals 1) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Stockholders' Equity [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$ 1.25	$ 1.23	$ 1.21

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net Income	$ 62,321	$ 59,345	$ 57,723
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		(7,160)
Net (Income) Loss from Discontinued Operations	(284)	6,404	(840)
Depreciation and Amortization	73,445	60,363	58,074
Deferred Tax Credits	(1,657)	(1,878)	(1,904)
Deferred Income Taxes	19,124	26,027	28,204
Change in Deferred Debits and Other Assets	(10,090)	11,407	(50,361)
Discretionary Contribution to Pension Fund	(10,000)	(10,000)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	14,685	20,524	58,442
Allowance for Equity/Other Funds Used During Construction	(857)	(1,303)	(1,543)
Change in Derivatives Net of Regulatory Deferral		(14,736)	519
Stock Compensation Expense - Equity Awards	3,178	1,716	1,783
Other - Net	7	(80)	601
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(944)	(1,746)	(4,647)
Change in Inventories	1,874	1,960	(12,577)
Change in Other Current Assets	(2,541)	(210)	(579)
Change in Payables and Other Current Liabilities	11,941	(15,150)	10,296
Change in Interest Payable and Income Taxes Receivable/Payable	3,339	(3,943)	2,578
Net Cash Provided by Continuing Operations	163,541	131,540	125,769
Net Cash Used in Discontinued Operations	(155)	(14,000)	(13,295)
Net Cash Provided by Operating Activities	163,386	117,540	112,474
Cash Flows from Investing Activities
Capital Expenditures	(161,259)	(160,084)	(163,582)
Proceeds from Disposal of Noncurrent Assets	4,837	3,590	2,467
Acquisition Purchase Price Cash Received (Paid)	1,500	(30,806)
Cash Used for Investments and Other Assets	(4,402)	(6,302)	(2,785)
Net Cash Used in Investing Activities - Continuing Operations	(159,324)	(193,602)	(163,900)
Net Proceeds from Sale of Discontinued Operations		39,401
Net Cash Used in Investing Activities - Discontinued Operations		(1,769)	(596)
Net Cash Used in Investing Activities	(159,324)	(155,970)	(164,496)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(3,363)	2,857	1,236
Net Short-Term (Repayments) Borrowings	(37,789)	69,818	(40,341)
Proceeds from Issuance of Common Stock	44,435	14,233	26,259
Common Stock Issuance Expenses	(562)	(451)	(673)
Payments for Retirement of Capital Stock	(104)	(1,596)	(590)
Proceeds from Issuance of Long-Term Debt	130,000		150,000
Short-Term and Long-Term Debt Issuance Expenses	(888)	(312)	(856)
Payments for Retirement of Long-Term Debt	(87,547)	(212)	(41,088)
Dividends Paid and Other Distributions	(48,244)	(46,223)	(44,261)
Net Cash (Used in) Provided by Financing Activities - Continuing Operations	(4,062)	38,114	49,686
Net Cash Provided by Financing Activities - Discontinued Operations		316	1,178
Net Cash (Used in) Provided by Financing Activities	(4,062)	38,430	50,864
Net Change in Cash and Cash Equivalents - Discontinued Operations			(849)
Net Change in Cash and Cash Equivalents			(2,007)
Cash and Cash Equivalents at Beginning of Period			2,007
Cash and Cash Equivalents at End of Period

Consolidated Statements of Capi

Consolidated Statements of Capitalization - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization [Line Items]
Short-Term Debt	$ 42,883	$ 80,672
Long-Term Debt	540,942	498,489
Less: Current Maturities - Otter Tail Corporation	33,201	52,422
Unamortized Debt Discount - Otter Tail Corporation	2,400	2,221
Total Long-Term Debt	505,341	443,846
Total Common Shareholders' Equity	670,104	605,023
Total Capitalization	1,175,445	1,048,869
Cumulative Preferred Shares
Schedule of Capitalization [Line Items]
Cumulative Shares
Cumulative Preference Shares
Schedule of Capitalization [Line Items]
Cumulative Shares
9.000% Notes, due December 15, 2016
Schedule of Capitalization [Line Items]
Long-Term Debt		52,330
North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [Line Items]
Long-Term Debt	106	182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	836	977
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Schedule of Capitalization [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Schedule of Capitalization [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Schedule of Capitalization [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Schedule of Capitalization [Line Items]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Schedule of Capitalization [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Schedule of Capitalization [Line Items]
Long-Term Debt	90,000	90,000
Otter Tail Corporation
Schedule of Capitalization [Line Items]
Short-Term Debt		59,666
Long-Term Debt	95,942	53,489
Less: Current Maturities - Otter Tail Corporation	231	52,422
Unamortized Debt Discount - Otter Tail Corporation	539	122
Total Long-Term Debt	95,172	945
Total Capitalization	765,276	605,968
Otter Tail Corporation | Otter Tail Corporation Credit Agreement
Schedule of Capitalization [Line Items]
Short-Term Debt		59,666
Otter Tail Corporation | Otter Tail Power Company Credit Agreement
Schedule of Capitalization [Line Items]
Short-Term Debt	42,883	21,006
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Schedule of Capitalization [Line Items]
Long-Term Debt		52,330
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Schedule of Capitalization [Line Items]
Long-Term Debt	15,000
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026
Schedule of Capitalization [Line Items]
Long-Term Debt	80,000
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [Line Items]
Long-Term Debt	106	182
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	836	977
Otter Tail Power Company
Schedule of Capitalization [Line Items]
Short-Term Debt	42,883	21,006
Long-Term Debt	445,000	445,000
Less: Current Maturities - Otter Tail Corporation	32,970
Unamortized Debt Discount - Otter Tail Corporation	1,861	2,099
Total Long-Term Debt	410,169	442,901
Total Capitalization	1,123,168
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Schedule of Capitalization [Line Items]
Long-Term Debt	33,000	33,000
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	140,000	140,000
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Schedule of Capitalization [Line Items]
Long-Term Debt	30,000	30,000
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Schedule of Capitalization [Line Items]
Long-Term Debt	42,000	42,000
Otter Tail Power Company | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Schedule of Capitalization [Line Items]
Long-Term Debt	60,000	60,000
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Schedule of Capitalization [Line Items]
Long-Term Debt	50,000	50,000
Otter Tail Power Company | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Schedule of Capitalization [Line Items]
Long-Term Debt	$ 90,000	$ 90,000

Consolidated Statements of Ca12

Consolidated Statements of Capitalization (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
9.000% Notes, due December 15, 2016
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate		9.00%
Long-Term Debt, Due Date		Dec. 15, 2016
North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [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
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Schedule of Capitalization [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
Schedule of Capitalization [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
Schedule of Capitalization [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
Schedule of Capitalization [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
Schedule of Capitalization [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
Schedule of Capitalization [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
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Cumulative Preferred Shares
Schedule of Capitalization [Line Items]
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, outstanding	0	0
Cumulative Preference Shares
Schedule of Capitalization [Line Items]
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, outstanding	0	0
OTTER TAIL CORPORATION | 9.000% Notes, due December 15, 2016
Schedule of Capitalization [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
Schedule of Capitalization [Line Items]
Description of variable rate basis	LIBOR plus 0.90%	LIBOR plus 0.90%
Long-Term Debt, Interest Rate	0.90%	0.90%
Long-Term Debt, Due Date	Feb. 5, 2018	Feb. 5, 2018
OTTER TAIL CORPORATION | 3.55% Guaranteed Senior Notes, due December 15, 2026
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
OTTER TAIL CORPORATION | North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [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
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Otter Tail Power Company | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Otter Tail Power Company | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Schedule of Capitalization [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations Regulation and ASC 980 The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion. OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses. Plant, Retirements and Depreciation Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates. Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income. Recoverability of Long-Lived Assets The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset. Jointly Owned Facilities OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction. The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and 2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities: Jointly Owned Facilities (dollars in thousands) OTP Electric Plant Construction Accumulated Net Plant December 31, 2016 Big Stone Plant 53.9 % $ 328,809 $ 23 $ (65,665 ) $ 263,167 Coyote Station 35.0 % 176,315 113 (101,499 ) 74,929 Fargo-Monticello 345 kV line 14.2 % 78,298 — (3,511 ) 74,787 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,406 — (924 ) 25,482 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,573 ) 14,758 Big Stone South to Brookings 345 kV line 1 50.0 % — 45,050 — 45,050 Big Stone South to Ellendale 345 kV line 1 50.0 % — 49,160 — 49,160 December 31, 2015 Big Stone Plant 53.9 % $ 327,474 $ (305 ) $ (57,641 ) $ 269,528 Coyote Station 35.0 % 165,497 7,405 (103,822 ) 69,080 Fargo-Monticello 345 kV line 14.2 % 78,272 — (2,213 ) 76,059 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,189 — (486 ) 25,703 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,233 ) 15,098 Big Stone South to Brookings 345 kV line 1 50.0 % — 14,210 — 14,210 Big Stone South to Ellendale 345 kV line 1 50.0 % — 8,335 — 8,335 1 Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). The Company’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income. Coyote Station Lignite Supply Agreement – Variable Interest Entity 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 accumulated development fees and capital charges under the LSA in May 2016. 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 December 31, 2016 could be as high as $60.6 million, OTP’s 35% share of unrecovered costs. Income Taxes Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property. The Company records income taxes in accordance with ASC Topic 740, Income Taxes, The Company also is required to assess the realizability of its deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required. 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 are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with 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. Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders. Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage. Under ASC 815, OTP accounts for forward energy contracts as derivatives subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting. Manufacturing and Plastics operating revenues are recorded when products are shipped. Warranty Reserves Certain products sold by the Company’s manufacturing and plastics companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations. Shipping and Handling Costs The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold. Use of Estimates The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Cash Equivalents The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents. Investments The following table provides a breakdown of the Company’s investments at December 31: (in thousands) 2016 2015 Cost Method: Economic Development Loan Pools $ 54 $ 81 Other 115 2,088 Equity Method Partnerships 23 22 Marketable Securities Classified as Available-for-Sale 8,225 8,093 Total Investments $ 8,417 $ 10,284 Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets — (1,500 ) Foley Company (Foley) Escrow Funds Reported Under Other Current Assets — (500 ) Investments $ 8,417 $ 8,284 The Company’s marketable securities classified as available-for-sale are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below. 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 December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 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 Electric segment inventories are reported at average cost. The Manufacturing and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following at December 31: (in thousands) 2016 2015 Finished Goods $ 27,755 $ 25,971 Work in Process 11,754 12,821 Raw Material, Fuel and Supplies 44,231 46,624 Total Inventories $ 83,740 $ 85,416 Goodwill and Other Intangible Assets The Company accounts for goodwill and other intangible assets in accordance with the requirements of ASC Topic 350, Intangibles—Goodwill and Other, In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. See note 16 to consolidated financial statements. 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 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. The following tables summarize changes to goodwill by business segment during 2016 and 2015: (in thousands) Gross Balance Accumulated Balance (net of Adjustments to 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 (in thousands) Gross Balance Accumulated Balance Adjustments Balance Manufacturing $ 12,186 $ — $ 12,186 $ 8,244 $ 20,430 Plastics 19,302 — 19,302 — 19,302 Total $ 31,488 $ — $ 31,488 $ 8,244 $ 39,732 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 December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 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: (in thousands) 2016 2015 2014 Amortization Expense – Intangible Assets $ 1,436 $ 1,127 $ 977 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of December 31, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 13,533 $ 20,371 (in thousands) 2016 2015 2014 Cash Paid (Received) During the Year for: Interest (net of amount capitalized) $ 31,269 $ 30,512 $ 26,364 Income Taxes $ (1,291 ) $ 7,322 $ 145 New Accounting Standards Accounting Standards Update (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. As of December 31, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09, with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. 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 (in thousands) December 31, 2015 Adjustments December 31, 2015 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 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments , ASU 2016-02 Leases (Topic 842) ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December 31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and 2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts, effective as of January 1, 2016, as illustrated below: Balance Sheet Account Affected, Effective January 1, 2016 Debit Credit Adjustment to Retained Earnings $ 623,000 Long-Term Incentive Payable $ 1,453,000 Deferred Taxes $ 416,000 Miscellaneous Paid-In Capital $ 2,492,000 The impact of adopting the updates in ASU 2016-09 effective January 1, 2016 on 2016 interim reporting periods was not material.

Business Combinations, Disposit

Business Combinations, Dispositions and Segment Information	12 Months Ended
	Dec. 31, 2016
Business Combinations, Dispositions and Segment Information [Abstract]
Business Combinations, Dispositions and Segment Information	2. Business Combinations, Dispositions 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 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, The Company acquired no new businesses in 2016 or 2014. In execution of the Company’s announced strategy of realigning its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward electric utility operations, the Company sold several of its holdings in recent years. On December 31, 2014 the Company was in the process of negotiating the sales of Foley, its mechanical and prime contractor on industrial projects, and AEV, Inc., its electrical design and construction services company, which resulted in the removal of its Construction segment from continuing operations. The sale of Foley closed on April 30, 2015 and the sale of the assets of AEV, Inc. closed on February 28, 2015. The results of operations of the Company’s recently disposed businesses are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and are summarized in note 16 to consolidated financial statements. Segment Information The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment. Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is 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 2016, 2015 and 2014. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.6% of sales in 2016, 97.1% of sales in 2015 and 95.9% of sales in 2014. The Company evaluates the performance of its business segments and allocates resources to them based on segment net income contribution and return on total invested capital. Information on continuing operations for the business segments for 2016, 2015 and 2014 is presented in the following table: (in thousands) 2016 2015 2014 Operating Revenue Electric $ 427,383 $ 407,131 $ 407,743 Manufacturing 221,289 215,011 219,583 Plastics 154,901 157,758 172,050 Intersegment Eliminations (34 ) (96 ) (114 ) Total $ 803,539 $ 779,804 $ 799,262 Cost of Products Sold Manufacturing $ 171,732 $ 171,956 $ 169,033 Plastics 123,496 123,085 139,081 Intersegment Eliminations (6 ) (9 ) (45 ) Total $ 295,222 $ 295,032 $ 308,069 Other Nonelectric Expenses Manufacturing $ 21,994 $ 21,115 $ 23,340 Plastics 9,402 9,850 9,292 Corporate 8,896 9,143 13,418 Intersegment Eliminations (28 ) (87 ) (69 ) Total $ 40,264 $ 40,021 $ 45,981 Depreciation and Amortization Electric $ 53,743 $ 44,786 $ 44,076 Manufacturing 15,794 11,853 10,518 Plastics 3,861 3,552 3,364 Corporate 47 172 116 Total $ 73,445 $ 60,363 $ 58,074 Operating Income (Loss) Electric $ 90,131 $ 87,171 $ 76,060 Manufacturing 11,769 10,086 16,692 Plastics 18,142 21,272 20,313 Corporate (8,943 ) (9,315 ) (13,534 ) Total $ 111,099 $ 109,214 $ 99,531 (in thousands) 2016 2015 2014 Interest Charges Electric $ 25,069 $ 24,371 $ 23,322 Manufacturing 3,859 3,560 3,243 Plastics 1,034 1,026 1,043 Corporate and Intersegment Eliminations 1,924 2,203 2,040 Total $ 31,886 $ 31,160 $ 29,648 Income Tax Expense (Benefit) – Continuing Operations Electric $ 16,366 $ 16,067 $ 11,029 Manufacturing 2,276 2,299 4,117 Plastics 6,538 8,187 7,301 Corporate (5,099 ) (4,911 ) (5,890 ) Total $ 20,081 $ 21,642 $ 16,557 Net Income (Loss) Electric $ 49,829 $ 48,370 $ 43,684 Manufacturing 5,694 4,247 9,361 Plastics 10,628 12,108 12,085 Corporate (4,114 ) (6,136 ) (8,247 ) Discontinued Operations 284 756 840 Total $ 62,321 $ 59,345 $ 57,723 Capital Expenditures Electric $ 149,648 $ 135,572 $ 148,719 Manufacturing 8,429 20,295 11,252 Plastics 3,085 4,206 3,567 Corporate 97 11 44 Total $ 161,259 $ 160,084 $ 163,582 Identifiable Assets Electric $ 1,622,231 $ 1,520,887 $ 1,438,791 Manufacturing 166,525 173,860 128,608 Plastics 84,592 81,624 86,650 Corporate 39,037 42,312 36,508 Assets of Discontinued Operations — — 47,559 Total $ 1,912,385 $ 1,818,683 $ 1,738,116

Rate and Regulatory Matters

Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 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 and use of reagents and emission allowances that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2016, 2015 and 2014. Major Capital Expenditure Projects The Big Stone South – Brookings MVP and CapX2020 Project The Big Stone South – Ellendale MVP Capacity Expansion 2020 (CapX2020) Transmission Line Projects Fargo–Monticello 345 kV CapX2020 Project (the Fargo Project) Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project) Big Stone Plant Air Quality Control System (AQCS) 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. Reagent Costs OTP’s systemwide costs for reagents are expected to increase to approximately $2.2 million annually through May 2021 when Hoot Lake Plant is expected to be retired. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs for the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) were initially incurred in 2015 when projects went into service. Minnesota 2016 General Rate Case ($ in thousands) Annualized or Actual Through Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 10,976 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 The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity. Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $3.6 million as of December 31, 2016. Oral arguments before the MPUC are expected to occur in late February 2017. The MPUC is expected to make its final decision in March 2017 and issue its written order in spring 2017. 2010 General Rate Case Minnesota Conservation Improvement Programs The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC. On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. OTP recognized a financial incentive for 2014 of $3.0 million due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge 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. The 2015 MNCIP program resulted in an approximate 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. Based on results from the 2016 MNCIP program year, OTP recognized a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017. 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. Transmission Cost Recovery Rider MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers. OTP filed an annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates in its current general rate case filing in Minnesota. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. 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. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC has granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017. In OTP’s 2016 general rate case, the MNDOC has argued that the MPUC should require OTP to include in the TCR rider retail rate base 100% of OTP’s investment in the Big Stone South – Brookings and Big Stone South – Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. OTP has opposed this treatment, arguing that the projects are appropriately assigned to the FERC jurisdiction, and the FERC’s determination of the projects’ revenue requirements should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding, the ALJ has recommended that the MPUC should affirm OTP’s treatment. If the MPUC finds that the MNDOC’s treatment should be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. Environmental Cost Recovery (ECR) Rider Reagent Costs and Emission Allowances North Dakota General Rates Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016. Reagent Costs and Emission Allowances South Dakota 2010 General Rate Case Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the years ended December 31: Rate Rider (in thousands) 2016 2015 2014 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 12,920 $ 10,724 $ 7,757 Environmental Cost Recovery 12,443 10,238 6,891 Transmission Cost Recovery 5,795 5,202 6,275 North Dakota Environmental Cost Recovery 11,089 9,502 5,872 Renewable Resource Adjustment 7,800 8,409 7,484 Transmission Cost Recovery 7,694 6,609 5,794 South Dakota Environmental Cost Recovery 2,538 1,967 234 Transmission Cost Recovery 1,820 1,290 1,207 Conservation Improvement Program Costs and Incentives 468 583 435 1 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC. Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. 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 sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. 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. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court of Appeals for the District of Columbia (D.C. Circuit). 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%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. 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 issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016. 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%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the D.C. Circuit. 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 not earlier than spring 2017. Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded reductions in revenue of $1.6 million in 2016 and $1.1 million in 2015 and has a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 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 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets: December 31, 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 $ 6,443 $ 108,267 $ 114,710 see below Deferred Marked-to-Market Losses 1 4,063 6,467 10,530 48 months Conservation Improvement Program Costs and Incentives 2 4,836 5,158 9,994 21 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,153 6,153 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 778 2,087 2,865 52 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,319 482 1,801 15 months Recoverable Fuel and Purchased Power Costs 1 1,798 — 1,798 12 months Debt Reacquisition Premiums 1 325 1,214 1,539 189 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 1,082 — 1,082 12 months Deferred Income Taxes 1 — 1,014 1,014 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 543 643 77 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 568 568 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 333 — 333 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 73 141 214 14 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 113 — 113 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 34 — 34 9 months Total Regulatory Assets $ 21,297 $ 132,094 $ 153,391 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 80,404 $ 80,404 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 1,381 782 2,163 24 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 208 919 16 months Deferred Income Taxes — 818 818 asset lives Minnesota Transmission Cost Recovery Rider Accrued Refund 757 — 757 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 285 — 285 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 139 — 139 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 132 132 24 months Other 21 89 110 204 months Total Regulatory Liabilities $ 3,294 $ 82,433 $ 85,727 Net Regulatory Asset Position $ 18,003 49,661 $ 67,664 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 North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Deferred Income Taxes 1 — 1,455 1,455 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below 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 North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 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 South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 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 December 31, 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 December 31, 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 189 months. 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 regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of December 31, 2016. 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. 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 December 31, 2016. The North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that have not been billed to North Dakota customers as of December 31, 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. 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 December 31, 2016. 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 Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of December 31, 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 December 31, 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 December 31, 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	12 Months Ended
	Dec. 31, 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 and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of December 31: (in thousands) 2016 2015 Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (17,382 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (17,382 ) $ (16,070 ) The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of December 31: (in thousands) 2016 2015 Loss Contracts Covered by Deposited Funds or Letters of Credit $ — $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 17,382 15,871 Total Loss Contracts based on Current Market Values $ 17,382 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871

Common Shares and Earnings Per

Common Shares and Earnings Per Share	12 Months Ended
	Dec. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares and Earnings Per Share	6. Common Shares and Earnings per Share 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. Common Share Distribution Agreement 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. Under the Distribution Agreement, the Company will designate the minimum price and maximum number of shares to be sold through JPMS on any given trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the NASDAQ Global Select Market at market prices or as otherwise agreed with JPMS. The Company may also agree to sell shares to JPMS, as principal for its own account, on terms agreed by the Company and JPMS in a separate agreement at the time of sale. The Company is not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement. 2016 Common Stock Activity Following is a reconciliation of the Company’s common shares outstanding from December 31, 2015 through December 31, 2016: Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 1,014,115 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 163,010 Cash Invested 115,801 Vesting of Executive Stock Performance Awards 54,700 Employee Stock Purchase Plan: Cash Invested 53,875 Dividends Reinvested 23,713 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,825 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, December 31, 2016 39,348,136 2014 Stock Incentive Plan The 2014 Stock Incentive Plan (2014 Incentive Plan), which was approved by the Company’s shareholders in April 2014, provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and other stock and stock-based awards. A total of 1,900,000 common shares were authorized for granting stock awards under the 2014 Incentive Plan, of which 1,356,811 were available for issuance as of December 31, 2016. The 2014 Incentive Plan terminates on December 13, 2023. Employee Stock Purchase Plan The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the Company’s common shares at 85% of the market price at the end of each six-month purchase period. For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month purchase period. On April 16, 2012, the Company’s shareholders approved an amendment to the Purchase Plan, increasing the number of shares available under the Purchase Plan from 900,000 common shares to 1,400,000 common shares and making certain other changes to the terms of the Purchase Plan. Of the 1,400,000 common shares authorized to be issued under the Purchase Plan, 384,159 were available for purchase as of December 31, 2016. At the discretion of the Company, shares purchased under the Purchase Plan can be either new issue shares or shares purchased in the open market. To provide shares for purchases for the Purchase Plan, 53,875 common shares were issued in 2016, 42,253 common shares were issued in 2015 and 39,222 common shares were issued in 2014. The shares to be purchased by employees participating in the Purchase Plan were not material to the calculation of diluted earnings per share during the investment period. Dividend Reinvestment and Share Purchase Plan The Company’s shelf registration statement filed with the SEC on May 11, 2015, as amended on October 13, 2015, provides for the issuance of up to 1,500,000 common shares under the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. New common shares issued under the Plan totaled 278,811 in 2016 and 302,519 in 2015, leaving 918,670 common shares available for issuance under the Plan as of December 31, 2016. Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments in 2016, 2015 and 2014. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation: 2016 2015 2014 Weighted Average Common Shares Outstanding – Basic 38,546,459 37,494,986 36,514,397 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 118,644 100,194 135,480 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 45,712 36,180 27,540 Nonvested Restricted Shares 16,778 22,848 49,998 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,417 13,488 24,048 Potentially Dilutive Stock Options — 330 1,096 Total Dilutive Shares 184,551 173,040 238,162 Weighted Average Common Shares Outstanding – Diluted 38,731,010 37,668,026 36,752,559 The effect of dilutive shares on earnings per share for the years ended December 31, 2016, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in any period.

Share-Based Payments

Share-Based Payments	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Share-Based Payments	7. Share-Based Payments Purchase Plan Through December 31, 2016, the Purchase Plan allowed employees through payroll withholding to purchase shares of the Company’s common stock at a 15% discount from the average market price on the last day of a six month investment period. Under ASC Topic 718, Compensation—Stock Compensation , Stock Options Granted Under the 1999 Incentive Plan The Company granted 2,041,500 options for the purchase of the Company’s common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan). The exercise price of the options granted was the average market price of the Company’s common stock on the grant date. Under ASC 718 accounting requirements, compensation expense is recorded based on the estimated fair value of the options on their grant date using a fair-value option pricing model. Under ASC 718 accounting requirements, the fair value of the options granted has been recorded as compensation expense over the requisite service period (the vesting period of the options). The estimated fair value of all options granted under the 1999 Incentive Plan was based on the Black-Scholes option pricing model. There were no options outstanding as of December 31, 2016 or December 31, 2015. Presented below is a summary of the stock options activity: Stock Option Activity 2016 2015 2014 Options Average Options Average Options Average Outstanding, Beginning of Year — 12,750 $ 24.93 34,700 $ 25.69 Exercised — 10,250 24.93 20,800 26.11 Forfeited or Expired — 2,500 24.93 1,150 26.495 Outstanding, End of Year — — 12,750 24.93 Exercisable, End of Year — — 12,750 24.93 Cash Received for Options Exercised $ 256,000 $ 543,000 Intrinsic Value of Options Exercised $ 75,000 $ 89,000 Restricted Stock Granted to Directors Under the 1999 Incentive Plan and the 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to members of the Company’s board of directors as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. On April 11, 2016, 23,200 shares of restricted stock were granted to the Company’s nonemployee directors. The grant-date fair value of each share of restricted stock granted on April 11, 2016 was $28.66 per share, the average of the high and low market price on the date of grant. The restricted shares granted in 2016 vest 25% per year on April 8 of each year in the period 2017 through 2020 and are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement. Presented below is a summary of the status of directors’ restricted stock awards for the years ended December 31: Directors’ Restricted Stock Awards 2016 2015 2014 Shares Weighted Shares Weighted Shares Weighted Nonvested, Beginning of Year 38,217 $ 29.78 38,050 $ 27.47 42,483 $ 25.03 Granted 23,200 28.66 15,200 31.775 16,800 29.41 Vested 15,083 28.28 15,033 25.96 21,233 24.11 Forfeited — — — Nonvested, End of Year 46,334 29.71 38,217 29.78 38,050 27.47 Compensation Expense Recognized $ 491,000 $ 417,000 $ 416,000 Fair Value of Shares Vested in Year $ 427,000 $ 390,000 $ 512,000 Restricted Stock Granted to Employees Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to employees as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. No shares of restricted stock were granted to employees in 2016 or 2015. Presented below is a summary of the status of employees’ restricted stock awards for the years ended December 31: Employees’ Restricted Stock Awards 2016 2015 2014 Shares Weighted Shares Weighted Shares Weighted Nonvested, Beginning of Year 13,581 $ 28.56 45,280 $ 27.46 48,315 $ 25.04 Granted — — 26,700 29.41 Vested 6,401 27.25 31,699 27.09 25,360 24.80 Forfeited — — 4,375 28.03 Nonvested, End of Year 7,180 29.72 13,581 28.56 45,280 27.46 Compensation Expense Recognized $ 96,000 $ 359,000 $ 998,000 Fair Value of Awards Vested $ 174,000 $ 859,000 $ 629,000 Restricted Stock Units Granted to Executive Officers On February 4, 2016, 22,000 restricted stock units under the 2014 Incentive Plan were granted to the Company’s executive officers. The grant-date fair value of each restricted stock unit was $28.915 per share, the average of the high and low market price on the date of grant. The restricted stock units granted to executive officers in 2016 vest 25% per year on February 6 of each year in the period 2017 through 2020 and 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 vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. Presented below is a summary of the status of restricted stock unit awards granted to executive officers for the years ended December 31: Executives’ Restricted Stock Unit Awards 2016 2015 Restricted Weighted Restricted Weighted Nonvested, Beginning of Year 24,300 $ 31.682 — Granted 22,000 28.915 29,100 $ 31.681 Vested 4,475 31.69 4,800 31.675 Forfeited — — Nonvested, End of Year 41,825 30.23 24,300 31.682 Compensation Expense Recognized $ 446,000 $ 452,000 Fair Value of Awards Vested $ 142,000 $ 152,000 Restricted Stock Units Granted to Employees In 2016 the following restricted stock unit awards under the 2014 Incentive Plan were granted to key employees of the Company who are not executive officers: Grant Date Units Grant-Date Restricted Stock Units Vesting 100% on April 8, 2020 April 11, 2016 15,800 $ 24.00 Restricted Stock Units Vesting 100% on April 8, 2020 September 21, 2016 1,420 $ 30.59 The grant-date fair value of each restricted stock unit was based on the average of the high and low market price of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion over the four-year vesting period. Under the terms of the restricted stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement. Presented below is a summary of the status of employees’ restricted stock unit awards for the years ended December 31: Employees’ Restricted Stock Unit Awards 2016 2015 2014 Restricted Weighted Restricted Weighted Restricted Weighted Nonvested, Beginning of Year 46,600 $ 23.75 45,900 $ 21.82 56,180 $ 19.79 Granted 17,220 24.54 15,650 25.89 11,800 24.95 Reinstated — — 75 30.81 Vested 12,250 19.03 12,250 19.46 14,305 18.05 Forfeited 4,200 24.51 2,700 22.84 7,850 18.90 Nonvested, End of Year 47,370 25.19 46,600 23.75 45,900 21.82 Compensation Expense Recognized $ 307,000 $ 304,000 $ 194,000 Fair Value of Awards Vested $ 233,000 $ 238,000 $ 258,000 Stock Performance Awards granted to Executive Officers Stock performance award agreements have been granted under the 1999 Incentive Plan and the 2014 Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the awards are granted. Awards granted in 2016 and 2015 also included a performance incentive based on the Company’s average 3-year adjusted return on equity relative to a targeted average 3-year adjusted return on equity. The number of shares earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement period. On February 4, 2016 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the 2016-2018 performance measurement period. 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 EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018. 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 122,250 common shares. Under the 2016 performance award agreements, 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 award agreements is accelerated and paid at target in the event of a change in control, disability or death (and upon retirement at or after age 62 for certain officers who are parties to executive employment agreements with the Company). Through December 31, 2015, the income tax withholding terms applicable to outstanding performance awards dictated that the awards be classified and accounted for as liability awards, in accordance with the requirements of ASC 718, with compensation measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date. In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09, resulting in the outstanding 2015 and 2016 performance awards being now classified as equity awards. See note 1 for additional information on the impact of the adoption of ASU 2016-09. The table below provides a summary of stock performance awards granted and amounts expensed related to the stock performance awards: Performance Maximum Target Expense Recognized 1 Earned 2016 2015 2014 2016-2018 122,250 81,500 $ 798,000 2015-2017 126,450 84,300 535,000 $ 943,000 2014-2016 159,450 106,300 332,000 (64,000 ) $ 1,422,000 121,491 2013-2015 90,600 45,300 — (445,000 ) 458,000 22,500 2012-2014 148,400 74,200 — — 142,000 89,991 Total $ 1,665,000 $ 434,000 $ 2,022,000 233,982 1 Stock-based payment expense recognized in 2016 and 2015 for the 2016-2018 and 2015-2017 performance awards reflects the accelerated recognition of expense for outstanding and unvested awards of executives who are eligible for retirement and whose awards vest on normal retirement, as defined in the performance award agreements, prior to the vesting dates of the awards. The earned shares shown in the table above for the 2014-2016 performance period include shares received in 2017 by participants in the plan, based on the Company achieving a total shareholder return ranking of 19 out of 43 companies in the EEI Index and a resulting payout at 114.29% of target. The earned shares also include shares for a portion of the award that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $848,000. The earned shares shown in the table above for the 2013-2015 performance period reflect shares that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $593,000. The earned shares shown in the table above for the 2012-2014 performance period reflect shares received in 2015 by active participants in the plan on December 31, 2014, based on the Company achieving a total shareholder return ranking of 21 out of 48 companies in the EEI Index and a resulting payout at 121.28% of target. In connection with the resignation of executive officers in May 2014 and March 2012, the following unvested stock performance awards were forfeited: 8,900 granted in 2014, 4,900 granted in 2013, and 6,600 granted in 2012. As of December 31, 2016 the total remaining unrecognized amount of compensation expense related to stock-based compensation for all of the Company’s stock-based payment programs was approximately $4.0 million (before income taxes), which will be amortized over a weighted average period of 2.2 years.

Retained Earnings and Dividend

Retained Earnings and Dividend Restriction	12 Months Ended
	Dec. 31, 2016
Retained Earnings Note Disclosure [Abstract]
Retained Earnings and Dividend Restriction	8. Retained Earnings and Dividend Restriction The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries. Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of December 31, 2016 the Company was in compliance with these financial covenants. See note 10 to consolidated financial statements 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, the 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. As of December 31, 2016 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $440,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000.

Commitments and Contingencies o

Commitments and Contingencies of Continuing Operations	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies of Continuing Operations	9. Commitments and Contingencies of Continuing Operations Construction and Other Purchase Commitments At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $84.8 million. Electric Utility Capacity and Energy Requirements and Coal Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. OTP has commitments under contracts providing for the purchase 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. The dollar amounts of OTP’s estimated purchase requirements under this agreement are excluded from the table below because OTP has not committed to any minimum level of purchases under the agreement. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs. See table below for schedule of commitments. 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. Rent expense from continuing operations was $7,565,000, $6,447,000 and $10,165,000 for 2016, 2015 and 2014, respectively. The amounts of the Company’s construction program and other commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases for continuing operations as of December 31, 2016, are as follows: Construction Capacity and Coal Operating Leases (in thousands) Commitments Requirements Commitments OTP Nonelectric Total 2017 $ 74,328 $ 23,711 $ 30,699 $ 2,374 $ 4,760 $ 7,134 2018 7,139 24,356 21,563 1,513 4,129 5,642 2019 3,331 24,925 22,102 1,237 2,598 3,835 2020 — 24,844 22,331 1,251 2,259 3,510 2021 — 12,988 22,840 1,103 1,996 3,099 Beyond 2021 — 166,137 550,719 9,396 7,320 16,716 Total $ 84,798 $ 276,961 $ 670,254 $ 16,874 $ 23,062 $ 39,936 Contingencies Based on the reduction by the FERC in the ROE component of the MISO Tariff, OTP has a $2.7 million liability on its balance sheet as of December 31, 2016 representing OTP’s best estimate of its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery under state jurisdictional TCR riders. Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders and the FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. OTP is an intervenor in these cases and a participant in mediation. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations. 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, excluding any liability for RSG charges for which an estimate cannot be made at this time. In 2014 the Environmental Protection Agency (EPA) published proposed standards of performance for carbon dioxide (CO 2 2 2 2 2 2 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 December 31, 2016 will not be material.

Short-Term and Long-Term Borrow

Short-Term and Long-Term Borrowings	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Short-Term and Long-Term Borrowings	10. Short-Term and Long-Term Borrowings Short-Term Debt The following table presents the status of the Company’s lines of credit as of December 31, 2016 and December 31, 2015: (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 130,000 $ — $ — $ 130,000 $ 90,334 OTP Credit Agreement 170,000 42,883 50 127,067 148,694 Total $ 300,000 $ 42,883 $ 50 $ 257,067 $ 239,028 Under the Otter Tail Corporation Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016 and the average daily balance of debt outstanding during 2016 was $16,200,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016 was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2016 was 1.9%. On October 29, 2012 the Company entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. The Company can draw on this credit facility to refinance certain indebtedness and support its operations and the operations of its subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on the Company’s senior unsecured credit ratings. The Company is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on the Company and the businesses of its wholly owned subsidiary, Varistar Corporation (Varistar) and its subsidiaries, including restrictions on the Company’s and Varistar’s ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of the Company’s subsidiaries. Outstanding letters of credit issued by the Company under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million. On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party. Long-Term Debt Issuances and Retirements 2016 Note Purchase Agreement On September 23, 2016 the Company entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which the Company agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. The Company’s obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by its Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under the Company’s term loan agreement. The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries sell a “substantial part” of its or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes. The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. These include restrictions on the Company’s and the Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on the Company’s and the Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s or the Material Subsidiaries’ credit ratings. Term Loan Agreement 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. 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 Term Loan Agreement contains a number of restrictions on the Company, Varistar and certain subsidiaries of Varistar, including restrictions on its and 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, as well as certain financial covenants as described below under the heading “Financial Covenants.” 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. 2013 Note Purchase Agreement On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) pursuant to which OTP has agreed to issue to the purchasers named therein, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The Notes were issued on February 27, 2014. OTP used a portion of the proceeds of the Notes to retire early a $40.9 million term loan then outstanding and to repay OTP’s short-term debt outstanding on February 27, 2014. The remaining proceeds of the Notes were used to pay fees and expenses related to the issuance of the Notes and for other general purposes, including construction program expenditures. The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing. 2007 and 2011 Note Purchase Agreements On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement). The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.” Shelf Registration On May 11, 2015 the Company filed a shelf registration statement with the SEC under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018. The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 42,883 $ — $ 42,883 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 15,000 $ 15,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 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 106 106 PACE Note, 2.54%, due March 18, 2021 836 836 Total $ 445,000 $ 95,942 $ 540,942 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,970 231 33,201 Unamortized Long-Term Debt Issuance Costs 1,861 539 2,400 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,169 $ 95,172 $ 505,341 Total Short-Term and Long-Term Debt (with current maturities) $ 486,022 $ 95,403 $ 581,425 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 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 The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2016 for each of the next five years are: (in thousands) 2017 2018 2019 2020 2021 Aggregate Amounts of Debt Maturities $ 33,231 $ 15,187 $ 172 $ 185 $ 140,171 Financial Covenants The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016. No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies. The Company’s and OTP’s borrowing agreements are subject to certain financial covenants. Specifically: · Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may 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 agreements. · Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016. · Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. · Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. · Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.

Pension Plan and Other Postreti

Pension Plan and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Pension Plan and Other Postretirement Benefits	11. Pension Plan and Other Postretirement Benefits For valuation of the Company’s pension and other postretirement benefit plans’ projected benefit obligations as of December 31, 2016, the Company adopted updated and modified mortality tables and an updated and modified mortality improvement scale that projects lower mortality improvements in the future for plan participants. The adoption of the updated and modified mortality tables and mortality improvement scale in 2016 decreased the Company’s pension and other postretirement benefit obligations from projected benefit obligations that would have been rendered using the mortality tables the Company had been using since 2014. Although the adoption of the updated and modified tables and improvement scale will have the effect of decreasing the estimated and recognized cost of future benefit payments in the near term, the ultimate cost recognized will be determined by the actual level and duration of future benefit payments. Pension Plan The Company's noncontributory funded pension plan covers substantially all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the plan. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but no change or discontinuance may affect the pensions theretofore vested. The pension plan has a trustee who is responsible for pension payments to retirees and a separate pension fund manager responsible for managing the plan's assets. An independent actuary assists the Company in performing the necessary actuarial valuations for the plan. The plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company. The following table lists components of net periodic pension benefit cost for the year ended December 31: (in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 5,518 $ 6,059 $ 4,666 Interest Cost on Projected Benefit Obligation 14,195 13,344 13,111 Expected Return on Assets (19,454 ) (18,383 ) (16,743 ) Amortization of Prior Service Cost: From Regulatory Asset 189 188 257 From Other Comprehensive Income 1 5 5 7 Amortization of Net Actuarial Loss: From Regulatory Asset 5,153 6,676 3,400 From Other Comprehensive Income 1 127 171 83 Net Periodic Pension Cost $ 5,733 $ 8,060 $ 4,781 1 Weighted average assumptions used to determine net periodic pension cost for the year ended December 31: 2016 2015 2014 Discount Rate 4.76 % 4.35 % 5.30 % Long-Term Rate of Return on Plan Assets 7.75 % 7.75 % 7.75 % Rate of Increase in Future Compensation Level 3.13 % 3.13 % 3.13 % The following table presents amounts recognized in the consolidated balance sheets as of December 31: (in thousands) 2016 2015 Regulatory Assets: Unrecognized Prior Service Cost $ 141 $ 329 Unrecognized Actuarial Loss 98,039 101,974 Total Regulatory Assets $ 98,180 $ 102,303 Accumulated Other Comprehensive Loss: Unrecognized Prior Service Cost $ 12 $ 16 Unrecognized Actuarial Loss 406 820 Total Accumulated Other Comprehensive Loss $ 418 $ 836 Noncurrent Liability $ 60,292 $ 69,101 Funded status as of December 31: (in thousands) 2016 2015 Accumulated Benefit Obligation $ (281,414 ) $ (268,387 ) Projected Benefit Obligation $ (314,637 ) $ (302,740 ) Fair Value of Plan Assets 254,345 233,639 Funded Status $ (60,292 ) $ (69,101 ) The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s benefit obligations over the two-year period ended December 31, 2016: (in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ 233,639 $ 244,589 Actual Return on Plan Assets 23,794 (9,160 ) Discretionary Company Contributions 10,000 10,000 Benefit Payments (13,088 ) (11,790 ) Fair Value of Plan Assets at December 31 $ 254,345 $ 233,639 Estimated Asset Return 10.1 % (3.7 )% Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 302,740 $ 311,650 Service Cost 5,518 6,059 Interest Cost 14,195 13,344 Benefit Payments (13,088 ) (11,790 ) Actuarial Loss (Gain) 5,272 (16,523 ) Projected Benefit Obligation at December 31 $ 314,637 $ 302,740 Weighted average assumptions used to determine benefit obligations at December 31: 2016 2015 Discount Rate 4.60 % 4.76 % Rate of Increase in Future Compensation Level 3.00 % 3.13 % The assumed rate of return on pension fund assets used for the determination of 2017 net periodic pension cost is 7.50%. The assumed long-term rate of return on plan assets is based primarily on asset category studies using historical market return and volatility data with forward looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically. The Company reviews its rate of return on plan asset assumptions annually. The assumptions are largely based on the asset category rate-of-return assumptions developed annually with the Company’s pension plan investment advisors, as well as input from actuaries who work with the pension plan. Market-related value of plan assets The Company’s expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets. The Company bases actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. Measurement Dates: 2016 2015 Net Periodic Pension Cost January 1, 2016 January 1, 2015 End of Year Benefit Obligations January 1, 2016 projected to January 1, 2015 projected to Market Value of Assets December 31, 2016 December 31, 2015 The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost in 2017 are: (in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 120 Amortization of Unrecognized Actuarial Loss 5,090 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost 3 Amortization of Unrecognized Actuarial Loss 125 Total Estimated Amortization $ 5,338 Cash flows The Company had no minimum funding requirement as of December 31, 2016 and will continue to evaluate if discretionary plan contributions will be made in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets: (in thousands) 2017 2018 2019 2020 2021 Years $ 13,413 $ 14,140 $ 14,806 $ 15,564 $ 16,335 $ 92,083 The following objectives guide the investment strategy of the Company’s pension plan (the Plan): · The assets of the Plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards (if applicable). Specifically: o The safeguards and diversity that a prudent investor would adhere to must be present in the investment program. o All transactions undertaken on behalf of the Plan must be in the best interest of plan participants and their beneficiaries. · The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries. · The near-term primary financial objective of the Plan is to improve the funded status of the Plan. · A secondary financial objective is to minimize pension funding and expense volatility where possible. The asset allocation strategy developed by the Company’s Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need for an investment allocation including multiple asset classes. The asset allocation in the table below contains guideline percentages, at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges. The policy of the Plan is to invest assets in accordance with the allocations shown below: Permitted Range Asset Class / PBO Funded Status < 100% PBO 100% PBO 105% PBO >=110% PBO Equity 30% - 65% 25% - 60% 20% - 55% 15% - 50% Investment Grade Fixed Income 35% - 75% 40% - 80% 45% - 85% 50% - 90% Below Investment Grade Fixed Income* 0% - 15% 0% - 15% 0% - 15% 0% - 15% Other** 0% - 20% 0% - 20% 0% - 20% 0% - 20% * Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. ** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund. The Company’s pension plan asset allocations at December 31, 2016 and 2015, by asset category are as follows: Asset Allocation 2016 2015 Large Capitalization Equity Securities 21.4 % 21.2 % International Equity Securities 22.0 % 21.6 % Small and Mid-Capitalization Equity Securities 9.0 % 8.1 % SEI Dynamic Asset Allocation Fund 5.4 % 5.6 % Equity Securities 57.8 % 56.5 % Fixed-Income Securities and Cash 34.3 % 35.8 % Other – SEI Energy Debt Collective Fund 4.1 % 3.6 % Other – SEI Special Situation Collective Investment Trust 3.8 % 4.1 % 100.0 % 100.0 % The following table presents the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the NAV practical expedient to fair valuation as of December 31: (in thousands) 2016 2015 Assets in Level 1 of the Fair Value Hierarchy $ 234,303 $ 215,676 SEI Energy Debt Collective Fund at NAV 10,441 8,342 SEI Special Situation Collective Investment Trust Fund at NAV (1) 9,601 9,621 Total Assets $ 254,345 $ 233,639 (1) Fair Value Measurements of Pension Fund Assets ASC 715, Compensation – Retirement Benefits, The following table presents, the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31: (in thousands) 2016 2015 Large Capitalization Equity Securities Mutual Fund $ 54,483 $ 49,513 International Equity Securities Mutual Funds 55,916 50,504 Small and Mid-Capitalization Equity Securities Mutual Fund 23,011 18,823 SEI Dynamic Asset Allocation Mutual Fund 13,622 13,004 Fixed Income Securities Mutual Funds 87,268 83,830 Cash Management – Money Market Fund 3 2 Total Assets $ 234,303 $ 215,676 The investments held by the SEI Special Situation Collective Investment Trust on December 31, 2016 and 2015 consisted of investments primarily in hedge funds that pursue alternative strategies, private equity funds and hybrid funds, as well as investments directly in other securities and financial instruments, with the objective of achieving high returns balanced against an appropriate level of volatility and market exposure over a full market cycle. The NAV of the SEI Special Situations Collective Investment Trust is determined by using the fair value of the portfolio as of the close of business at the end of the year. The fair value of the fund is calculated independently by the fund’s administrator and is reviewed by the Company. The investments held by the SEI Energy Debt Collective Fund on December 31, 2016 and 2015 consist mainly of below investment grade high yielding bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. The Company invested $10.0 million in the SEI Energy Debt Fund in July 2015. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA (as applicable). The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available 30 days after the end of a calendar quarter. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund, as determined by the investment manager in its sole discretion. The Company reviews and verifies the reasonableness of the year-end valuations. Executive Survivor and Supplemental Retirement Plan (ESSRP) The ESSRP is an unfunded, nonqualified benefit plan for executive officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their deaths for a 15-year postretirement period. Life insurance carried on certain plan participants is payable to the Company on the employee's death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan. The following table lists components of net periodic pension benefit cost for the year ended December 31: (in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 252 $ 189 $ 51 Interest Cost on Projected Benefit Obligation 1,667 1,523 1,520 Amortization of Prior Service Cost: From Regulatory Asset 16 16 22 From Other Comprehensive Income 1 38 38 51 Amortization of Net Actuarial Loss: From Regulatory Asset 293 334 142 From Other Comprehensive Income 2 446 602 46 Net Periodic Pension Cost $ 2,712 $ 2,702 $ 1,832 1 Electric Operation and Maintenance Expenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31 2 Electric Operation and Maintenance Expenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86 ) Weighted average assumptions used to determine net periodic pension cost for the year ended December 31: 2016 2015 2014 Discount Rate 4.76 % 4.35 % 5.30 % Rate of Increase in Future Compensation Level 3.13 % 3.15 % 3.18 % The following table presents amounts recognized in the consolidated balance sheets as of December 31: (in thousands) 2016 2015 Regulatory Assets: Unrecognized Prior Service Cost $ 58 $ 75 Unrecognized Actuarial Loss 2,890 2,936 Total Regulatory Assets $ 2,948 $ 3,011 Projected Benefit Obligation Liability – Net Amount Recognized $ (37,335 ) $ (35,811 ) Accumulated Other Comprehensive Loss: Unrecognized Prior Service Cost $ 134 $ 172 Unrecognized Actuarial Loss 5,915 5,815 Total Accumulated Other Comprehensive Loss $ 6,049 $ 5,987 The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31, 2016 and a statement of the funded status as of December 31 of both years: (in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ — $ — Actual Return on Plan Assets — — Employer Contributions 1,188 1,119 Benefit Payments (1,188 ) (1,119 ) Fair Value of Plan Assets at December 31 $ — $ — Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 35,811 $ 35,650 Service Cost 252 189 Interest Cost 1,667 1,523 Benefit Payments (1,188 ) (1,119 ) Plan Amendments — — Actuarial Loss (Gain) 793 (432 ) Projected Benefit Obligation at December 31 $ 37,335 $ 35,811 Weighted average assumptions used to determine benefit obligations at December 31: 2016 2015 Discount Rate 4.60 % 4.76 % Rate of Increase in Future Compensation Level 3.00 % 3.13 % The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost for the ESSRP in 2017 are: (in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 16 Amortization of Unrecognized Actuarial Loss 285 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost 38 Amortization of Unrecognized Actuarial Loss 440 Total Estimated Amortization $ 779 Cash flows The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid: Years (in thousands) 2017 2018 2019 2020 2021 2022-2026 $ 1,253 $ 1,487 $ 1,562 $ 1,544 $ 1,754 $ 12,700 Other Postretirement Benefits The Company provides a portion of health insurance and life insurance benefits for retired OTP and corporate employees. Substantially all of the Company's electric utility and corporate employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. There are no plan assets. The following table lists components of net periodic postretirement benefit cost for the year ended December 31: (in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 1,301 $ 1,297 $ 1,055 Interest Cost on Projected Benefit Obligation 2,503 2,097 2,200 Amortization of Prior Service Cost From Regulatory Asset 134 205 205 From Other Comprehensive Income 1 3 5 5 Amortization of Net Actuarial Loss From Regulatory Asset 379 — — From Other Comprehensive Income 1 9 — — Net Periodic Postretirement Benefit Cost $ 4,329 $ 3,604 $ 3,465 Effect of Medicare Part D Subsidy $ (923 ) $ (1,487 ) $ (948 ) 1 Weighted average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31: 2016 2015 2014 Discount Rate 4.57 % 4.20 % 5.10 % The following table presents amounts recognized in the consolidated balance sheets as of December 31: (in thousands) 2016 2015 Regulatory Asset: Unrecognized Prior Service Cost $ (4 ) $ 129 Unrecognized Net Actuarial Loss 13,586 1,289 Net Regulatory Asset $ 13,582 $ 1,418 Projected Benefit Obligation Liability – Net Amount Recognized $ (62,571 ) $ (48,730 ) Accumulated Other Comprehensive (Income) Loss: Unrecognized Prior Service Cost $ 4 $ 8 Unrecognized Net Actuarial Gain (171 ) (347 ) Accumulated Other Comprehensive Income $ (167 ) $ (339 ) The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations and accrued postretirement benefit cost over the two-year period ended December 31, 2016: (in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ — $ — Actual Return on Plan Assets — — Company Contributions 2,825 2,365 Benefit Payments (Net of Medicare Part D Subsidy) (5,908 ) (5,324 ) Participant Premium Payments 3,083 2,959 Fair Value of Plan Assets at December 31 $ — $ — Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 48,730 $ 53,638 Service Cost (Net of Medicare Part D Subsidy) 1,301 1,297 Interest Cost (Net of Medicare Part D Subsidy) 2,503 2,097 Benefit Payments (Net of Medicare Part D Subsidy) (5,908 ) (5,324 ) Participant Premium Payments 3,083 2,959 Actuarial Loss (Gain) 12,862 (5,937 ) Projected Benefit Obligation at December 31 $ 62,571 $ 48,730 Reconciliation of Accrued Postretirement Cost: Accrued Postretirement Cost at January 1 $ (47,652 ) $ (46,413 ) Expense (4,329 ) (3,604 ) Net Company Contribution 2,825 2,365 Accrued Postretirement Cost at December 31 $ (49,156 ) $ (47,652 ) Weighted average assumptions used to determine benefit obligations at December 31: 2016 2015 Discount Rate 4.46 % 4.57 % Assumed healthcare cost-trend rates as of December 31: 2016 2015 Healthcare Cost-Trend Rate Assumed for Next Year Pre-65 6.01 % 6.16 % Healthcare Cost-Trend Rate Assumed for Next Year Post-65 6.23 % 6.43 % Rate to Which the Cost-Trend Rate is Assumed to Decline 4.50 % 4.50 % Year the Rate Reaches the Ultimate Trend Rate 2038 2038 Assumed healthcare cost-trend rates have a significant effect on the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2016 would have the following effects: (in thousands) 1 Point 1 Point Effect on the Postretirement Benefit Obligation $ 7,151 $ (7,492 ) Effect on Total of Service and Interest Cost $ 653 $ (519 ) Effect on Expense $ 1,454 $ (907 ) Measurement Dates: 2016 2015 Net Periodic Postretirement Benefit Cost January 1, 2016 January 1, 2015 End of Year Benefit Obligations January 1, 2016 projected to January 1, 2015 projected to The estimated net amounts of unrecognized prior service cost to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic postretirement benefit cost in 2017 are: (in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ — Amortization of Unrecognized Actuarial Loss 932 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost — Amortization of Unrecognized Actuarial Loss 23 Total Estimated Amortization $ 955 Cash flows The Company expects to contribute $3.5 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2017. The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $416,000 in 2017. The following benefit payments, which reflect expected future service, as appropriate, net of expected Medicare Part D subsidy receipts and participant premium payments, are expected to be paid: Years (in thousands) 2017 2018 2019 2020 2021 2022-2026 $ 3,512 $ 3,669 $ 3,828 $ 3,912 $ 4,046 $ 20,377 401K Plan The Company sponsors a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans by the Company and its subsidiary companies included in continuing operations totaled $3,877,000 for 2016, $3,602,000 for 2015 and $3,171,000 for 2014. Employee Stock Ownership Plan The Company has a stock ownership plan for the benefit of all its electric utility employees. Contributions made by the Company were $647,000 for 2016, $674,000 for 2015 and $696,000 for 2014.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 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 December 31, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Cash and Cash Equivalents $ — $ — $ — $ — Short-Term Debt (42,883 ) (42,883 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (538,542 ) (583,835 ) (496,268 ) (561,245 )

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	13. Property, Plant and Equipment (in thousands) December 31, December 31, Electric Plant in Service Production $ 891,330 $ 879,121 Transmission 410,679 391,941 Distribution 466,285 451,820 General 92,063 97,881 Electric Plant in Service 1,860,357 1,820,763 Construction Work in Progress 149,997 64,117 Total Gross Electric Plant 2,010,354 1,884,880 Less Accumulated Depreciation and Amortization 622,657 592,001 Net Electric Plant $ 1,387,697 $ 1,292,879 Nonelectric Operations Plant Equipment $ 155,809 $ 155,715 Buildings and Leasehold Improvements 51,323 41,149 Land 4,694 4,479 Nonelectric Operations Plant 211,826 201,343 Construction Work in Progress 3,264 15,495 Total Gross Nonelectric Plant 215,090 216,838 Less Accumulated Depreciation and Amortization 125,562 121,903 Net Nonelectric Operations Plant $ 89,528 $ 94,935 Net Plant $ 1,477,225 $ 1,387,814 The estimated service lives for rate-regulated properties is 5 to 82 years. For nonelectric property the estimated useful lives are from 3 to 40 years. Service Life Range (years) Low High Electric Fixed Assets: Production Plant 9 82 Transmission Plant 42 70 Distribution Plant 5 68 General Plant 5 50 Nonelectric Fixed Assets: Equipment 3 12 Buildings and Leasehold Improvements 7 40

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	14. Income Taxes The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2016, 2015 and 2014) to net income before total income tax expense for the following reasons: (in thousands) 2016 2015 2014 Tax Computed at Federal Statutory Rate – Continuing Operations $ 28,741 $ 28,081 $ 25,704 Increases (Decreases) in Tax from: Federal PTCs (7,175 ) (6,962 ) (7,517 ) State Income Taxes Net of Federal Income Tax Expense 2,848 4,945 1,993 North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850 ) (850 ) (849 ) Corporate-owned Life Insurance (680 ) (167 ) (354 ) Dividend Received/Paid Deduction (537 ) (560 ) (622 ) Section 199 Domestic Production Activities Deduction (482 ) — (1,026 ) Investment Tax Credit Amortization (350 ) (571 ) (597 ) Allowance for Funds Used During Construction – Equity (280 ) (426 ) (505 ) Differences Reversing in Excess of Federal Rates 77 (1,143 ) (106 ) Permanent and Other Differences (1,231 ) (705 ) 436 Total Income Tax Expense – Continuing Operations $ 20,081 $ 21,642 $ 16,557 Income Tax Expense – Discontinued Operations – U.S. 138 2,991 3,952 Income Tax Expense – Continuing and Discontinued Operations $ 20,219 $ 24,633 $ 20,509 Overall Effective Federal, State and Foreign Income Tax Rate 24.5 % 29.3 % 26.2 % Income Tax Expense From Continuing Operations Includes the Following: Current Federal Income Taxes $ 1,070 $ 211 $ 124 Current State Income Taxes 1,211 1 5 Deferred Federal Income Taxes 23,586 23,050 21,044 Deferred State Income Taxes 2,589 6,763 4,347 Federal PTCs (7,175 ) (6,962 ) (7,517 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850 ) (850 ) (849 ) Investment Tax Credit Amortization (350 ) (571 ) (597 ) Total $ 20,081 $ 21,642 $ 16,557 Total Income Before Income Taxes – Continuing and Discontinued Operations $ 82,540 $ 83,978 $ 78,232 The Company's deferred tax assets and liabilities were composed of the following on December 31: (in thousands) 2016 2015 Deferred Tax Assets Benefit Liabilities $ 44,381 $ 41,788 Federal PTCs 43,433 39,505 Retirement Benefits Liabilities 38,390 41,958 North Dakota Wind Tax Credits 32,962 32,962 Cost of Removal 31,636 29,463 Differences Related to Property 9,876 10,177 Net Operating Loss Carryforward 3,865 22,824 Vacation Accrual 2,725 2,500 Investment Tax Credits 818 1,109 Other 7,793 7,617 Total Deferred Tax Assets $ 215,879 $ 229,903 Deferred Tax Liabilities Differences Related to Property $ (371,761 ) $ (366,234 ) Retirement Benefits Regulatory Asset (38,390 ) (41,958 ) Excess Tax over Book Pension (15,509 ) (13,775 ) North Dakota Wind Tax Credits (3,654 ) (3,179 ) Impact of State Net Operating Losses on Federal Taxes (1,352 ) (1,596 ) Other (11,804 ) (10,830 ) Total Deferred Tax Liabilities $ (442,470 ) $ (437,572 ) Deferred Income Taxes $ (226,591 ) $ (207,669 ) Federal PTCs are earned as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 3.6% in 2016 compared with 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years. Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2016: (in thousands) Amount 2017 2027-36 United States Federal Net Operating Losses $ — $ — $ — Federal Tax Credits 46,435 — 46,435 State Net Operating Losses 3,865 — 3,865 State Tax Credits 33,993 389 33,604 The carryforward period on a portion of the North Dakota wind tax credits from the Langdon wind project is five years. OTP has adjusted its deferred tax assets and deferred tax credits by $0.4 million for potential unused North Dakota wind tax credits related to the Langdon wind project. The following table summarizes the activity related to our unrecognized tax benefits: (in thousands) 2016 2015 2014 Balance on January 1 $ 468 $ 222 $ 4,239 Increases Related to Tax Positions for Prior Years 406 236 120 Decreases Related to Tax Positions for Prior Years — — (4,142 ) Increases Related to Tax Positions for Current Year 114 10 5 Uncertain Positions Resolved During Year (97 ) — — Balance on December 31 $ 891 $ 468 $ 222 The balance of unrecognized tax benefits as of December 31, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 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 our consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of December 31, 2016. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes.

Asset Retirement Obligations (A

Asset Retirement Obligations (AROs)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations (AROs)	15. Asset Retirement Obligations (AROs) The Company’s AROs are related to OTP’s coal-fired generation plants and its 92 wind turbines located in North Dakota. The AROs include items such as site restoration, closure of ash pits, and removal of certain structures, generators, asbestos and storage tanks. The Company has legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. The Company has no assets legally restricted for the settlement of any of its AROs. On December 19, 2014 the EPA’s rule regulating coal combustion residuals (CCR) went into effect. The final rule regulates CCR as a non-hazardous solid waste under Subtitle D of the Resource Conservation and Recovery Act. In the second quarter of 2015, subsequent to publication of the CCR rule, OTP completed an assessment of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it had no immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but has discontinued the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally, OTP identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the slag sluice pond and slag stockpile are currently in use, so the cost of the new ARO was capitalized. Therefore, the establishment of the ARO will have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when incurred, will be charged against, and reduce, the accumulated ARO liability. OTP recorded no new AROs in 2016. Reconciliations of carrying amounts of the present value of the Company’s legal AROs, capitalized asset retirement costs and related accumulated depreciation and a summary of settlement activity for the years ended December 31, 2016 and 2015 are presented in the following table: (in thousands) 2016 2015 Asset Retirement Obligations Beginning Balance $ 8,084 $ 7,721 New Obligations Recognized — 451 Adjustments Due to Revisions in Cash Flow Estimates (103 ) (424 ) Accrued Accretion 360 336 Settlements — — Ending Balance $ 8,341 $ 8,084 Asset Retirement Costs Capitalized Beginning Balance $ 3,086 $ 3,059 New Obligations Recognized — 451 Adjustments Due to Revisions in Cash Flow Estimates (103 ) (424 ) Settlements — — Ending Balance $ 2,983 $ 3,086 Accumulated Depreciation – Asset Retirement Costs Capitalized Beginning Balance $ 673 $ 527 New Obligations Recognized — — Adjustments Due to Revisions in Cash Flow Estimates — — Depreciation Expense 122 146 Settlements — — Ending Balance $ 795 $ 673 Settlements None None Original Capitalized Asset Retirement Cost – Retired $ — $ — Accumulated Depreciation — — Asset Retirement Obligation $ — $ — Settlement Cost — — Gain on Settlement – Deferred Under Regulatory Accounting $ — $ —

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	16. Discontinued Operations On April 30, 2015 the Company sold Foley for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million in selling expenses. On February 28, 2015 the Company sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and AEV, Inc. were formerly included in the Company’s Construction segment. On February 8, 2013 the Company completed the sale of substantially all the assets of its dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of our wind tower manufacturing business. This business was the only remaining entity in the Company’s former Wind Energy segment. The Company’s Wind Energy and Construction segments were eliminated as a result of the sales of its wind tower manufacturing business, Foley and AEV, Inc. The financial position, results of operations and cash flows of Foley, AEV, Inc., the Company’s wind tower manufacturing business and its dock and boatlift company are reported as discontinued operations in the Company’s consolidated financial statements. Following are summary presentations of the results of discontinued operations for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, 2016 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Expenses $ 250 $ — $ (757 ) $ 85 $ — $ (422 ) Income Tax (Benefit) Expense (136 ) 5 303 (34 ) — 138 Net (Loss) Income $ (114 ) $ (5 ) $ 454 $ (51 ) $ — $ 284 For the Year Ended December 31, 2015 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Revenues $ 21,625 $ 2,998 $ — $ — $ — $ 24,623 Operating Expenses 26,839 4,532 (462 ) 966 (240 ) 31,635 Asset Impairment Charge 1,000 — — — — 1,000 Interest Expense 177 27 — — (204 ) — Other Income (Deductions) (42 ) 2 111 — (2 ) 69 Income Tax (Benefit) Expense (921 ) (638 ) 229 (386 ) 177 (1,539 ) Net (Loss) Income from Operations (5,512 ) (921 ) 344 (580 ) 265 (6,404 ) (Loss) Gain on Disposition Before Taxes (204 ) 11,894 — — — 11,690 Income Tax (Benefit) Expense on Disposition (227 ) 4,757 — — — 4,530 Net Gain on Disposition 23 7,137 — — — 7,160 Net (Loss) Income $ (5,489 ) $ 6,216 $ 344 $ (580 ) $ 265 $ 756 For the Year Ended December 31, 2014 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Revenues $ 105,333 $ 44,527 $ — $ — $ — $ 149,860 Operating Expenses 100,826 40,297 19 (180 ) (960 ) 140,002 Asset Impairment Charge 5,605 — — — — 5,605 Interest Expense 510 184 — — (694 ) — Other (Deductions) Income (38 ) 304 — 277 (4 ) 539 Income Tax Expense (Benefit) 1,388 1,729 (8 ) 183 660 3,952 Net (Loss) Income $ (3,034 ) $ 2,621 $ (11 ) $ 274 $ 990 $ 840 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 $4.4 million in 2015. In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. Following are summary presentations of the major components of assets and liabilities of discontinued operations as of December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) Foley AEV, Inc. Wind Dock and Total Current Liabilities $ — $ — $ 589 $ 774 $ 1,363 Liabilities of Discontinued Operations $ — $ — $ 589 $ 774 $ 1,363 December 31, 2015 (in thousands) Foley AEV, Inc. Wind Dock and Total Current Liabilities $ — $ — $ 1,299 $ 799 $ 2,098 Liabilities of Discontinued Operations $ — $ — $ 1,299 $ 799 $ 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 (24 ) (124 ) Decrease in Warranty Estimates for Prior Years (710 ) (300 ) Warranty Reserve Balance, December 31 $ 1,369 $ 2,103 The warranty reserve balances as of December 31, 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. 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. Expenses associated with remediation activities of these companies could be substantial. 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 net income and financial condition.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events Stock Incentive Awards On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan: Award Shares/Units Weighted Vesting Restricted Stock Units Granted 15,900 $ 37.65 25% per year through February 6, 2021 Stock Performance Awards Granted 59,500 $ 31.00 December 31, 2019 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant. Under the performance share awards the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2017 through December 31, 2019, 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, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are 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 equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award. Under the 2017 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event. The 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.

SCHEDULE 1 - CONDENSED FINANCIA

SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF REGISTRANT	SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT OTTER TAIL CORPORATION (PARENT COMPANY) Condensed Balance Sheets, December 31 (in thousands) 2016 2015 ASSETS Current Assets Cash and Cash Equivalents $ 6,218 $ — Accounts Receivable 12 38 Accounts Receivable from Subsidiaries 1,706 2,311 Interest Receivable from Subsidiaries 141 175 Income Taxes Receivable 662 4,000 Notes Receivable from Subsidiaries 1,671 5,645 Other 936 1,096 Total Current Assets 11,346 13,265 Investments in Subsidiaries 692,723 713,344 Notes Receivable from Subsidiaries 79,843 72,560 Deferred Income Taxes 35,387 37,406 Other Assets 29,079 26,957 Total Assets $ 848,378 $ 863,532 LIABILITIES AND EQUITY Current Liabilities Short-Term Debt $ — $ 59,666 Current Maturities of Long-Term Debt 231 52,422 Accounts Payable to Subsidiaries 5,958 5,959 Notes Payable to Subsidiaries 38,519 99,467 Other 5,838 6,035 Total Current Liabilities 50,546 223,549 Other Noncurrent Liabilities 32,556 34,015 Commitments and Contingencies Capitalization Long-Term Debt, Net of Current Maturities 95,172 945 Common Shareholder Equity 670,104 605,023 Total Capitalization 765,276 605,968 Total Liabilities and Equity $ 848,378 $ 863,532 See accompanying notes to condensed financial statements. OTTER TAIL CORPORATION (PARENT COMPANY) Condensed Statements of Income—For the Years Ended December 31 (in thousands) 2016 2015 2014 Operating Loss Revenue $ — $ — $ — Operating Expenses 9,689 10,188 12,593 Operating Loss (9,689 ) (10,188 ) (12,593 ) Other Income (Expense) Equity Income in Earnings of Subsidiaries 67,047 66,067 64,926 Interest Charges (6,817 ) (6,786 ) (6,326 ) Interest Charges to Subsidiaries (173 ) (193 ) (117 ) Interest Income from Subsidiaries 4,897 4,786 4,980 Other Income 1,621 421 1,379 Total Other Income 66,575 64,295 64,842 Income Before Income Taxes 56,886 54,107 52,249 Income Tax Benefit (5,435 ) (5,238 ) (5,474 ) Net Income $ 62,321 $ 59,345 $ 57,723 See accompanying notes to condensed financial statements. OTTER TAIL CORPORATION (PARENT COMPANY) Condensed Statements of Cash Flows—For the Years Ended December 31 (in thousands) 2016 2015 2014 Cash Flows from Operating Activities Net Cash Provided by Operating Activities $ 83,296 $ 53,958 $ 47,697 Cash Flows from Investing Activities Return of Capital (Investment in Subsidiaries) 9,912 (88,079 ) (44,000 ) Debt Issued to Subsidiaries (3,309 ) (12,592 ) (7,662 ) Cash Provided by (Used in) Investing Activities 106 (11 ) (44 ) Net Cash Provided by (Used in) Investing Activities 6,709 (100,682 ) (51,706 ) Cash Flows from Financing Activities Change in Checks Written in Excess of Cash (428 ) 213 215 Net Short-Term (Repayments) Borrowings (59,666 ) 48,812 10,854 (Repayments to) Borrowings from Subsidiaries (60,948 ) 32,249 4,656 Proceeds from Issuance of Common Stock 44,435 14,233 26,259 Common Stock Issuance Expenses (562 ) (451 ) (673 ) Payments for Retirement of Capital Stock (104 ) (1,596 ) (590 ) Proceeds from the Issuance of Long-Term Debt 130,000 — — Short-Term and Long-Term Debt Issuance Expenses (723 ) (312 ) (170 ) Payments for Retirement of Long-Term Debt (87,547 ) (201 ) (188 ) Dividends Paid and Other Distributions (48,244 ) (46,223 ) (44,261 ) Net Cash (Used in) Provided by Financing Activities (83,787 ) 46,724 (3,898 ) Net Change in Cash and Cash Equivalents 6,218 — (7,907 ) Cash and Cash Equivalents at Beginning of Period — — 7,907 Cash and Cash Equivalents at End of Period $ 6,218 $ — $ — See accompanying notes to condensed financial statements. Otter Tail Corporation (Parent Company) Notes to Condensed Financial Statements For the years ended December 31, 2016, 2015 and 2014 Incorporated by reference are Otter Tail Corporation’s consolidated statements of comprehensive income and common shareholders’ equity in Part II, Item 8. Basis of Presentation The condensed financial information of Otter Tail Corporation is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this Annual Report on Form 10-K. Otter Tail Corporation’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income (loss) from operations of the subsidiaries is reported on a net basis as equity income (loss) in earnings of subsidiaries. Related Party Transactions As of December 31, 2016: (in thousands) Accounts Interest Current Long-Term Accounts Current Otter Tail Power Company $ 1,572 $ — $ — $ — $ 10 $ — Vinyltech Corporation 3 20 — 11,500 — 15,951 Northern Pipe Products, Inc. — 10 — 5,943 — 6,560 BTD Manufacturing, Inc. — 92 — 52,000 — 2,342 Wind Tower Business — — 1,441 — — — Dock and Boatlift Business — — 230 — — — T.O. Plastics, Inc. — 19 — 10,400 — 12,378 Varistar Corporation 60 — — — 5,948 1,288 Otter Tail Assurance Limited 71 — — — — — $ 1,706 $ 141 $ 1,671 $ 79,843 $ 5,958 $ 38,519 As of December 31, 2015: (in thousands) Accounts Interest Current Long-Term Accounts Current Otter Tail Power Company $ 1,928 $ — $ — $ — $ 11 $ — Vinyltech Corporation — 32 — 8,500 — 14,844 Northern Pipe Products, Inc. — 8 — 3,160 — 7,088 BTD Manufacturing, Inc. 13 107 3,924 53,500 — — Wind Tower Business — — 1,444 — — — Dock and Boatlift Business — — 277 — — — T.O. Plastics, Inc. — 28 — 7,400 — 6,405 Varistar Corporation 60 — — — 5,948 71,130 Otter Tail Assurance Limited 310 — — — — — $ 2,311 $ 175 $ 5,645 $ 72,560 $ 5,959 $ 99,467 Dividends Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows: (in thousands) 2016 2015 2014 Cash Dividends Paid to Parent by Subsidiaries $ 77,779 $ 46,188 $ 44,261 See Otter Tail Corporation’s notes to consolidated financial statements in Part II, Item 8 for other disclosures. Other schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto.

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations
Regulation and ASC 980	Regulation and ASC 980 The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion. OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.
Plant, Retirements and Depreciation	Plant, Retirements and Depreciation Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates. Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
Recoverability of Long-Lived Assets	Recoverability of Long-Lived Assets The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.
Jointly Owned Facilities	Jointly Owned Facilities OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction. The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and 2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities: Jointly Owned Facilities (dollars in thousands) OTP Electric Plant Construction Accumulated Net Plant December 31, 2016 Big Stone Plant 53.9 % $ 328,809 $ 23 $ (65,665 ) $ 263,167 Coyote Station 35.0 % 176,315 113 (101,499 ) 74,929 Fargo-Monticello 345 kV line 14.2 % 78,298 — (3,511 ) 74,787 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,406 — (924 ) 25,482 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,573 ) 14,758 Big Stone South to Brookings 345 kV line 1 50.0 % — 45,050 — 45,050 Big Stone South to Ellendale 345 kV line 1 50.0 % — 49,160 — 49,160 December 31, 2015 Big Stone Plant 53.9 % $ 327,474 $ (305 ) $ (57,641 ) $ 269,528 Coyote Station 35.0 % 165,497 7,405 (103,822 ) 69,080 Fargo-Monticello 345 kV line 14.2 % 78,272 — (2,213 ) 76,059 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,189 — (486 ) 25,703 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,233 ) 15,098 Big Stone South to Brookings 345 kV line 1 50.0 % — 14,210 — 14,210 Big Stone South to Ellendale 345 kV line 1 50.0 % — 8,335 — 8,335 1 Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). The Company’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income.
Coyote Station Lignite Supply Agreement - Variable Interest Entity	Coyote Station Lignite Supply Agreement – Variable Interest Entity 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 accumulated development fees and capital charges under the LSA in May 2016. 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 December 31, 2016 could be as high as $60.6 million, OTP’s 35% share of unrecovered costs.
Income Taxes	Income Taxes Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property. The Company records income taxes in accordance with ASC Topic 740, Income Taxes, The Company also is required to assess the realizability of its deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required.
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 are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with 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. Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders. Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage. Under ASC 815, OTP accounts for forward energy contracts as derivatives subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting. Manufacturing and Plastics operating revenues are recorded when products are shipped.
Warranty Reserves	Warranty Reserves Certain products sold by the Company’s manufacturing and plastics companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations.
Shipping and Handling Costs	Shipping and Handling Costs The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.
Use of Estimates	Use of Estimates The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Cash Equivalents	Cash Equivalents The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.
Investments	Investments The following table provides a breakdown of the Company’s investments at December 31: (in thousands) 2016 2015 Cost Method: Economic Development Loan Pools $ 54 $ 81 Other 115 2,088 Equity Method Partnerships 23 22 Marketable Securities Classified as Available-for-Sale 8,225 8,093 Total Investments $ 8,417 $ 10,284 Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets — (1,500 ) Foley Company (Foley) Escrow Funds Reported Under Other Current Assets — (500 ) Investments $ 8,417 $ 8,284 The Company’s marketable securities classified as available-for-sale are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below.
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 December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 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 Electric segment inventories are reported at average cost. The Manufacturing and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following at December 31: (in thousands) 2016 2015 Finished Goods $ 27,755 $ 25,971 Work in Process 11,754 12,821 Raw Material, Fuel and Supplies 44,231 46,624 Total Inventories $ 83,740 $ 85,416
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets The Company accounts for goodwill and other intangible assets in accordance with the requirements of ASC Topic 350, Intangibles—Goodwill and Other, In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. See note 16 to consolidated financial statements. 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 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. The following tables summarize changes to goodwill by business segment during 2016 and 2015: (in thousands) Gross Balance Accumulated Balance (net of Adjustments to 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 (in thousands) Gross Balance Accumulated Balance Adjustments Balance Manufacturing $ 12,186 $ — $ 12,186 $ 8,244 $ 20,430 Plastics 19,302 — 19,302 — 19,302 Total $ 31,488 $ — $ 31,488 $ 8,244 $ 39,732 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 December 31, 2016 and December 31, 2015: December 31, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 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: (in thousands) 2016 2015 2014 Amortization Expense – Intangible Assets $ 1,436 $ 1,127 $ 977 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information As of December 31, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 13,533 $ 20,371 (in thousands) 2016 2015 2014 Cash Paid (Received) During the Year for: Interest (net of amount capitalized) $ 31,269 $ 30,512 $ 26,364 Income Taxes $ (1,291 ) $ 7,322 $ 145
New Accounting Standards	New Accounting Standards Accounting Standards Update (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. As of December 31, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09, with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. 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 (in thousands) December 31, 2015 Adjustments December 31, 2015 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 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments , ASU 2016-02 Leases (Topic 842) ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December 31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and 2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts, effective as of January 1, 2016, as illustrated below: Balance Sheet Account Affected, Effective January 1, 2016 Debit Credit Adjustment to Retained Earnings $ 623,000 Long-Term Incentive Payable $ 1,453,000 Deferred Taxes $ 416,000 Miscellaneous Paid-In Capital $ 2,492,000 The impact of adopting the updates in ASU 2016-09 effective January 1, 2016 on 2016 interim reporting periods was not material.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule for ownership share of jointly owned facilities	Jointly Owned Facilities (dollars in thousands) OTP Electric Plant Construction Accumulated Net Plant December 31, 2016 Big Stone Plant 53.9 % $ 328,809 $ 23 $ (65,665 ) $ 263,167 Coyote Station 35.0 % 176,315 113 (101,499 ) 74,929 Fargo-Monticello 345 kV line 14.2 % 78,298 — (3,511 ) 74,787 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,406 — (924 ) 25,482 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,573 ) 14,758 Big Stone South to Brookings 345 kV line 1 50.0 % — 45,050 — 45,050 Big Stone South to Ellendale 345 kV line 1 50.0 % — 49,160 — 49,160 December 31, 2015 Big Stone Plant 53.9 % $ 327,474 $ (305 ) $ (57,641 ) $ 269,528 Coyote Station 35.0 % 165,497 7,405 (103,822 ) 69,080 Fargo-Monticello 345 kV line 14.2 % 78,272 — (2,213 ) 76,059 Brookings-Southeast Twin Cities 345 kV line 1 4.8 % 26,189 — (486 ) 25,703 Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 — (1,233 ) 15,098 Big Stone South to Brookings 345 kV line 1 50.0 % — 14,210 — 14,210 Big Stone South to Ellendale 345 kV line 1 50.0 % — 8,335 — 8,335 1 Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).
Schedule of breakdown of Investments	(in thousands) 2016 2015 Cost Method: Economic Development Loan Pools $ 54 $ 81 Other 115 2,088 Equity Method Partnerships 23 22 Marketable Securities Classified as Available-for-Sale 8,225 8,093 Total Investments $ 8,417 $ 10,284 Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets — (1,500 ) Foley Company (Foley) Escrow Funds Reported Under Other Current Assets — (500 ) Investments $ 8,417 $ 8,284
Schedule of assets and liabilities that are measured at fair value on a recurring basis	December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 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	(in thousands) 2016 2015 Finished Goods $ 27,755 $ 25,971 Work in Process 11,754 12,821 Raw Material, Fuel and Supplies 44,231 46,624 Total Inventories $ 83,740 $ 85,416
Schedule of changes to goodwill by business segment	(in thousands) Gross Balance Accumulated Balance (net of Adjustments to 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 (in thousands) Gross Balance Accumulated Balance Adjustments Balance Manufacturing $ 12,186 $ — $ 12,186 $ 8,244 $ 20,430 Plastics 19,302 — 19,302 — 19,302 Total $ 31,488 $ — $ 31,488 $ 8,244 $ 39,732
Schedule of components of intangible assets	December 31, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 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	(in thousands) 2016 2015 2014 Amortization Expense – Intangible Assets $ 1,436 $ 1,127 $ 977
Schedule of estimated annual amortization expense for intangible assets	(in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099
Schedule of supplemental disclosure of cash flow information	As of December 31, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 13,533 $ 20,371 (in thousands) 2016 2015 2014 Cash Paid (Received) During the Year for: Interest (net of amount capitalized) $ 31,269 $ 30,512 $ 26,364 Income Taxes $ (1,291 ) $ 7,322 $ 145
Schedule of effects of applying the guidance and reclassification of unamortized line of credit issuance costs	(in thousands) December 31, 2015 Adjustments December 31, 2015 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
Schedule of related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts	Balance Sheet Account Affected, Effective January 1, 2016 Debit Credit Adjustment to Retained Earnings $ 623,000 Long-Term Incentive Payable $ 1,453,000 Deferred Taxes $ 416,000 Miscellaneous Paid-In Capital $ 2,492,000

Business Combinations, Dispos33

Business Combinations, Dispositions and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations, Dispositions and Segment Information [Abstract]
Schedule of business combination disclosing the preliminary 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	(in thousands) 2016 2015 2014 Operating Revenue Electric $ 427,383 $ 407,131 $ 407,743 Manufacturing 221,289 215,011 219,583 Plastics 154,901 157,758 172,050 Intersegment Eliminations (34 ) (96 ) (114 ) Total $ 803,539 $ 779,804 $ 799,262 Cost of Products Sold Manufacturing $ 171,732 $ 171,956 $ 169,033 Plastics 123,496 123,085 139,081 Intersegment Eliminations (6 ) (9 ) (45 ) Total $ 295,222 $ 295,032 $ 308,069 Other Nonelectric Expenses Manufacturing $ 21,994 $ 21,115 $ 23,340 Plastics 9,402 9,850 9,292 Corporate 8,896 9,143 13,418 Intersegment Eliminations (28 ) (87 ) (69 ) Total $ 40,264 $ 40,021 $ 45,981 Depreciation and Amortization Electric $ 53,743 $ 44,786 $ 44,076 Manufacturing 15,794 11,853 10,518 Plastics 3,861 3,552 3,364 Corporate 47 172 116 Total $ 73,445 $ 60,363 $ 58,074 Operating Income (Loss) Electric $ 90,131 $ 87,171 $ 76,060 Manufacturing 11,769 10,086 16,692 Plastics 18,142 21,272 20,313 Corporate (8,943 ) (9,315 ) (13,534 ) Total $ 111,099 $ 109,214 $ 99,531 (in thousands) 2016 2015 2014 Interest Charges Electric $ 25,069 $ 24,371 $ 23,322 Manufacturing 3,859 3,560 3,243 Plastics 1,034 1,026 1,043 Corporate and Intersegment Eliminations 1,924 2,203 2,040 Total $ 31,886 $ 31,160 $ 29,648 Income Tax Expense (Benefit) – Continuing Operations Electric $ 16,366 $ 16,067 $ 11,029 Manufacturing 2,276 2,299 4,117 Plastics 6,538 8,187 7,301 Corporate (5,099 ) (4,911 ) (5,890 ) Total $ 20,081 $ 21,642 $ 16,557 Net Income (Loss) Electric $ 49,829 $ 48,370 $ 43,684 Manufacturing 5,694 4,247 9,361 Plastics 10,628 12,108 12,085 Corporate (4,114 ) (6,136 ) (8,247 ) Discontinued Operations 284 756 840 Total $ 62,321 $ 59,345 $ 57,723 Capital Expenditures Electric $ 149,648 $ 135,572 $ 148,719 Manufacturing 8,429 20,295 11,252 Plastics 3,085 4,206 3,567 Corporate 97 11 44 Total $ 161,259 $ 160,084 $ 163,582 Identifiable Assets Electric $ 1,622,231 $ 1,520,887 $ 1,438,791 Manufacturing 166,525 173,860 128,608 Plastics 84,592 81,624 86,650 Corporate 39,037 42,312 36,508 Assets of Discontinued Operations — — 47,559 Total $ 1,912,385 $ 1,818,683 $ 1,738,116

Rate and Regulatory Matters (Ta

Rate and Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 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: ($ in thousands) Annualized or Actual Through Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 10,976 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	Rate Rider (in thousands) 2016 2015 2014 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 12,920 $ 10,724 $ 7,757 Environmental Cost Recovery 12,443 10,238 6,891 Transmission Cost Recovery 5,795 5,202 6,275 North Dakota Environmental Cost Recovery 11,089 9,502 5,872 Renewable Resource Adjustment 7,800 8,409 7,484 Transmission Cost Recovery 7,694 6,609 5,794 South Dakota Environmental Cost Recovery 2,538 1,967 234 Transmission Cost Recovery 1,820 1,290 1,207 Conservation Improvement Program Costs and Incentives 468 583 435 1

Regulatory Assets and Liabili35

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of amount of regulatory assets and liabilities	December 31, 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 $ 6,443 $ 108,267 $ 114,710 see below Deferred Marked-to-Market Losses 1 4,063 6,467 10,530 48 months Conservation Improvement Program Costs and Incentives 2 4,836 5,158 9,994 21 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,153 6,153 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 778 2,087 2,865 52 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,319 482 1,801 15 months Recoverable Fuel and Purchased Power Costs 1 1,798 — 1,798 12 months Debt Reacquisition Premiums 1 325 1,214 1,539 189 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 1,082 — 1,082 12 months Deferred Income Taxes 1 — 1,014 1,014 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 543 643 77 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 568 568 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 333 — 333 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 73 141 214 14 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 113 — 113 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 34 — 34 9 months Total Regulatory Assets $ 21,297 $ 132,094 $ 153,391 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 80,404 $ 80,404 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 1,381 782 2,163 24 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 208 919 16 months Deferred Income Taxes — 818 818 asset lives Minnesota Transmission Cost Recovery Rider Accrued Refund 757 — 757 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 285 — 285 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 139 — 139 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 132 132 24 months Other 21 89 110 204 months Total Regulatory Liabilities $ 3,294 $ 82,433 $ 85,727 Net Regulatory Asset Position $ 18,003 49,661 $ 67,664 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 North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Deferred Income Taxes 1 — 1,455 1,455 asset lives Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below 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 North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 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 South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 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 Subje36

Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables)	12 Months Ended
	Dec. 31, 2016
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]
Schedule of current fair value of these forward contract positions subject to legally enforceable netting arrangements	(in thousands) 2016 2015 Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (17,382 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (17,382 ) $ (16,070 )
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions	(in thousands) 2016 2015 Loss Contracts Covered by Deposited Funds or Letters of Credit $ — $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 17,382 15,871 Total Loss Contracts based on Current Market Values $ 17,382 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871

Common Shares and Earnings Pe37

Common Shares and Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]
Schedule of reconciliation of Company's common shares outstanding	Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 1,014,115 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 163,010 Cash Invested 115,801 Vesting of Executive Stock Performance Awards 54,700 Employee Stock Purchase Plan: Cash Invested 53,875 Dividends Reinvested 23,713 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,825 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, December 31, 2016 39,348,136
Schedule of outstanding stock options excluded from the calculation of diluted earnings per share	2016 2015 2014 Weighted Average Common Shares Outstanding – Basic 38,546,459 37,494,986 36,514,397 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 118,644 100,194 135,480 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 45,712 36,180 27,540 Nonvested Restricted Shares 16,778 22,848 49,998 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,417 13,488 24,048 Potentially Dilutive Stock Options — 330 1,096 Total Dilutive Shares 184,551 173,040 238,162 Weighted Average Common Shares Outstanding – Diluted 38,731,010 37,668,026 36,752,559

Share-Based Payments (Tables)

Share-Based Payments (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of stock options activity	Stock Option Activity 2016 2015 2014 Options Average Options Average Options Average Outstanding, Beginning of Year — 12,750 $ 24.93 34,700 $ 25.69 Exercised — 10,250 24.93 20,800 26.11 Forfeited or Expired — 2,500 24.93 1,150 26.495 Outstanding, End of Year — — 12,750 24.93 Exercisable, End of Year — — 12,750 24.93 Cash Received for Options Exercised $ 256,000 $ 543,000 Intrinsic Value of Options Exercised $ 75,000 $ 89,000
Schedule of the status of directors' restricted stock awards	Directors’ Restricted Stock Awards 2016 2015 2014 Shares Weighted Shares Weighted Shares Weighted Nonvested, Beginning of Year 38,217 $ 29.78 38,050 $ 27.47 42,483 $ 25.03 Granted 23,200 28.66 15,200 31.775 16,800 29.41 Vested 15,083 28.28 15,033 25.96 21,233 24.11 Forfeited — — — Nonvested, End of Year 46,334 29.71 38,217 29.78 38,050 27.47 Compensation Expense Recognized $ 491,000 $ 417,000 $ 416,000 Fair Value of Shares Vested in Year $ 427,000 $ 390,000 $ 512,000
Schedule of status of employees' restricted stock awards	Employees’ Restricted Stock Awards 2016 2015 2014 Shares Weighted Shares Weighted Shares Weighted Nonvested, Beginning of Year 13,581 $ 28.56 45,280 $ 27.46 48,315 $ 25.04 Granted — — 26,700 29.41 Vested 6,401 27.25 31,699 27.09 25,360 24.80 Forfeited — — 4,375 28.03 Nonvested, End of Year 7,180 29.72 13,581 28.56 45,280 27.46 Compensation Expense Recognized $ 96,000 $ 359,000 $ 998,000 Fair Value of Awards Vested $ 174,000 $ 859,000 $ 629,000
Schedule of status of employees' restricted stock unit awards	Employees’ Restricted Stock Unit Awards 2016 2015 2014 Restricted Weighted Restricted Weighted Restricted Weighted Nonvested, Beginning of Year 46,600 $ 23.75 45,900 $ 21.82 56,180 $ 19.79 Granted 17,220 24.54 15,650 25.89 11,800 24.95 Reinstated — — 75 30.81 Vested 12,250 19.03 12,250 19.46 14,305 18.05 Forfeited 4,200 24.51 2,700 22.84 7,850 18.90 Nonvested, End of Year 47,370 25.19 46,600 23.75 45,900 21.82 Compensation Expense Recognized $ 307,000 $ 304,000 $ 194,000 Fair Value of Awards Vested $ 233,000 $ 238,000 $ 258,000
Schedule of stock performance awards granted and amounts expensed related to the stock performance awards	Performance Maximum Target Expense Recognized 1 Earned 2016 2015 2014 2016-2018 122,250 81,500 $ 798,000 2015-2017 126,450 84,300 535,000 $ 943,000 2014-2016 159,450 106,300 332,000 (64,000 ) $ 1,422,000 121,491 2013-2015 90,600 45,300 — (445,000 ) 458,000 22,500 2012-2014 148,400 74,200 — — 142,000 89,991 Total $ 1,665,000 $ 434,000 $ 2,022,000 233,982 1
Executive Officers
Schedule of status of employees' restricted stock awards	Executives’ Restricted Stock Unit Awards 2016 2015 Restricted Weighted Restricted Weighted Nonvested, Beginning of Year 24,300 $ 31.682 — Granted 22,000 28.915 29,100 $ 31.681 Vested 4,475 31.69 4,800 31.675 Forfeited — — Nonvested, End of Year 41,825 30.23 24,300 31.682 Compensation Expense Recognized $ 446,000 $ 452,000 Fair Value of Awards Vested $ 142,000 $ 152,000
Key Employees
Schedule of status of employees' restricted stock unit awards	Grant Date Units Grant-Date Restricted Stock Units Vesting 100% on April 8, 2020 April 11, 2016 15,800 $ 24.00 Restricted Stock Units Vesting 100% on April 8, 2020 September 21, 2016 1,420 $ 30.59

Commitments and Contingencies39

Commitments and Contingencies of Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of amounts of commitments under construction programs, capacity and energy agreements, coal and coal delivery contracts and operating leases	Construction Capacity and Coal Operating Leases (in thousands) Commitments Requirements Commitments OTP Nonelectric Total 2017 $ 74,328 $ 23,711 $ 30,699 $ 2,374 $ 4,760 $ 7,134 2018 7,139 24,356 21,563 1,513 4,129 5,642 2019 3,331 24,925 22,102 1,237 2,598 3,835 2020 — 24,844 22,331 1,251 2,259 3,510 2021 — 12,988 22,840 1,103 1,996 3,099 Beyond 2021 — 166,137 550,719 9,396 7,320 16,716 Total $ 84,798 $ 276,961 $ 670,254 $ 16,874 $ 23,062 $ 39,936

Short-Term and Long-Term Borr40

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Tables)	12 Months Ended
	Dec. 31, 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 $ 130,000 $ — $ — $ 130,000 $ 90,334 OTP Credit Agreement 170,000 42,883 50 127,067 148,694 Total $ 300,000 $ 42,883 $ 50 $ 257,067 $ 239,028
Schedule of short-term and long-term debt outstanding	December 31, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 42,883 $ — $ 42,883 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 15,000 $ 15,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 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 106 106 PACE Note, 2.54%, due March 18, 2021 836 836 Total $ 445,000 $ 95,942 $ 540,942 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,970 231 33,201 Unamortized Long-Term Debt Issuance Costs 1,861 539 2,400 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,169 $ 95,172 $ 505,341 Total Short-Term and Long-Term Debt (with current maturities) $ 486,022 $ 95,403 $ 581,425 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 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
Schedule of aggregate amounts of maturities on bonds outstanding and other long-term obligations	(in thousands) 2017 2018 2019 2020 2021 Aggregate Amounts of Debt Maturities $ 33,231 $ 15,187 $ 172 $ 185 $ 140,171

Pension Plan and Other Postre41

Pension Plan and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Pension Plan
Schedule of components of net periodic benefit cost	(in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 5,518 $ 6,059 $ 4,666 Interest Cost on Projected Benefit Obligation 14,195 13,344 13,111 Expected Return on Assets (19,454 ) (18,383 ) (16,743 ) Amortization of Prior Service Cost: From Regulatory Asset 189 188 257 From Other Comprehensive Income 1 5 5 7 Amortization of Net Actuarial Loss: From Regulatory Asset 5,153 6,676 3,400 From Other Comprehensive Income 1 127 171 83 Net Periodic Pension Cost $ 5,733 $ 8,060 $ 4,781 1
Schedule of weighted-average assumptions used to determine net periodic benefit cost	2016 2015 2014 Discount Rate 4.76 % 4.35 % 5.30 % Long-Term Rate of Return on Plan Assets 7.75 % 7.75 % 7.75 % Rate of Increase in Future Compensation Level 3.13 % 3.13 % 3.13 %
Schedule of amounts recognized in consolidated balance sheets	(in thousands) 2016 2015 Regulatory Assets: Unrecognized Prior Service Cost $ 141 $ 329 Unrecognized Actuarial Loss 98,039 101,974 Total Regulatory Assets $ 98,180 $ 102,303 Accumulated Other Comprehensive Loss: Unrecognized Prior Service Cost $ 12 $ 16 Unrecognized Actuarial Loss 406 820 Total Accumulated Other Comprehensive Loss $ 418 $ 836 Noncurrent Liability $ 60,292 $ 69,101
Schedule of funded status	(in thousands) 2016 2015 Accumulated Benefit Obligation $ (281,414 ) $ (268,387 ) Projected Benefit Obligation $ (314,637 ) $ (302,740 ) Fair Value of Plan Assets 254,345 233,639 Funded Status $ (60,292 ) $ (69,101 )
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	(in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ 233,639 $ 244,589 Actual Return on Plan Assets 23,794 (9,160 ) Discretionary Company Contributions 10,000 10,000 Benefit Payments (13,088 ) (11,790 ) Fair Value of Plan Assets at December 31 $ 254,345 $ 233,639 Estimated Asset Return 10.1 % (3.7 )% Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 302,740 $ 311,650 Service Cost 5,518 6,059 Interest Cost 14,195 13,344 Benefit Payments (13,088 ) (11,790 ) Actuarial Loss (Gain) 5,272 (16,523 ) Projected Benefit Obligation at December 31 $ 314,637 $ 302,740
Schedule of weighted average assumptions used to determine benefit obligations	2016 2015 Discount Rate 4.60 % 4.76 % Rate of Increase in Future Compensation Level 3.00 % 3.13 %
Schedule of measurement dates	Measurement Dates: 2016 2015 Net Periodic Pension Cost January 1, 2016 January 1, 2015 End of Year Benefit Obligations January 1, 2016 projected to January 1, 2015 projected to Market Value of Assets December 31, 2016 December 31, 2015
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 120 Amortization of Unrecognized Actuarial Loss 5,090 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost 3 Amortization of Unrecognized Actuarial Loss 125 Total Estimated Amortization $ 5,338
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	(in thousands) 2017 2018 2019 2020 2021 Years $ 13,413 $ 14,140 $ 14,806 $ 15,564 $ 16,335 $ 92,083
Schedule of allocation targets and tactical ranges reflecting investment policy statement approved by BAC	Permitted Range Asset Class / PBO Funded Status < 100% PBO 100% PBO 105% PBO >=110% PBO Equity 30% - 65% 25% - 60% 20% - 55% 15% - 50% Investment Grade Fixed Income 35% - 75% 40% - 80% 45% - 85% 50% - 90% Below Investment Grade Fixed Income* 0% - 15% 0% - 15% 0% - 15% 0% - 15% Other** 0% - 20% 0% - 20% 0% - 20% 0% - 20% * Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. ** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.
Schedule Of pension plan asset allocations by asset category	Asset Allocation 2016 2015 Large Capitalization Equity Securities 21.4 % 21.2 % International Equity Securities 22.0 % 21.6 % Small and Mid-Capitalization Equity Securities 9.0 % 8.1 % SEI Dynamic Asset Allocation Fund 5.4 % 5.6 % Equity Securities 57.8 % 56.5 % Fixed-Income Securities and Cash 34.3 % 35.8 % Other – SEI Energy Debt Collective Fund 4.1 % 3.6 % Other – SEI Special Situation Collective Investment Trust 3.8 % 4.1 % 100.0 % 100.0 %
Schedule of pension fund assets measured at fair value	(in thousands) 2016 2015 Assets in Level 1 of the Fair Value Hierarchy $ 234,303 $ 215,676 SEI Energy Debt Collective Fund at NAV 10,441 8,342 SEI Special Situation Collective Investment Trust Fund at NAV (1) 9,601 9,621 Total Assets $ 254,345 $ 233,639 (1)
Schedule of pension fund assets measured at fair value including level 1 fair value hierarchy	(in thousands) 2016 2015 Large Capitalization Equity Securities Mutual Fund $ 54,483 $ 49,513 International Equity Securities Mutual Funds 55,916 50,504 Small and Mid-Capitalization Equity Securities Mutual Fund 23,011 18,823 SEI Dynamic Asset Allocation Mutual Fund 13,622 13,004 Fixed Income Securities Mutual Funds 87,268 83,830 Cash Management – Money Market Fund 3 2 Total Assets $ 234,303 $ 215,676
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Schedule of components of net periodic benefit cost	(in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 252 $ 189 $ 51 Interest Cost on Projected Benefit Obligation 1,667 1,523 1,520 Amortization of Prior Service Cost: From Regulatory Asset 16 16 22 From Other Comprehensive Income 1 38 38 51 Amortization of Net Actuarial Loss: From Regulatory Asset 293 334 142 From Other Comprehensive Income 2 446 602 46 Net Periodic Pension Cost $ 2,712 $ 2,702 $ 1,832 1 Electric Operation and Maintenance Expenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31 2 Electric Operation and Maintenance Expenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86 )
Schedule of weighted-average assumptions used to determine net periodic benefit cost	2016 2015 2014 Discount Rate 4.76 % 4.35 % 5.30 % Rate of Increase in Future Compensation Level 3.13 % 3.15 % 3.18 %
Schedule of amounts recognized in consolidated balance sheets	(in thousands) 2016 2015 Regulatory Assets: Unrecognized Prior Service Cost $ 58 $ 75 Unrecognized Actuarial Loss 2,890 2,936 Total Regulatory Assets $ 2,948 $ 3,011 Projected Benefit Obligation Liability – Net Amount Recognized $ (37,335 ) $ (35,811 ) Accumulated Other Comprehensive Loss: Unrecognized Prior Service Cost $ 134 $ 172 Unrecognized Actuarial Loss 5,915 5,815 Total Accumulated Other Comprehensive Loss $ 6,049 $ 5,987
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	(in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ — $ — Actual Return on Plan Assets — — Employer Contributions 1,188 1,119 Benefit Payments (1,188 ) (1,119 ) Fair Value of Plan Assets at December 31 $ — $ — Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 35,811 $ 35,650 Service Cost 252 189 Interest Cost 1,667 1,523 Benefit Payments (1,188 ) (1,119 ) Plan Amendments — — Actuarial Loss (Gain) 793 (432 ) Projected Benefit Obligation at December 31 $ 37,335 $ 35,811
Schedule of weighted average assumptions used to determine benefit obligations	2016 2015 Discount Rate 4.60 % 4.76 % Rate of Increase in Future Compensation Level 3.00 % 3.13 %
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 16 Amortization of Unrecognized Actuarial Loss 285 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost 38 Amortization of Unrecognized Actuarial Loss 440 Total Estimated Amortization $ 779
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	Years (in thousands) 2017 2018 2019 2020 2021 2022-2026 $ 1,253 $ 1,487 $ 1,562 $ 1,544 $ 1,754 $ 12,700
Other Postretirement Benefits
Schedule of components of net periodic benefit cost	(in thousands) 2016 2015 2014 Service Cost–Benefit Earned During the Period $ 1,301 $ 1,297 $ 1,055 Interest Cost on Projected Benefit Obligation 2,503 2,097 2,200 Amortization of Prior Service Cost From Regulatory Asset 134 205 205 From Other Comprehensive Income 1 3 5 5 Amortization of Net Actuarial Loss From Regulatory Asset 379 — — From Other Comprehensive Income 1 9 — — Net Periodic Postretirement Benefit Cost $ 4,329 $ 3,604 $ 3,465 Effect of Medicare Part D Subsidy $ (923 ) $ (1,487 ) $ (948 ) 1
Schedule of weighted-average assumptions used to determine net periodic benefit cost	2016 2015 2014 Discount Rate 4.57 % 4.20 % 5.10 %
Schedule of amounts recognized in consolidated balance sheets	(in thousands) 2016 2015 Regulatory Asset: Unrecognized Prior Service Cost $ (4 ) $ 129 Unrecognized Net Actuarial Loss 13,586 1,289 Net Regulatory Asset $ 13,582 $ 1,418 Projected Benefit Obligation Liability – Net Amount Recognized $ (62,571 ) $ (48,730 ) Accumulated Other Comprehensive (Income) Loss: Unrecognized Prior Service Cost $ 4 $ 8 Unrecognized Net Actuarial Gain (171 ) (347 ) Accumulated Other Comprehensive Income $ (167 ) $ (339 )
Schedule of funded status	(in thousands) 2016 2015 Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ — $ — Actual Return on Plan Assets — — Company Contributions 2,825 2,365 Benefit Payments (Net of Medicare Part D Subsidy) (5,908 ) (5,324 ) Participant Premium Payments 3,083 2,959 Fair Value of Plan Assets at December 31 $ — $ — Reconciliation of Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 48,730 $ 53,638 Service Cost (Net of Medicare Part D Subsidy) 1,301 1,297 Interest Cost (Net of Medicare Part D Subsidy) 2,503 2,097 Benefit Payments (Net of Medicare Part D Subsidy) (5,908 ) (5,324 ) Participant Premium Payments 3,083 2,959 Actuarial Loss (Gain) 12,862 (5,937 ) Projected Benefit Obligation at December 31 $ 62,571 $ 48,730 Reconciliation of Accrued Postretirement Cost: Accrued Postretirement Cost at January 1 $ (47,652 ) $ (46,413 ) Expense (4,329 ) (3,604 ) Net Company Contribution 2,825 2,365 Accrued Postretirement Cost at December 31 $ (49,156 ) $ (47,652 )
Schedule of weighted average assumptions used to determine benefit obligations	2016 2015 Discount Rate 4.46 % 4.57 %
Schedule of healthcare cost-trend rates	2016 2015 Healthcare Cost-Trend Rate Assumed for Next Year Pre-65 6.01 % 6.16 % Healthcare Cost-Trend Rate Assumed for Next Year Post-65 6.23 % 6.43 % Rate to Which the Cost-Trend Rate is Assumed to Decline 4.50 % 4.50 % Year the Rate Reaches the Ultimate Trend Rate 2038 2038
Schedule of effects of one percentage change in assumed healthcare cost-trend rates	(in thousands) 1 Point 1 Point Effect on the Postretirement Benefit Obligation $ 7,151 $ (7,492 ) Effect on Total of Service and Interest Cost $ 653 $ (519 ) Effect on Expense $ 1,454 $ (907 )
Schedule of measurement dates	Measurement Dates: 2016 2015 Net Periodic Postretirement Benefit Cost January 1, 2016 January 1, 2015 End of Year Benefit Obligations January 1, 2016 projected to January 1, 2015 projected to
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands) 2017 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ — Amortization of Unrecognized Actuarial Loss 932 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost — Amortization of Unrecognized Actuarial Loss 23 Total Estimated Amortization $ 955
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	Years (in thousands) 2017 2018 2019 2020 2021 2022-2026 $ 3,512 $ 3,669 $ 3,828 $ 3,912 $ 4,046 $ 20,377

Fair Value of Financial Instr42

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of long-term debt including current maturities	December 31, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Cash and Cash Equivalents $ — $ — $ — $ — Short-Term Debt (42,883 ) (42,883 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (538,542 ) (583,835 ) (496,268 ) (561,245 )

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Schedule of property, plant and equipment	(in thousands) December 31, December 31, Electric Plant in Service Production $ 891,330 $ 879,121 Transmission 410,679 391,941 Distribution 466,285 451,820 General 92,063 97,881 Electric Plant in Service 1,860,357 1,820,763 Construction Work in Progress 149,997 64,117 Total Gross Electric Plant 2,010,354 1,884,880 Less Accumulated Depreciation and Amortization 622,657 592,001 Net Electric Plant $ 1,387,697 $ 1,292,879 Nonelectric Operations Plant Equipment $ 155,809 $ 155,715 Buildings and Leasehold Improvements 51,323 41,149 Land 4,694 4,479 Nonelectric Operations Plant 211,826 201,343 Construction Work in Progress 3,264 15,495 Total Gross Nonelectric Plant 215,090 216,838 Less Accumulated Depreciation and Amortization 125,562 121,903 Net Nonelectric Operations Plant $ 89,528 $ 94,935 Net Plant $ 1,477,225 $ 1,387,814
Schedule of estimated service lives for properties	Service Life Range (years) Low High Electric Fixed Assets: Production Plant 9 82 Transmission Plant 42 70 Distribution Plant 5 68 General Plant 5 50 Nonelectric Fixed Assets: Equipment 3 12 Buildings and Leasehold Improvements 7 40

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of income from continuing operations before income taxes and income tax expense	(in thousands) 2016 2015 2014 Tax Computed at Federal Statutory Rate – Continuing Operations $ 28,741 $ 28,081 $ 25,704 Increases (Decreases) in Tax from: Federal PTCs (7,175 ) (6,962 ) (7,517 ) State Income Taxes Net of Federal Income Tax Expense 2,848 4,945 1,993 North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850 ) (850 ) (849 ) Corporate-owned Life Insurance (680 ) (167 ) (354 ) Dividend Received/Paid Deduction (537 ) (560 ) (622 ) Section 199 Domestic Production Activities Deduction (482 ) — (1,026 ) Investment Tax Credit Amortization (350 ) (571 ) (597 ) Allowance for Funds Used During Construction – Equity (280 ) (426 ) (505 ) Differences Reversing in Excess of Federal Rates 77 (1,143 ) (106 ) Permanent and Other Differences (1,231 ) (705 ) 436 Total Income Tax Expense – Continuing Operations $ 20,081 $ 21,642 $ 16,557 Income Tax Expense – Discontinued Operations – U.S. 138 2,991 3,952 Income Tax Expense – Continuing and Discontinued Operations $ 20,219 $ 24,633 $ 20,509 Overall Effective Federal, State and Foreign Income Tax Rate 24.5 % 29.3 % 26.2 % Income Tax Expense From Continuing Operations Includes the Following: Current Federal Income Taxes $ 1,070 $ 211 $ 124 Current State Income Taxes 1,211 1 5 Deferred Federal Income Taxes 23,586 23,050 21,044 Deferred State Income Taxes 2,589 6,763 4,347 Federal PTCs (7,175 ) (6,962 ) (7,517 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850 ) (850 ) (849 ) Investment Tax Credit Amortization (350 ) (571 ) (597 ) Total $ 20,081 $ 21,642 $ 16,557 Total Income Before Income Taxes – Continuing and Discontinued Operations $ 82,540 $ 83,978 $ 78,232
Schedule of deferred tax assets and liabilities	(in thousands) 2016 2015 Deferred Tax Assets Benefit Liabilities $ 44,381 $ 41,788 Federal PTCs 43,433 39,505 Retirement Benefits Liabilities 38,390 41,958 North Dakota Wind Tax Credits 32,962 32,962 Cost of Removal 31,636 29,463 Differences Related to Property 9,876 10,177 Net Operating Loss Carryforward 3,865 22,824 Vacation Accrual 2,725 2,500 Investment Tax Credits 818 1,109 Other 7,793 7,617 Total Deferred Tax Assets $ 215,879 $ 229,903 Deferred Tax Liabilities Differences Related to Property $ (371,761 ) $ (366,234 ) Retirement Benefits Regulatory Asset (38,390 ) (41,958 ) Excess Tax over Book Pension (15,509 ) (13,775 ) North Dakota Wind Tax Credits (3,654 ) (3,179 ) Impact of State Net Operating Losses on Federal Taxes (1,352 ) (1,596 ) Other (11,804 ) (10,830 ) Total Deferred Tax Liabilities $ (442,470 ) $ (437,572 ) Deferred Income Taxes $ (226,591 ) $ (207,669 )
Schedule of tax credits and tax net operating losses available	(in thousands) Amount 2017 2027-36 United States Federal Net Operating Losses $ — $ — $ — Federal Tax Credits 46,435 — 46,435 State Net Operating Losses 3,865 — 3,865 State Tax Credits 33,993 389 33,604
Schedule of activity related to unrecognized tax benefits	(in thousands) 2016 2015 2014 Balance on January 1 $ 468 $ 222 $ 4,239 Increases Related to Tax Positions for Prior Years 406 236 120 Decreases Related to Tax Positions for Prior Years — — (4,142 ) Increases Related to Tax Positions for Current Year 114 10 5 Uncertain Positions Resolved During Year (97 ) — — Balance on December 31 $ 891 $ 468 $ 222

Asset Retirement Obligations 45

Asset Retirement Obligations (AROs) (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of reconciliations of carrying amounts of present value of legal AROs, capitalized asset retirement costs and related accumulated depreciation and summary of settlement activity	(in thousands) 2016 2015 Asset Retirement Obligations Beginning Balance $ 8,084 $ 7,721 New Obligations Recognized — 451 Adjustments Due to Revisions in Cash Flow Estimates (103 ) (424 ) Accrued Accretion 360 336 Settlements — — Ending Balance $ 8,341 $ 8,084 Asset Retirement Costs Capitalized Beginning Balance $ 3,086 $ 3,059 New Obligations Recognized — 451 Adjustments Due to Revisions in Cash Flow Estimates (103 ) (424 ) Settlements — — Ending Balance $ 2,983 $ 3,086 Accumulated Depreciation – Asset Retirement Costs Capitalized Beginning Balance $ 673 $ 527 New Obligations Recognized — — Adjustments Due to Revisions in Cash Flow Estimates — — Depreciation Expense 122 146 Settlements — — Ending Balance $ 795 $ 673 Settlements None None Original Capitalized Asset Retirement Cost – Retired $ — $ — Accumulated Depreciation — — Asset Retirement Obligation $ — $ — Settlement Cost — — Gain on Settlement – Deferred Under Regulatory Accounting $ — $ —

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 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	For the Year Ended December 31, 2016 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Expenses $ 250 $ — $ (757 ) $ 85 $ — $ (422 ) Income Tax (Benefit) Expense (136 ) 5 303 (34 ) — 138 Net (Loss) Income $ (114 ) $ (5 ) $ 454 $ (51 ) $ — $ 284 For the Year Ended December 31, 2015 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Revenues $ 21,625 $ 2,998 $ — $ — $ — $ 24,623 Operating Expenses 26,839 4,532 (462 ) 966 (240 ) 31,635 Asset Impairment Charge 1,000 — — — — 1,000 Interest Expense 177 27 — — (204 ) — Other Income (Deductions) (42 ) 2 111 — (2 ) 69 Income Tax (Benefit) Expense (921 ) (638 ) 229 (386 ) 177 (1,539 ) Net (Loss) Income from Operations (5,512 ) (921 ) 344 (580 ) 265 (6,404 ) (Loss) Gain on Disposition Before Taxes (204 ) 11,894 — — — 11,690 Income Tax (Benefit) Expense on Disposition (227 ) 4,757 — — — 4,530 Net Gain on Disposition 23 7,137 — — — 7,160 Net (Loss) Income $ (5,489 ) $ 6,216 $ 344 $ (580 ) $ 265 $ 756 For the Year Ended December 31, 2014 (in thousands) Foley AEV, Inc. Wind Dock and Intercompany Total Operating Revenues $ 105,333 $ 44,527 $ — $ — $ — $ 149,860 Operating Expenses 100,826 40,297 19 (180 ) (960 ) 140,002 Asset Impairment Charge 5,605 — — — — 5,605 Interest Expense 510 184 — — (694 ) — Other (Deductions) Income (38 ) 304 — 277 (4 ) 539 Income Tax Expense (Benefit) 1,388 1,729 (8 ) 183 660 3,952 Net (Loss) Income $ (3,034 ) $ 2,621 $ (11 ) $ 274 $ 990 $ 840 December 31, 2016 (in thousands) Foley AEV, Inc. Wind Dock and Total Current Liabilities $ — $ — $ 589 $ 774 $ 1,363 Liabilities of Discontinued Operations $ — $ — $ 589 $ 774 $ 1,363 December 31, 2015 (in thousands) Foley AEV, Inc. Wind Dock and Total Current Liabilities $ — $ — $ 1,299 $ 799 $ 2,098 Liabilities of Discontinued Operations $ — $ — $ 1,299 $ 799 $ 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 (24 ) (124 ) Decrease in Warranty Estimates for Prior Years (710 ) (300 ) Warranty Reserve Balance, December 31 $ 1,369 $ 2,103

Subsequent Events (Tables)

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Schedule of stock incentive awards under the 2014 Stock Incentive Plan	Award Shares/Units Weighted Vesting Restricted Stock Units Granted 15,900 $ 37.65 25% per year through February 6, 2021 Stock Performance Awards Granted 59,500 $ 31.00 December 31, 2019

Summary of Significant Accoun48

Summary of Significant Accounting Policies - OTP's Ownership Interests in Jointly Owned Facilities (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Big Stone Plant
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service		$ 328,809	$ 327,474
Construction Work in Progress		23	(305)
Accumulated Depreciation		(65,665)	(57,641)
Net Plant		263,167	269,528
Coyote Station
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service		176,315	165,497
Construction Work in Progress		113	7,405
Accumulated Depreciation		(101,499)	(103,822)
Net Plant		74,929	69,080
Fargo-Monticello 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service		78,298	78,272
Construction Work in Progress
Accumulated Depreciation		(3,511)	(2,213)
Net Plant		74,787	76,059
Brookings-Southeast Twin Cities 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	[1]	26,406	26,189
Construction Work in Progress	[1]
Accumulated Depreciation	[1]	(924)	(486)
Net Plant	[1]	25,482	25,703
Bemidji-Grand Rapids 230 kV line
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service		16,331	16,331
Construction Work in Progress
Accumulated Depreciation		(1,573)	(1,233)
Net Plant		14,758	15,098
Big Stone South to Brookings 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	[1]
Construction Work in Progress	[1]	45,050	14,210
Accumulated Depreciation	[1]
Net Plant	[1]	45,050	14,210
Big Stone South to Ellendale 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	[1]
Construction Work in Progress	[1]	49,160	8,335
Accumulated Depreciation	[1]
Net Plant	[1]	$ 49,160	$ 8,335
Otter Tail Power Company | Big Stone Plant
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage		53.90%	53.90%
Otter Tail Power Company | Coyote Station
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage		35.00%	35.00%
Otter Tail Power Company | Fargo-Monticello 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage		14.20%	14.20%
Otter Tail Power Company | Brookings-Southeast Twin Cities 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage	[1]	4.80%	4.80%
Otter Tail Power Company | Bemidji-Grand Rapids 230 kV line
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage		14.80%	14.80%
Otter Tail Power Company | Big Stone South to Brookings 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage	[1]	50.00%	50.00%
Otter Tail Power Company | Big Stone South to Ellendale 345 kV line
Jointly Owned Utility Plant Interests [Line Items]
Ownership Percentage	[1]	50.00%	50.00%
[1]	Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Breakdown of Investments (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule of Investments [Line Items]
Marketable Securities Classified as Available-for-Sale	$ 8,225	$ 8,093
Total Investments	8,417	10,284
Investments	8,417	8,284
AEV, Inc.
Schedule of Investments [Line Items]
Escrow Funds Reported Under Other Current Assets		(1,500)
Foley Company
Schedule of Investments [Line Items]
Escrow Funds Reported Under Other Current Assets		(500)
Economic Development Loan Pools
Schedule of Investments [Line Items]
Cost Method	54	81
Other
Schedule of Investments [Line Items]
Cost Method	115	2,088
Equity Method Partnerships
Schedule of Investments [Line Items]
Equity Method	$ 23	$ 22

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details 2) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Level 1
Assets:
Total Assets	$ 849	$ 2,196
Level 1 | Money Market Escrow Accounts - AEV, Inc. and Foley Company Sales
Assets:
Current Assets - Other		2,000
Level 1 | Money Market and Mutual Funds
Assets:
Other Assets - Nonqualified Retirement Savings Plan	849	196
Level 2
Assets:
Total Assets	8,225	8,093
Liabilities
Total Liabilities		199
Level 2 | Forward Gasoline Purchase Contracts
Liabilities
Other Accrued Liabilities - Derivative Liabilities		199
Level 2 | Corporate Debt Securities
Assets:
Investments Held by Captive Insurance Company	5,280	3,858
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities - Held by Captive Insurance Company
Assets:
Investments Held by Captive Insurance Company	$ 2,945	$ 4,235

Summary of Significant Accoun51

Summary of Significant Accounting Policies - Inventories (Details 3) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Finished Goods	$ 27,755	$ 25,971
Work in Process	11,754	12,821
Raw Material, Fuel and Supplies	44,231	46,624
Total Inventories	$ 83,740	$ 85,416

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Gross Balance	$ 39,732	$ 31,488
Accumulated Impairments
Balance (net of impairments)	39,732	31,488
Adjustments and Additions to Goodwill	(2,160)	8,244
Balance (net of impairments)	37,572	39,732
Manufacturing
Goodwill [Roll Forward]
Gross Balance	20,430	12,186
Accumulated Impairments
Balance (net of impairments)	20,430	12,186
Adjustments and Additions to Goodwill	(2,160)	8,244
Balance (net of impairments)	18,270	20,430
Plastics
Goodwill [Roll Forward]
Gross Balance	19,302	19,302
Accumulated Impairments
Balance (net of impairments)	19,302	19,302
Adjustments and Additions to Goodwill
Balance (net of impairments)	$ 19,302	$ 19,302

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Components of Intangible Assets (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	$ 23,081	$ 22,999
Amortized Intangible Assets, Accumulated Amortization	8,123	7,326
Amortized Intangible Assets, Net Carrying Amount	14,958	15,673
Customer Relationships
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	22,491	21,681
Amortized Intangible Assets, Accumulated Amortization	7,861	6,714
Amortized Intangible Assets, Net Carrying Amount	$ 14,630	$ 14,967
Customer Relationships | Minimum
Amortizable Intangible Assets:
Remaining Amortization Periods	36 months	48 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Remaining Amortization Periods	224 months	236 months
Covenant not to Compete
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	$ 590	$ 620
Amortized Intangible Assets, Accumulated Amortization	262	69
Amortized Intangible Assets, Net Carrying Amount	$ 328	$ 551
Remaining Amortization Periods	20 months	32 months
Other Intangible Assets
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount		$ 639
Amortized Intangible Assets, Accumulated Amortization		543
Amortized Intangible Assets, Net Carrying Amount		$ 96
Remaining Amortization Periods		9 months
Emission Allowances
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount		$ 59
Amortized Intangible Assets, Net Carrying Amount		$ 59

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 1,436	$ 1,127	$ 977

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangible Assets (Details 7) $ in Thousands	Dec. 31, 2016USD ($)
Estimated Amortization Expense - Intangible Assets
2,017	$ 1,330
2,018	1,264
2,019	1,133
2,020	1,099
2,021	$ 1,099

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information of Noncash Investing Activities (Details 8) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$ 13,533	$ 20,371

Summary of Significant Accoun57

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information Of Cash Paid During Year (Details 9) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Paid (Received) During the Year for:
Interest (net of amount capitalized)	$ 31,269	$ 30,512	$ 26,364
Income Taxes	$ (1,291)	$ 7,322	$ 145

Summary of Significant Accoun58

Summary of Significant Accounting Policies - Effect of applying the guidance in ASU 2015-17 retrospectively to consolidated balance sheet (Details 10) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets [Abstract]
Other Assets	$ 34,104	$ 32,784
Total Assets	1,912,385	1,818,683	$ 1,738,116
Current Liabilities
Current Maturities of Long-Term Debt	33,201	52,422
Total Current Liabilities	215,671	271,116
Capitalization
Long-Term Debt - Net	505,341	443,846
Total Capitalization	1,175,445	1,048,869
Total Liabilities and Equity	$ 1,912,385	1,818,683
Previously Stated
Assets [Abstract]
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
Assets [Abstract]
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 Accoun59

Summary of Significant Accounting Policies - Balance Sheet Account Affected, Effective January 1, 2016 (Details 11)	Dec. 31, 2016USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Balance Sheet Account Affected, Effective January 1, 2016	$ 1,869,000
Adjustment to Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Balance Sheet Account Affected, Effective January 1, 2016	(623,000)
Long-Term Incentive Payable
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Balance Sheet Account Affected, Effective January 1, 2016	(1,453,000)
Deferred Taxes
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Balance Sheet Account Affected, Effective January 1, 2016	(416,000)
Miscellaneous Paid-In Capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Balance Sheet Account Affected, Effective January 1, 2016	$ 2,492,000

Summary of Significant Accoun60

Summary of Significant Accounting Policies (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Electric Plant
Significant Accounting Policies [Line Items]
Interest capitalized on a plant	$ 495,000	$ 723,000	$ 689,000
Provisions for utility depreciation	2.88%	2.61%	2.89%
Electric Plant | Minimum
Significant Accounting Policies [Line Items]
Estimated useful lives of Property and equipment	5 Years
Electric Plant | Maximum
Significant Accounting Policies [Line Items]
Estimated useful lives of Property and equipment	82 Years
Nonelectric Plant | Minimum
Significant Accounting Policies [Line Items]
Estimated useful lives of Property and equipment	3 years
Nonelectric Plant | Maximum
Significant Accounting Policies [Line Items]
Estimated useful lives of Property and equipment	40 years

Summary of Significant Accoun61

Summary of Significant Accounting Policies (Detail Textuals 1) - Coyote Creek Mining Company, L.L.C. (CCMC) - Lignite Sales Agreement - Otter Tail Power Company $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Significant Accounting Policies [Line Items]
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	$ 60.6

Summary of Significant Accoun62

Summary of Significant Accounting Policies (Detail Textuals 2) - USD ($)	Sep. 01, 2015	Jun. 30, 2016	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Significant Accounting Policies [Line Items]
Goodwill				$ 31,488,000	$ 37,572,000	$ 39,732,000
Reduction in acquired goodwill					(2,160,000)	$ 8,244,000
Cumulative-effect net-of-tax adjustment to retained earnings					1,869,000
Adjustment to Retained Earnings
Significant Accounting Policies [Line Items]
Cumulative-effect net-of-tax adjustment to retained earnings					$ (623,000)
Impulse Manufacturing Inc | Customer Relationships
Significant Accounting Policies [Line Items]
Value of intangible assets acquired	$ 4,870,000
Amortization period	20 years
Increase (decrease) in the fair value of asset acquired		$ 810,000
Impulse Manufacturing Inc | Covenant not to Compete
Significant Accounting Policies [Line Items]
Value of intangible assets acquired	$ 620,000
Amortization period	3 years
Increase (decrease) in the fair value of asset acquired		(30,000)
Foley Company
Significant Accounting Policies [Line Items]
Goodwill impairment charge			$ 1,000,000	$ 5,600,000
Miller Welding & Iron Works, Inc. (BTD-Illinois) | Impulse Manufacturing Inc
Significant Accounting Policies [Line Items]
Goodwill	$ 8,200,000
Reduction in acquired goodwill		$ 2,200,000

Business Combinations, Dispos63

Business Combinations, Dispositions and Segment Information (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Sep. 01, 2015	Dec. 31, 2014
Assets:
Goodwill	$ 37,572	$ 39,732		$ 31,488
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, Dispos64

Business Combinations, Dispositions and Segment Information - Information on Continuing Operations for Business Segments (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating Revenue	$ 803,539	$ 779,804	$ 799,262
Cost of Products Sold	295,222	295,032	308,069
Other Nonelectric Expenses	40,264	40,021	45,981
Depreciation and Amortization	73,445	60,363	58,074
Operating Income (Loss)	111,099	109,214	99,531
Interest Charges	31,886	31,160	29,648
Income Tax Expense (Benefit) - Continuing Operations	20,081	21,642	16,557
Net Income (Loss)	62,321	59,345	57,723
Capital Expenditures	161,259	160,084	163,582
Identifiable Assets	1,912,385	1,818,683	1,738,116
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income (Loss)	284	756	840
Identifiable Assets			47,559
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(34)	(96)	(114)
Cost of Products Sold	(6)	(9)	(45)
Other Nonelectric Expenses	(28)	(87)	(69)
Corporate
Segment Reporting Information [Line Items]
Other Nonelectric Expenses	8,896	9,143	13,418
Depreciation and Amortization	47	172	116
Operating Income (Loss)	(8,943)	(9,315)	(13,534)
Interest Charges	1,924	2,203	2,040
Income Tax Expense (Benefit) - Continuing Operations	(5,099)	(4,911)	(5,890)
Net Income (Loss)	(4,114)	(6,136)	(8,247)
Capital Expenditures	97	11	44
Identifiable Assets	39,037	42,312	36,508
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	427,383	407,131	407,743
Depreciation and Amortization	53,743	44,786	44,076
Operating Income (Loss)	90,131	87,171	76,060
Interest Charges	25,069	24,371	23,322
Income Tax Expense (Benefit) - Continuing Operations	16,366	16,067	11,029
Net Income (Loss)	49,829	48,370	43,684
Capital Expenditures	149,648	135,572	148,719
Identifiable Assets	1,622,231	1,520,887	1,438,791
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	221,289	215,011	219,583
Cost of Products Sold	171,732	171,956	169,033
Other Nonelectric Expenses	21,994	21,115	23,340
Depreciation and Amortization	15,794	11,853	10,518
Operating Income (Loss)	11,769	10,086	16,692
Interest Charges	3,859	3,560	3,243
Income Tax Expense (Benefit) - Continuing Operations	2,276	2,299	4,117
Net Income (Loss)	5,694	4,247	9,361
Capital Expenditures	8,429	20,295	11,252
Identifiable Assets	166,525	173,860	128,608
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	154,901	157,758	172,050
Cost of Products Sold	123,496	123,085	139,081
Other Nonelectric Expenses	9,402	9,850	9,292
Depreciation and Amortization	3,861	3,552	3,364
Operating Income (Loss)	18,142	21,272	20,313
Interest Charges	1,034	1,026	1,043
Income Tax Expense (Benefit) - Continuing Operations	6,538	8,187	7,301
Net Income (Loss)	10,628	12,108	12,085
Capital Expenditures	3,085	4,206	3,567
Identifiable Assets	$ 84,592	$ 81,624	$ 86,650

Business Combinations, Dispos65

Business Combinations, Dispositions and Segment Information (Detail Textuals) - USD ($) $ in Thousands	Sep. 01, 2015	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Cash			$ (1,500)	$ 30,806
Revenues recorded			803,539	779,804	$ 799,262
Net loss			$ 62,321	$ 59,345	$ 57,723
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, Dispos66

Business Combinations, Dispositions and Segment Information (Detail Textuals 1) - Segment	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Number of segments	3
Operating revenues | United States
Segment Reporting Information [Line Items]
Percentage of sales revenue	98.60%	97.10%	95.90%

Rate and Regulatory Matters (De

Rate and Regulatory Matters (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Annualized or Test Year
Regulatory Matters [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
Actual Through December 31, 2016
Regulatory Matters [Line Items]
Interim Revenue Increase (subject to refund)	$ 10,976

Rate and Regulatory Matters (68

Rate and Regulatory Matters (Details 1) - 2016 Test Year Allocation $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Revenue Requirement Deficiency Cost Factors
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
Increased Rate Base
Revenue Requirement Deficiency Cost Factors
Total Requested Revenue Increase	10,000
Increased Expenses
Revenue Requirement Deficiency Cost Factors
Total Requested Revenue Increase	7,700
Other
Revenue Requirement Deficiency Cost Factors
Total Requested Revenue Increase	$ 1,596

Rate and Regulatory Matters (69

Rate and Regulatory Matters (Details 2) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Regulatory Matters [Line Items]
Revenue		$ 803,539	$ 779,804	$ 799,262
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenue	[1]	12,920	10,724	7,757
Otter Tail Power Company | Minnesota | Environmental Cost Recovery
Regulatory Matters [Line Items]
Revenue		12,443	10,238	6,891
Otter Tail Power Company | Minnesota | Transmission Cost Recovery
Regulatory Matters [Line Items]
Revenue		5,795	5,202	6,275
Otter Tail Power Company | North Dakota | Environmental Cost Recovery
Regulatory Matters [Line Items]
Revenue		11,089	9,502	5,872
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Regulatory Matters [Line Items]
Revenue		7,800	8,409	7,484
Otter Tail Power Company | North Dakota | Transmission Cost Recovery
Regulatory Matters [Line Items]
Revenue		7,694	6,609	5,794
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenue		468	583	435
Otter Tail Power Company | South Dakota | Environmental Cost Recovery
Regulatory Matters [Line Items]
Revenue		2,538	1,967	234
Otter Tail Power Company | South Dakota | Transmission Cost Recovery
Regulatory Matters [Line Items]
Revenue		$ 1,820	$ 1,290	$ 1,207
[1]	Includes MNCIP costs recovered in base rates.

Rate and Regulatory Matters (70

Rate and Regulatory Matters (Detail Textuals) - Otter Tail Power Company $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)kVmi	Dec. 31, 2011USD ($)kVmi
Regulatory Matters [Line Items]
Increase In reagent costs and emission allowances | $	$ 2.2
Big Stone South - Brookings MVP
Regulatory Matters [Line Items]
Expanded capacity of projects | kV		345
Extended distance of transmission line | mi		70
Capacity Expansion 2020 | Brookings Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest | $		$ 26
Percentage of ownership interest acquired in transmission line		4.80%
Expanded capacity of projects | kV		345
Distance of transmission line | mi		250
Capacity Expansion 2020 | Fargo Project
Regulatory Matters [Line Items]
Investment to acquire ownership interest | $	$ 81
Percentage of ownership interest acquired in transmission line	14.20%
Expanded capacity of projects | kV	345
Distance of transmission line | mi	240
Percentage of certain assets of project	100.00%
Big Stone AQCS Project BART - compliant AQCS
Regulatory Matters [Line Items]
Capitalized projected cost | $	$ 200
Federal Energy Regulatory Commission | Big Stone South - Ellendale MVP
Regulatory Matters [Line Items]
Expanded capacity of projects | kV		345
Extended distance of transmission line | mi		163
Minnesota Public Utilities Commission
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	50.00%
North Dakota Public Service Commission
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	40.00%
South Dakota Public Utilities Commission
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	10.00%

Rate and Regulatory Matters (71

Rate and Regulatory Matters (Detail Textuals 1) $ in Millions

1 Months Ended

12 Months Ended

Feb. 16, 2016

Dec. 21, 2015USD ($)

Sep. 30, 2015USD ($)

Apr. 25, 2011USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)$ / kWh

Aug. 16, 2016

May 25, 2016

Apr. 14, 2016

Apr. 01, 2016USD ($)

Jul. 09, 2015USD ($)

Sep. 26, 2014USD ($)

Otter Tail Power Company | 2016 General Rate Case

Regulatory Matters [Line Items]

Estimated interim rate refund

$ 3.6

Otter Tail Power Company | 2016 General Rate Case | Rebuttal testimony

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

10.05%

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program

Regulatory Matters [Line Items]

Financial incentives recognized during period

5.1

$ 4.2

$ 3

Decrease in estimation of kilowatt-hours for financial incentives | $ / kWh

2,000,000

Amount of financial incentive requested

$ 5.1

$ 4.3

Percentage increase in energy savings

18.00%

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%

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Minimum

Regulatory Matters [Line Items]

Percentage of operating revenue from service to be invested in energy conservation in Minnesota

1.50%

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013

Regulatory Matters [Line Items]

Financial incentive request approved

$ 4

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 To 2015

Regulatory Matters [Line Items]

Lower estimated incentives | $ / kWh

0.09

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 To 2016

Regulatory Matters [Line Items]

Lower estimated incentives | $ / kWh

0.07

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014

Regulatory Matters [Line Items]

Financial incentive request approved

$ 3

Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider

Regulatory Matters [Line Items]

Seeking revenue recovery

$ 7.2

$ 7.8

Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case

Regulatory Matters [Line Items]

General rate revenue increase approved

$ 5

Percentage of increase in base rate revenue approved by rate authority

1.60%

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

8.33%

Allowed rate of return on rate base

8.61%

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

10.43%

Allowed rate of return on equity

10.74%

Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case

Regulatory Matters [Line Items]

Allowed rate of return on rate base

8.07%

Allowed rate of return on equity

10.40%

Percentage of capital

52.50%

Increase to base rate portion of customer bills

9.56%

Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Transmission Cost Recovery Rider

Regulatory Matters [Line Items]

Allowed rate of return on rate base

100.00%

MNDOC | 2016 General Rate Case | Direct testimony

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

8.87%

MNDOC | 2016 General Rate Case | Rebuttal testimony

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

8.66%

OAG | 2016 General Rate Case | Direct testimony

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

6.96%

OAG | 2016 General Rate Case | Rebuttal testimony

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

7.14%

ALJ | 2016 General Rate Case

Regulatory Matters [Line Items]

Percentage of allowed rate of return on equity

9.54%

Rate and Regulatory Matters (72

Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - USD ($) $ in Millions	Mar. 12, 2014	Apr. 01, 2017	Dec. 30, 2016	Sep. 01, 2016	Mar. 31, 2016	Aug. 31, 2015	Jul. 01, 2015	Mar. 31, 2015	Mar. 31, 2014	Nov. 25, 2009
Renewable Resource Cost Recovery Rider
Regulatory Matters [Line Items]
Percentage of reduction in the NDRRA	13.50%
Percentage of ECR rider rate			7.005%
Allowed rate of return on equity	10.50%
Renewable Resource Cost Recovery Rider | Subsequent Event
Regulatory Matters [Line Items]
Percentage of ECR rider rate previously in effect		7.573%
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
Revenue requirement				$ 5.7
Reduction of projected over collection				$ 2.6
Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Percentage of ECR rider rate					7.904%		9.193%	7.531%	4.319%
Revenue requirement					$ 10.4		$ 12.2
General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved										$ 3.6
Percentage of increase in base rate revenue approved by MPUC										3.00%
Allowed rate of return on rate base										8.62%
Allowed rate of return on equity										10.75%

Rate and Regulatory Matters (73

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

Feb. 12, 2015

Nov. 06, 2014

Nov. 12, 2013

Sep. 28, 2016

Aug. 31, 2016

Dec. 22, 2015

Aug. 31, 2015

Apr. 21, 2011

Dec. 31, 2016

Dec. 31, 2015

Sep. 19, 2016

Jan. 31, 2012

Regulatory Matters [Line Items]

Regulatory liabilities

$ 85,727,000

$ 80,754,000

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

Regulatory Matters [Line Items]

Annual Revenue Requesting Recovery

$ 2,300,000

$ 2,700,000

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 approved by MPUC

2.32%

Allowed rate of return on rate base

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%

Proposed reduced return on equity used in transmission rates

8.67%

9.15%

Current return on equity used in transmission rates

12.38%

10.32%

Additional Incentive Basis Point

50-basis points

Expected percentage of return on equity

10.82%

9.70%

Expected percentage of return on equity description

ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder)

Reductions in revenue

1,600,000

$ 1,100,000

Regulatory liabilities

$ 2,700,000

Regulatory Assets and Liabili74

Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current		$ 21,297	$ 18,904
Regulatory Liabilities - Current		3,294	3,322
Net Regulatory Asset Position - Current		18,003	15,582
Regulatory Assets - Long-Term		132,094	127,707
Regulatory Liabilities - Long-Term		82,433	77,432
Net Regulatory Asset Position - Long-Term		49,661	50,275
Regulatory Assets - Total		153,391	146,611
Regulatory Liabilities - Total		85,727	80,754
Net Regulatory Asset Position		67,664	65,857
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	6,443	7,439
Regulatory Assets - Long-Term	[1]	108,267	99,293
Regulatory Assets - Total	[1]	$ 114,710	$ 106,732
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Deferred Marked-to-Market Losses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 4,063	$ 4,063
Regulatory Assets - Long-Term	[1]	6,467	10,530
Regulatory Assets - Total	[1]	$ 10,530	$ 14,593
Regulatory Assets - Remaining Recovery/Refund Period	[1]	48 months	60 months
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 4,836	$ 4,411
Regulatory Assets - Long-Term	[2]	5,158	4,266
Regulatory Assets - Total	[2]	$ 9,994	$ 8,677
Regulatory Assets - Remaining Recovery/Refund Period	[2]	21 months	18 months
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]
Regulatory Assets - Long-Term	[1]	6,153	5,672
Regulatory Assets - Total	[1]	$ 6,153	$ 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 Assets - Current	[1]	$ 778	$ 942
Regulatory Assets - Long-Term	[1]	2,087	2,620
Regulatory Assets - Total	[1]	$ 2,865	$ 3,562
Regulatory Assets - Remaining Recovery/Refund Period	[1]	52 months	84 months
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 1,319
Regulatory Assets - Long-Term	[2]	482	1,266
Regulatory Assets - Total	[2]	$ 1,801	$ 1,266
Regulatory Assets - Remaining Recovery/Refund Period	[2]	15 months	15 months
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 1,798
Regulatory Assets - Long-Term	[1]
Regulatory Assets - Total	[1]	$ 1,798
Regulatory Assets - Remaining Recovery/Refund Period	[1]	12 months
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 325	$ 351
Regulatory Assets - Long-Term	[1]	1,214	1,539
Regulatory Assets - Total	[1]	$ 1,539	$ 1,890
Regulatory Assets - Remaining Recovery/Refund Period	[1]	189 months	201 months
Minnesota Deferred Rate Case Expenses Subject to Recovery
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 1,082	$ 291
Regulatory Assets - Long-Term	[1]
Regulatory Assets - Total	[1]	$ 1,082	$ 291
Regulatory Assets - Remaining Recovery/Refund Period	[1]	12 months	12 months
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]
Regulatory Liabilities - Current
Regulatory Assets - Long-Term	[1]	1,014	1,455
Regulatory Liabilities - Long-Term		818	1,110
Regulatory Assets - Total	[1]	1,014	1,455
Regulatory Liabilities - Total		$ 818	$ 1,110
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 100	$ 100
Regulatory Assets - Long-Term	[2]	543	643
Regulatory Assets - Total	[2]	$ 643	$ 743
Regulatory Assets - Remaining Recovery/Refund Period		77 months	89 months	[2]
North Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]
Regulatory Assets - Long-Term	[2]	568
Regulatory Assets - Total	[2]	$ 568
Regulatory Assets - Remaining Recovery/Refund Period		24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 333	$ 698
Regulatory Liabilities - Current
Regulatory Assets - Long-Term	[2]		355
Regulatory Liabilities - Long-Term		132
Regulatory Assets - Total	[2]	333	$ 1,053
Regulatory Liabilities - Total		$ 132
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months	24 months
Regulatory Liabilities - Remaining Recovery/Refund Period		24 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 73	$ 33
Regulatory Assets - Long-Term	[2]	141
Regulatory Assets - Total	[2]	$ 214	$ 33
Regulatory Assets - Remaining Recovery/Refund Period	[2]	14 months	12 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 113
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]	$ 113
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 34
Regulatory Assets - Long-Term	[2]		68
Regulatory Assets - Total	[2]	$ 34	$ 68
Regulatory Assets - Remaining Recovery/Refund Period	[2]	9 months
Regulatory Assets - Remaining Recovery/Refund Period	[2]		see below
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current
Regulatory Liabilities - Long-Term		80,404	74,948
Regulatory Liabilities - Total		$ 80,404	$ 74,948
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Revenue for Rate Case Expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 711
Regulatory Liabilities - Long-Term		208	1,279
Regulatory Liabilities - Total		$ 919	$ 1,279
Regulatory Liabilities - Remaining Recovery/Refund Period		16 months
Regulatory Liabilities - Remaining Recovery/Refund Period			see below
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			$ 5
Regulatory Liabilities - Long-Term			95
Regulatory Liabilities - Total			$ 100
Regulatory Liabilities - Remaining Recovery/Refund Period			216 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]		$ 576
Regulatory Assets - Long-Term	[2]
Regulatory Assets - Total	[2]		$ 576
Regulatory Assets - Remaining Recovery/Refund Period	[2]		12 months
Refundable Fuel Clause Adjustment Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			$ 1,834
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			$ 1,834
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 139	$ 777
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 139	$ 777
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 285	$ 185
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 285	$ 185
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 Liabilities - Current		$ 1,381	$ 132
Regulatory Liabilities - Long-Term		782
Regulatory Liabilities - Total		$ 2,163	$ 132
Regulatory Assets - Remaining Recovery/Refund Period	[1]	12 months
Regulatory Liabilities - Remaining Recovery/Refund Period		24 months	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			$ 321
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			$ 321
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			$ 68
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			$ 68
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Other
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 21
Regulatory Liabilities - Long-Term		89
Regulatory Liabilities - Total		$ 110
Regulatory Liabilities - Remaining Recovery/Refund Period		204 months
Minnesota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 757
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total		$ 757
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
[1]	Costs subject to recovery without a rate of return.
[2]	Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Regulatory Assets and Liabili75

Regulatory Assets and Liabilities (Detail Textuals)	12 Months Ended
	Dec. 31, 2016
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	189 months

Open Contract Positions Subje76

Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Details) - Legally enforceable netting arrangements - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements	(17,382)	(16,070)
Net Balance Subject to Legally Enforceable Netting Arrangements	$ (17,382)	$ (16,070)

Open Contract Positions Subje77

Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Credit Derivatives [Line Items]
Loss Contracts Covered by Deposited Funds or Letters of Credit			$ 199
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	17,382	15,871
Total Loss Contracts based on Current Market Values		$ 17,382	$ 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 $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871.

Open Contract Positions Subje78

Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Parentheticals) (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 17,382	$ 15,871
Offsetting Gains with Counterparties under Master Netting Agreements
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$ 17,382	$ 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 $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871.

Common Shares and Earnings Pe79

Common Shares and Earnings Per Share - Reconciliation of Common Shares Outstanding (Details)	12 Months Ended
	Dec. 31, 2016shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance (in shares)	37,857,186
Issuances:
At-the-Market Offering	1,014,115
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	163,010
Cash Invested	115,801
Vesting of Executive Stock Performance Awards	54,700
Employee Stock Purchase Plan:
Cash Invested	53,875
Dividends Reinvested	23,713
Employee Stock Ownership Plan	23,837
Restricted Stock Issued to Directors	23,200
Vesting of Restricted Stock Units	21,825
Directors Deferred Compensation	542
Retirements:
Shares Withheld for Individual Income Tax Requirements	(3,668)
Balance (in shares)	39,348,136

Common Shares and Earnings Pe80

Common Shares and Earnings Per Share (Details 1) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	38,546,000	37,495,000	36,514,000
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	118,644	100,194	135,480
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	45,712	36,180	27,540
Nonvested Restricted Shares	16,778	22,848	49,998
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	3,417	13,488	24,048
Potentially Dilutive Stock Options		330	1,096
Total Dilutive Shares	184,551	173,040	238,162
Weighted Average Common Shares Outstanding - Diluted	38,731,000	37,668,000	36,753,000

Common Shares and Earnings Pe81

Common Shares and Earnings Per Share (Detail Textuals) - USD ($) $ / shares in Units, $ in Millions	Jan. 01, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 11, 2015
Stockholders Equity Note [Line Items]
Common shares issued for cash		53,875
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
Subsequent Event
Stockholders Equity Note [Line Items]
Percentage of market price for eligible employees to purchase shares at the end of each six month purchase period	100.00%
1999 Employee Stock Purchase Plan
Stockholders Equity Note [Line Items]
Percentage of market price for eligible employees to purchase shares at the end of each six month purchase period		85.00%
Common shares authorized for granting stock awards		1,400,000
Common shares available for grant		384,159
Common shares issued for cash		53,875	42,253	39,222
1999 Employee Stock Purchase Plan | Previously Reported
Stockholders Equity Note [Line Items]
Common shares authorized for granting stock awards		900,000
Dividend Reinvestment and Share Purchase Plan
Stockholders Equity Note [Line Items]
Common shares available for grant		918,670
Common shares issued for cash		278,811	302,519
Shelf registration for issuance of common shares					1,500,000
2014 Stock Incentive Plan
Stockholders Equity Note [Line Items]
Common shares authorized for granting stock awards		1,900,000
Common shares available for grant		1,356,811
Distribution Agreement | J.P. Morgan Securities LLC (JPMS)
Stockholders Equity Note [Line Items]
Agreement with distribution agent for offer and sale of shares, aggregate sales price					$ 75

Share-Based Payments - Summary

Share-Based Payments - Summary of Stock Options Activity (Details) - Stock options - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Options
Outstanding, Beginning of Year		12,750	34,700
Exercised		10,250	20,800
Forfeited or Expired		2,500	1,150
Outstanding, End of Year			12,750
Exercisable, End of Year			12,750
Average Exercise Price
Outstanding, Beginning of Year		$ 24.93	$ 25.69
Exercised		24.93	26.11
Forfeited or Expired		$ 24.93	26.495
Outstanding, End of Year			24.93
Exercisable, End of Year			$ 24.93
Cash Received for Options Exercised		$ 256,000	$ 543,000
Intrinsic Value of Options Exercised		$ 75,000	$ 89,000

Share-Based Payments - Summar83

Share-Based Payments - Summary of Status of Directors' Restricted Stock Awards (Details 1) - Director - Restricted Stock - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Shares
Nonvested, Beginning of Year	38,217	38,050	42,483
Granted	23,200	15,200	16,800
Vested	15,083	15,033	21,233
Forfeited
Nonvested, End of Year	46,334	38,217	38,050
Weighted Average Grant-Date Fair Value
Nonvested, Beginning of Year	$ 29.78	$ 27.47	$ 25.03
Granted	28.66	31.775	29.41
Vested	28.28	25.96	24.11
Forfeited
Nonvested, End of Year	$ 29.71	$ 29.78	$ 27.47
Compensation Expense Recognized	$ 491,000	$ 417,000	$ 416,000
Fair Value of Shares Vested in Year	$ 427,000	$ 390,000	$ 512,000

Share-Based Payments - Summar84

Share-Based Payments - Summary of Status of Employees' Restricted Stock Awards (Details 2) - Employee - Restricted Stock - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Shares
Nonvested, Beginning of Year	13,581	45,280	48,315
Granted			26,700
Awards Vested	6,401	31,699	25,360
Forfeited			4,375
Nonvested, End of Year	7,180	13,581	45,280
Weighted Average Grant-Date Fair Value
Nonvested, Beginning of Year	$ 28.56	$ 27.46	$ 25.04
Granted			29.41
Awards Vested	27.25	27.09	24.80
Forfeited			28.03
Nonvested, End of Year	$ 29.72	$ 28.56	$ 27.46
Compensation Expense Recognized	$ 96,000	$ 359,000	$ 998,000
Fair Value of Awards Vested	$ 174,000	$ 859,000	$ 629,000

Share-Based Payments - Summar85

Share-Based Payments - Summary of Status of Executive Restricted Stock Awards (Details 3) - Executives - Restricted Stock - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units
Nonvested, Beginning of Year	24,300
Granted	22,000	29,100
Vested	4,475	4,800
Forfeited
Nonvested, End of Year	41,825	24,300
Weighted Average Grant-Date Fair Value
Nonvested, Beginning of Year	$ 31.682
Granted	28.915	$ 31.681
Vested	31.69	31.675
Nonvested, End of Year	$ 30.23	$ 31.682
Compensation Expense Recognized	$ 446,000	$ 452,000
Fair Value of Awards Vested	$ 142,000	$ 152,000

Share-Based Payments - Summar86

Share-Based Payments - Summary of restricted stock unit awards granted and vested to executive officers (Details 4) - Restricted Stock Units (RSU) - Employee - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Units Granted	17,220	15,650	11,800
Grant-Date Fair Value per Award	$ 24.54	$ 25.89	$ 24.95
2014 Stock Incentive Plan | Vesting 100% on April 8, 2020 | Granted on April 11, 2016
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Units Granted	15,800
Grant-Date Fair Value per Award	$ 24
Vesting percentage	100.00%
2014 Stock Incentive Plan | Vesting 100% on April 8, 2020 | Granted on September 21, 2016
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Units Granted	1,420
Grant-Date Fair Value per Award	$ 30.59
Vesting percentage	100.00%

Share-Based Payments - Summar87

Share-Based Payments - Summary of Status of Employees' Restricted Stock Unit Awards (Details 5) - Restricted Stock Units (RSU) - Employee - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Units
Nonvested, Beginning of Year	46,600	45,900	56,180
Granted	17,220	15,650	11,800
Reinstated			75
Vested	12,250	12,250	14,305
Forfeited	4,200	2,700	7,850
Nonvested, End of Year	47,370	46,600	45,900
Weighted Average Grant-Date Fair Value
Nonvested, Beginning of Year	$ 23.75	$ 21.82	$ 19.79
Granted	24.54	25.89	24.95
Reinstated			30.81
Vested	19.03	19.46	18.05
Forfeited	24.51	22.84	18.90
Nonvested, End of Year	$ 25.19	$ 23.75	$ 21.82
Compensation Expense Recognized	$ 307,000	$ 304,000	$ 194,000
Fair Value of Awards Vested	$ 233,000	$ 238,000	$ 258,000

Share-Based Payments - Summar88

Share-Based Payments - Summary of Stock Performance Awards Granted and Amounts Expensed (Details 6) - Executive Officers - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense Recognized	[1]	$ 1,665,000	$ 434,000	$ 2,022,000
Earned Shares		233,982
Performance Period 2016 To 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		122,250
Shares Used To Estimate Expense		81,500
Expense Recognized	[1]	$ 798,000
Performance Period 2015 To 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		126,450
Shares Used To Estimate Expense		84,300
Expense Recognized	[1]	$ 535,000	943,000
Performance Period 2014 To 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		159,450
Shares Used To Estimate Expense		106,300
Expense Recognized	[1]	$ 332,000	(64,000)	1,422,000
Earned Shares		121,491
Performance Period 2013 To 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		90,600
Shares Used To Estimate Expense		45,300
Expense Recognized	[1]		(445,000)	458,000
Earned Shares		22,500
Performance Period 2012 To 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		148,400
Shares Used To Estimate Expense		74,200
Expense Recognized	[1]			$ 142,000
Earned Shares		89,991
[1]	Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards.

Share-Based Payments (Detail Te

Share-Based Payments (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Discount from average market price to purchase shares	15.00%
Investment period	6 months
Stock compensation expense	$ 173,000	$ 184,000	$ 175,000
1999 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options to purchase common stock	2,041,500

Share-Based Payments (Detail 90

Share-Based Payments (Detail Textuals 1) - Restricted Stock - $ / shares	Feb. 04, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/UnitsGranted		23,200	15,200	16,800
Forfeited
Vesting percentage		25.00%
Grant-Date Fair Value per Award		$ 28.66	$ 31.775	$ 29.41
Executive Officers | 2014 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/UnitsGranted	22,000
Vesting percentage	25.00%
Grant-Date Fair Value per Award	$ 28.915

Share-Based Payments (Detail 91

Share-Based Payments (Detail Textuals 2) - USD ($)	Feb. 04, 2016	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized amount of compensation expense related to stock-based compensation		$ 4,000,000
Weighted-average period of amortization		2 years 2 months 12 days
Chief Executive Officer | Performance Period 2014 To 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issue price per share of earned shares issued	$ 26.35
Value of earned shares issued	$ 848,000
Payout target percentage	114.29%
Chief Executive Officer | Performance Period 2012 To 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout target percentage	121.28%
Executive Officers | Performance Period 2015 To 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		126,450
Executive Officers | Performance Period 2014 To 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		159,450
Executive Officers | Performance Period 2013 To 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		90,600
Issue price per share of earned shares issued	$ 26.35
Value of earned shares issued	$ 593,000
Executive Officers | Performance Period 2012 To 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		148,400
Executive Officers | Performance Period 2016 To 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		122,250
2014 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted		1,900,000
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted	81,500
Basis for achieving performance target, description	Common shares for achieving the target set for the Company's 3-year average adjusted return on equity
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Actual payment percentage of target amount	150.00%
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Performance Target One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted	54,333
Basis for achieving performance target, description	Common shares based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018.
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Performance Target Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted	27,167
Basis for achieving performance target, description	Common shares for achieving the target set for the Company's 3-year average adjusted return on equity.
2014 Stock Incentive Plan | Restricted Stock Units (RSU) | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Awards Granted			8,900	4,900	6,600

Retained Earnings and Dividen92

Retained Earnings and Dividend Restriction (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Retained Earnings Restriction [Line Items]
Total Capitalization	$ 1,175,445,000	$ 1,048,869,000
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	52.90%
Net assets restricted from distribution	$ 440,000,000
Total Capitalization	$ 1,123,168,000
OTP | Minimum
Retained Earnings Restriction [Line Items]
Required equity to total capitalization ratio to limit dividend payment	47.50%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Required equity to total capitalization ratio to limit dividend payment	58.10%

Commitments and Contingencies93

Commitments and Contingencies of Continuing Operations - Amounts of Commitments under Construction Programs, Capacity and Energy Requirements, Coal and Coal Delivery Contracts and Operating Leases (Details) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leases
2,017	$ 7,134
2,018	5,642
2,019	3,835
2,020	3,510
2,021	3,099
Beyond 2,021	16,716
Total	39,936
OTP
Operating Leases
2,017	2,374
2,018	1,513
2,019	1,237
2,020	1,251
2,021	1,103
Beyond 2,021	9,396
Total	16,874
OTP | Construction Program and Other Commitments
Purchase Commitments
2,017	74,328
2,018	7,139
2,019	3,331
2,020
2,021
Beyond 2,021
Total	84,798
OTP | Capacity and Energy Requirements
Purchase Commitments
2,017	23,711
2,018	24,356
2,019	24,925
2,020	24,844
2,021	12,988
Beyond 2,021	166,137
Total	276,961
OTP | Coal Purchase Commitments
Purchase Commitments
2,017	30,699
2,018	21,563
2,019	22,102
2,020	22,331
2,021	22,840
Beyond 2,021	550,719
Total	670,254
Nonelectric
Operating Leases
2,017	4,760
2,018	4,129
2,019	2,598
2,020	2,259
2,021	1,996
Beyond 2,021	7,320
Total	$ 23,062

Commitments and Contingencies94

Commitments and Contingencies of Continuing Operations (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Line Items]
Rent expense from continuing operations	$ 7,565,000	$ 6,447,000	$ 10,165,000
Loss contingency, range of possible loss, maximum	1,000,000
OTP | Construction Programs and Other Commitments
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$ 84,800,000
OTP | Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year	2017 and 2040
OTP | Federal Energy Regulatory Commission
Commitments and Contingencies Disclosure [Line Items]
Estimated liability of refund obligation	$ 2,700,000

Short-Term and Long-Term Borr95

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Line Limit	$ 300,000
In Use	42,883
Restricted due to Outstanding Letters of Credit	50
Available	257,067	$ 239,028
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	130,000
In Use
Restricted due to Outstanding Letters of Credit
Available	130,000	90,334
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	42,883
Restricted due to Outstanding Letters of Credit	50
Available	$ 127,067	$ 148,694

Short-Term and Long-Term Borr96

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Breakdown of Assignment of Company's Consolidated Short-Term and Long-Term Debt Outstanding (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Short-Term Debt	$ 42,883	$ 80,672
Long-Term Debt	540,942	498,489
Less: Current Maturities - Otter Tail Corporation	33,201	52,422
Unamortized Long-Term Debt Issuance Costs	2,400	2,221
Total Long-Term Debt net of Unamortized Debt Issuance Costs	505,341	443,846
Total Short-Term and Long-Term Debt (with current maturities)	581,425	576,940
Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	15,000
3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt	80,000
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt		52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000	90,000
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	106	182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	836	977
OTP
Debt Instrument [Line Items]
Short-Term Debt	42,883	21,006
Long-Term Debt	445,000	445,000
Less: Current Maturities - Otter Tail Corporation	32,970
Unamortized Long-Term Debt Issuance Costs	1,861	2,099
Total Long-Term Debt net of Unamortized Debt Issuance Costs	410,169	442,901
Total Short-Term and Long-Term Debt (with current maturities)	486,022	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		59,666
Long-Term Debt	95,942	53,489
Less: Current Maturities - Otter Tail Corporation	231	52,422
Unamortized Long-Term Debt Issuance Costs	539	122
Total Long-Term Debt net of Unamortized Debt Issuance Costs	95,172	945
Total Short-Term and Long-Term Debt (with current maturities)	95,403	113,033
OTTER TAIL CORPORATION | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	15,000
OTTER TAIL CORPORATION | 3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt	80,000
OTTER TAIL CORPORATION | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt		52,330
OTTER TAIL CORPORATION | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	106	182
OTTER TAIL CORPORATION | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 836	$ 977

Short-Term and Long-Term Borr97

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Breakdown of Assignment of Company's Consolidated Short-Term and Long-Term Debt Outstanding (Parentheticals) (Details 1)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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
3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate		9.00%
Long-Term Debt, Due Date		Dec. 15, 2016
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 1, 2018	Apr. 1, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Otter Tail Corporation | 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 | 3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%
Long-Term Debt, Due Date	Dec. 15, 2016	Dec. 15, 2016
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 1, 2018	Apr. 1, 2018
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

Short-Term and Long-Term Borr98

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Aggregate Amounts of Maturities on Bonds Outstanding and Other Long-Term Obligations (Details 2) $ in Thousands	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
Aggregate amounts of debt maturities in 2017	$ 33,231
Aggregate amounts of debt maturities in 2018	15,187
Aggregate amounts of debt maturities in 2019	172
Aggregate amounts of debt maturities in 2020	185
Aggregate amounts of debt maturities in 2021	$ 140,171

Short-Term and Long-Term Borr99

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Oct. 29, 2012
Line of Credit Facility [Line Items]
Maximum amount of debt outstanding	$ 87,211,000
Average daily balance of debt outstanding	$ 48,776,000
Weighted average interest rate paid on short-term debt	1.90%
Line Limit	$ 300,000,000
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Maximum amount of debt outstanding	63,757,000
Average daily balance of debt outstanding	$ 16,200,000
Weighted average interest rate paid on short-term debt	2.30%	2.00%
Line Limit	$ 130,000,000
Line of credit facility, description of variable rate basis	LIBOR
Line of credit facility, basis spread on variable rate	1.75%
Otter Tail Corporation Credit Agreement | Unsecured revolving credit facility
Line of Credit Facility [Line Items]
Line Limit			$ 150,000,000
Line of credit facility, maximum borrowing capacity, subject to conditions			250,000,000
Reduced line of credit facility, borrowing capacity			40,000,000
OTP Credit Agreement
Line of Credit Facility [Line Items]
Maximum amount of debt outstanding	$ 51,885,000
Average daily balance of debt outstanding	$ 32,576,000
Weighted average interest rate paid on short-term debt	1.80%	1.50%
Line Limit	$ 170,000,000
Line of credit facility, maximum amount of letters of credit outstanding at any time	$ 50,000,000
Line of credit facility, description of variable rate basis	LIBOR
Line of credit facility, basis spread on variable rate	1.25%
OTP Credit Agreement | Revolving credit facility
Line of Credit Facility [Line Items]
Line Limit			170,000,000
Line of credit facility, maximum borrowing capacity, subject to conditions			$ 250,000,000

Short-Term and Long-Term Bor100

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 1) - USD ($)	12 Months Ended
	Dec. 31, 2016	Sep. 23, 2016	Dec. 31, 2015
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Debt instrument, interest rate			9.00%
3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Debt instrument, interest rate	3.55%
2016 Note Purchase Agreement
Debt Instrument [Line Items]
Debt instrument description of prepayment	The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount.
2016 Note Purchase Agreement | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Repayments of Debt	$ 52,330,000
2016 Note Purchase Agreement | 3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Original debt issued, principal amount		$ 80,000,000
Debt instrument, interest rate		3.55%
Unsecured Term Loan | 2016 Note Purchase Agreement | February 2016 term loan agreement
Debt Instrument [Line Items]
Repayments of Debt	$ 50,000,000

Short-Term and Long-Term Bor101

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 2) - USD ($)	Feb. 05, 2016	Dec. 31, 2016
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 300,000,000
Maximum amount of debt outstanding		$ 87,211,000
Term Loan Agreement | JPMorgan
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 50,000,000
Minimum increments tranches of term loans	10,000,000
Maximum amount of debt outstanding	$ 100,000,000
Interest rate base	LIBOR plus 0.90%
Borrowed amount	$ 50,000,000
Term Loan Agreement | JPMorgan | LIBOR
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR
Debt Instrument, Basis Spread on Variable Rate	0.90%
Term Loan Agreement | JPMorgan | Prime Rate
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	Prime Rate
Term Loan Agreement | JPMorgan | Federal Reserve Bank of New York Rate
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	Federal Reserve Bank of New York Rate
Debt Instrument, Basis Spread on Variable Rate	0.50%
Term Loan Agreement | JPMorgan | Statutory Reserve Rate
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR multiplied by the Statutory Reserve Rate
Debt Instrument, Basis Spread on Variable Rate	1.00%

Short-Term and Long-Term Bor102

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 3) - USD ($) $ in Millions	Aug. 14, 2013	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Financial covenants of debt		Financial Covenants The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016. No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies. The Company's and OTP's borrowing agreements are subject to certain financial covenants. Specifically:· Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may 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 agreements.· Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016.· Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.· Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.· Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Debt instrument, interest rate		4.63%	4.63%
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Debt instrument, interest rate		5.95%	5.95%
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Debt instrument, interest rate		6.15%	6.15%
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Debt instrument, interest rate		6.37%	6.37%
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Debt instrument, interest rate		6.47%	6.47%
Note Purchase Agreement 2013
Debt Instrument [Line Items]
Interest bearing debt, maximum percentage of total capitalization		60.00%
Priority debt to total capitalization		20.00%
2007 and 2011 Note Purchase Agreements
Debt Instrument [Line Items]
Priority debt to total capitalization		20.00%
2007 and 2011 Note Purchase Agreements | Minimum
Debt Instrument [Line Items]
Debt to total capitalization ratio		0.60
Interest and dividend coverage ratio		1
2007 and 2011 Note Purchase Agreements | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio		1
Interest and dividend coverage ratio		1.50
Otter Tail Corporation Credit Agreement | Minimum
Debt Instrument [Line Items]
Debt to total capitalization ratio		0.60
Interest and dividend coverage ratio		1
Otter Tail Corporation Credit Agreement | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio		1
Interest and dividend coverage ratio		1.50
2016 Note Purchase Agreement
Debt Instrument [Line Items]
Debt instrument description of prepayment		The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount.
Priority debt to total capitalization		10.00%
OTP Credit Agreement | Minimum
Debt Instrument [Line Items]
Debt to total capitalization ratio		0.60
OTP Credit Agreement | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio		1
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Debt instrument, interest rate		4.63%	4.63%
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Debt instrument, interest rate		5.95%	5.95%
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Debt instrument, interest rate		6.15%	6.15%
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Debt instrument, interest rate		6.37%	6.37%
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Debt instrument, interest rate		6.47%	6.47%
Otter Tail Power Company | Note Purchase Agreement 2013
Debt Instrument [Line Items]
Debt instrument description of prepayment		The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount.
Otter Tail Power Company | Note Purchase Agreement 2013 | Series A Senior Unsecured Notes due on February 27, 2029
Debt Instrument [Line Items]
Aggregate principal amount of note	$ 60
Debt instrument, interest rate	4.68%
Otter Tail Power Company | Note Purchase Agreement 2013 | Series B Senior Unsecured Notes due on February 27, 2044
Debt Instrument [Line Items]
Aggregate principal amount of note	$ 90
Debt instrument, interest rate	5.47%
Portion of proceeds used to retire outstanding term loan	$ 40.9
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 140
Debt instrument, interest rate		4.63%
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 33
Debt instrument, interest rate		5.95%
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 30
Debt instrument, interest rate		6.15%
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 42
Debt instrument, interest rate		6.37%
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 50
Debt instrument, interest rate		6.47%
Otter Tail Power Company | Note Purchase Agreement 2011 | Unsecured Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of note		$ 155
Otter Tail Power Company | 2007 and 2011 Note Purchase Agreements
Debt Instrument [Line Items]
Debt instrument description of prepayment		The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount.

Pension Plan and Other Postr103

Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period		$ 5,518	$ 6,059	$ 4,666
Interest Cost on Projected Benefit Obligation		14,195	13,344	13,111
Expected Return on Assets		(19,454)	(18,383)	(16,743)
Amortization of Prior Service Cost:
From Regulatory Asset		189	188	257
From Other Comprehensive Income	[1]	5	5	7
Amortization of Net Actuarial Loss:
From Regulatory Asset		5,153	6,676	3,400
From Other Comprehensive Income	[1]	127	171	83
Net Periodic Cost		5,733	8,060	4,781
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Service Cost-Benefit Earned During the Period		252	189	51
Interest Cost on Projected Benefit Obligation		1,667	1,523	1,520
Amortization of Prior Service Cost:
From Regulatory Asset		16	16	22
From Other Comprehensive Income	[2]	38	38	51
Amortization of Net Actuarial Loss:
From Regulatory Asset		293	334	142
From Other Comprehensive Income	[3]	446	602	46
Net Periodic Cost		2,712	2,702	1,832
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost (Net of Medicare Part D Subsidy)		1,301	1,297	1,055
Interest Cost (Net of Medicare Part D Subsidy)		2,503	2,097	2,200
Amortization of Prior Service Cost:
From Regulatory Asset		134	205	205
From Other Comprehensive Income	[1]	3	5	5
Amortization of Net Actuarial Loss:
From Regulatory Asset		379
From Other Comprehensive Income	[1]	9
Net Periodic Cost		4,329	3,604	3,465
Effect of Medicare Part D Subsidy		$ (923)	$ (1,487)	$ (948)
[1]	Corporate cost included in Other Nonelectric Expenses.
[2]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31
[3]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86)

Pension Plan and Other Postr104

Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Parentheticals) (Details) - Executive Survivor and Supplemental Retirement Plan (ESSRP) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income	[1]	$ 38	$ 38	$ 51
Amortization of Net Actuarial Loss from Other Comprehensive Income	[2]	446	602	46
Electric Operation and Maintenance Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income		15	15	20
Amortization of Net Actuarial Loss from Other Comprehensive Income		272	310	132
Other Nonelectric Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income		23	23	31
Amortization of Net Actuarial Loss from Other Comprehensive Income		$ 174	$ 292	$ (86)
[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31
[2]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86)

Pension Plan and Other Postr105

Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost (Details 1)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.76%	4.35%	5.30%
Long-Term Rate of Return on Plan Assets	7.75%	7.75%	7.75%
Rate of Increase in Future Compensation Level	3.13%	3.13%	3.13%
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.76%	4.35%	5.30%
Rate of Increase in Future Compensation Level	3.13%	3.15%	3.18%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.57%	4.20%	5.10%

Pension Plan and Other Postr106

Pension Plan and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan
Regulatory Assets:
Unrecognized Prior Service Cost	$ 141	$ 329
Unrecognized Actuarial Loss	98,039	101,974
Total Regulatory Assets	98,180	102,303
Projected Benefit Obligation Liability - Net Amount Recognized	(314,637)	(302,740)	$ (311,650)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	12	16
Unrecognized Actuarial Loss (Gain)	406	820
Total Accumulated Other Comprehensive Loss	418	836
Noncurrent Liability	60,292	69,101
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Regulatory Assets:
Unrecognized Prior Service Cost	58	75
Unrecognized Actuarial Loss	2,890	2,936
Total Regulatory Assets	2,948	3,011
Projected Benefit Obligation Liability - Net Amount Recognized	(37,335)	(35,811)	(35,650)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	134	172
Unrecognized Actuarial Loss (Gain)	5,915	5,815
Total Accumulated Other Comprehensive Loss	6,049	5,987
Other Postretirement Benefits
Regulatory Assets:
Unrecognized Prior Service Cost	(4)	129
Unrecognized Actuarial Loss	13,586	1,289
Total Regulatory Assets	13,582	1,418
Projected Benefit Obligation Liability - Net Amount Recognized	(62,571)	(48,730)	$ (53,638)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	4	8
Unrecognized Actuarial Loss (Gain)	(171)	(347)
Total Accumulated Other Comprehensive Loss	$ (167)	$ (339)

Pension Plan and Other Postr107

Pension Plan and Other Postretirement Benefits - Funded Status (Details 3) - Pension Plan - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ (281,414)	$ (268,387)
Projected Benefit Obligation	(314,637)	(302,740)	$ (311,650)
Fair Value of Plan Assets	254,345	233,639	$ 244,589
Funded Status	$ (60,292)	$ (69,101)

Pension Plan and Other Postr108

Pension Plan and Other Postretirement Benefits - Reconciliation of Changes in Fair Value of Plan Assets and Plan's Benefit Obligations (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1	$ 233,639	$ 244,589
Actual Return on Plan Assets	23,794	(9,160)
Discretionary Company Contributions	10,000	10,000
Benefit Payments	(13,088)	(11,790)
Fair Value of Plan Assets at December 31	$ 254,345	$ 233,639	$ 244,589
Estimated Asset Return	10.10%	(3.70%)
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	$ 302,740	$ 311,650
Service Cost	5,518	6,059	4,666
Interest Cost	14,195	13,344	13,111
Benefit Payments	(13,088)	(11,790)
Actuarial (Gain) Loss	5,272	(16,523)
Projected Benefit Obligation at December 31	314,637	302,740	311,650
Reconciliation of Accrued Postretirement Cost:
Expense	(5,733)	(8,060)	(4,781)
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1
Actual Return on Plan Assets
Employer Contributions	1,188	1,119
Benefit Payments	(1,188)	(1,119)
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	35,811	35,650
Service Cost	252	189	51
Interest Cost	1,667	1,523	1,520
Benefit Payments	(1,188)	(1,119)
Plan Amendments
Actuarial (Gain) Loss	793	(432)
Projected Benefit Obligation at December 31	37,335	35,811	35,650
Reconciliation of Accrued Postretirement Cost:
Expense	(2,712)	(2,702)	(1,832)
Employer Contributions	1,188	1,119
Other Postretirement Benefits
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1
Actual Return on Plan Assets
Employer Contributions	2,825	2,365
Benefit Payments (Net of Medicare Part D Subsidy)	(5,908)	(5,324)
Participant Premium Payments	3,083	2,959
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	48,730	53,638
Service Cost (Net of Medicare Part D Subsidy)	1,301	1,297	1,055
Interest Cost (Net of Medicare Part D Subsidy)	2,503	2,097	2,200
Benefit Payments (Net of Medicare Part D Subsidy)	(5,908)	(5,324)
Participant Premium Payments	3,083	2,959
Actuarial (Gain) Loss	12,862	(5,937)
Projected Benefit Obligation at December 31	62,571	48,730	53,638
Reconciliation of Accrued Postretirement Cost:
Accrued Postretirement Cost at January 1	(47,652)	(46,413)
Expense	(4,329)	(3,604)	(3,465)
Employer Contributions	2,825	2,365
Accrued Postretirement Cost at December 31	$ (49,156)	$ (47,652)	$ (46,413)

Pension Plan and Other Postr109

Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Benefit Obligations (Details 5)	Dec. 31, 2016	Dec. 31, 2015
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.60%	4.76%
Rate of Increase in Future Compensation Level	3.00%	3.13%
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.60%	4.76%
Rate of Increase in Future Compensation Level	3.00%	3.13%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.46%	4.57%

Pension Plan and Other Postr110

Pension Plan and Other Postretirement Benefits - Measurement Dates (Details 6)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Pension Cost	Jan. 1, 2016	Jan. 1, 2015
Market Value of Assets	Dec. 31, 2016	Dec. 31, 2015
Pension Plan | Minimum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	Jan. 1, 2016	Jan. 1, 2015
Pension Plan | Maximum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Pension Cost	Jan. 1, 2016	Jan. 1, 2015
Other Postretirement Benefits | Minimum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	Jan. 1, 2016	Jan. 1, 2015
Other Postretirement Benefits | Maximum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	Dec. 31, 2016	Dec. 31, 2015

Pension Plan and Other Postr111

Pension Plan and Other Postretirement Benefits - Estimated Amounts of Unrecognized Net Actuarial Losses and Prior Service Costs to be Amortized (Details 7) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Pension Plan
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost	$ 120
Amortization of Unrecognized Actuarial Loss	5,090
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost	3
Amortization of Unrecognized Actuarial Loss	125
Total Estimated Amortization	5,338
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost	16
Amortization of Unrecognized Actuarial Loss	285
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost	38
Amortization of Unrecognized Actuarial Loss	440
Total Estimated Amortization	779
Other Postretirement Benefits
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss	932
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss	23
Total Estimated Amortization	$ 955

Pension Plan and Other Postr112

Pension Plan and Other Postretirement Benefits - Benefit Payments, which Reflect Expected Future Service, as Appropriate, Expected to be Paid out from Plan Assets (Details 8) $ in Thousands	Dec. 31, 2016USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2,017	$ 13,413
2,018	14,140
2,019	14,806
2,020	15,564
2,021	16,335
Years 2022-2026	92,083
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
2,017	1,253
2,018	1,487
2,019	1,562
2,020	1,544
2,021	1,754
Years 2022-2026	12,700
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2,017	3,512
2,018	3,669
2,019	3,828
2,020	3,912
2,021	4,046
Years 2022-2026	$ 20,377

Pension Plan and Other Postr113

Pension Plan and Other Postretirement Benefits - The policy of the Plan is to invest assets in accordance with the allocations (Details 9) - Pension Plan	12 Months Ended
	Dec. 31, 2016
Equity | less than 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	30.00%
Equity | less than 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	65.00%
Equity | 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	25.00%
Equity | 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	60.00%
Equity | 105% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	20.00%
Equity | 105% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	55.00%
Equity | >=110% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%
Equity | >=110% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	50.00%
Investment Grade Fixed Income | less than 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	35.00%
Investment Grade Fixed Income | less than 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	75.00%
Investment Grade Fixed Income | 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	40.00%
Investment Grade Fixed Income | 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	80.00%
Investment Grade Fixed Income | 105% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	45.00%
Investment Grade Fixed Income | 105% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	85.00%
Investment Grade Fixed Income | >=110% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	50.00%
Investment Grade Fixed Income | >=110% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	90.00%
Below Investment Grade Fixed Income | less than 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[1]
Below Investment Grade Fixed Income | less than 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%	[1]
Below Investment Grade Fixed Income | 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[1]
Below Investment Grade Fixed Income | 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%	[1]
Below Investment Grade Fixed Income | 105% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[1]
Below Investment Grade Fixed Income | 105% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%	[1]
Below Investment Grade Fixed Income | >=110% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[1]
Below Investment Grade Fixed Income | >=110% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%	[1]
Other | less than 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[2]
Other | less than 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	20.00%	[2]
Other | 100% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[2]
Other | 100% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	20.00%	[2]
Other | 105% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[2]
Other | 105% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	20.00%	[2]
Other | >=110% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[2]
Other | >=110% PBO | Maximum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	20.00%	[2]
[1]	Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds.
[2]	Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.

Pension Plan and Other Postr114

Pension Plan and Other Postretirement Benefits - Pension Plan Asset Allocations by Asset Category (Details 10) - Pension Plan	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	57.80%	56.50%
Large Capitalization Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	21.40%	21.20%
International Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	22.00%	21.60%
Small and Mid-Capitalization Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	8.10%
SEI Dynamic Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	5.40%	5.60%
Fixed-Income Securities and Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	34.30%	35.80%
Other - SEI Energy Debt Collective Fund
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	4.10%	3.60%
Other - SEI Special Situation Collective Investment Trust
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	3.80%	4.10%

Pension Plan and Other Postr115

Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value and NAV (Details 11) - Pension Plan - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Assets in Level 1 of the Fair Value Hierarchy		$ 234,303	$ 215,676
SEI Energy Debt Collective Fund at NAV		10,441	8,342
SEI Special Situation Collective Investment Trust Fund at NAV	[1]	9,601	9,621
Total Assets		$ 254,345	$ 233,639	$ 244,589
[1]	On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in January 2017 was $9,679,000.

Pension Plan and Other Postr116

Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value and NAV (Parenthetical)(Details 11)	12 Months Ended
	Dec. 31, 2016USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Cash value of investment on settlement	$ 9,679,000

Pension Plan and Other Postr117

Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value (Details 12) - Pension Plan - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Total Assets	$ 254,345	$ 233,639	$ 244,589
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total Assets	234,303	215,676
Level 1 | Large Capitalization Equity Securities Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	54,483	49,513
Level 1 | International Equity Securities Mutual Funds
Defined Benefit Plan Disclosure [Line Items]
Total Assets	55,916	50,504
Level 1 | Small and Mid-Capitalization Equity Securities Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	23,011	18,823
Level 1 | SEI Dynamic Asset Allocation Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	13,622	13,004
Level 1 | Fixed Income Securities Mutual Funds
Defined Benefit Plan Disclosure [Line Items]
Total Assets	87,268	83,830
Level 1 | Cash Management - Money Market Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	$ 3	$ 2

Pension Plan and Other Postr118

Pension Plan and Other Postretirement Benefits - Healthcare Cost-Trend Rates (Details 13) - Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Rate to Which the Cost-Trend Rate is Assumed to Decline	4.50%	4.50%
Year the Rate Reaches the Ultimate Trend Rate	2,038	2,038
Pre65
Defined Benefit Plan Disclosure [Line Items]
Healthcare Cost-Trend Rate Assumed for Next Year	6.01%	6.16%
Post65
Defined Benefit Plan Disclosure [Line Items]
Healthcare Cost-Trend Rate Assumed for Next Year	6.23%	6.43%

Pension Plan and Other Postr119

Pension Plan and Other Postretirement Benefits - Effects of One Percentage Change in Assumed healthcare Cost-Trend Rates (Details 14) - Other Postretirement Benefits $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect of 1 point increase on the Postretirement Benefit Obligation	$ 7,151
Effect of 1 point increase on Total of Service and Interest Cost	653
Effect of 1 point increase on Expense	1,454
Effect of 1 point decrease on the Postretirement Benefit Obligation	(7,492)
Effect of 1 point decrease on Total of Service and Interest Cost	(519)
Effect of 1 point decrease on Expense	$ (907)

Pension Plan and Other Postr120

Pension Plan and Other Postretirement Benefits (Detail Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Contributions made to 401K plan by the companies	$ 3,877,000	$ 3,602,000	$ 3,171,000
Contributions made by the company to employee stock ownership plan	$ 647,000	$ 674,000	$ 696,000
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, vesting percentage	100.00%
Defined benefit plan vesting period	5 years
Assumed rate of return on pension fund assets for the determination of 2017 net periodic pension cost	7.50%
Pension Plan | SEI Energy Debt Fund
Defined Benefit Plan Disclosure [Line Items]
Amount invested in pension fund assets	$ 10,000,000
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Period of benefit payments to the beneficiaries on their deaths	15 years
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Health insurance benefits, requisite age	55 years
Health insurance benefits, requisite service period	10 years
Estimated future employer contributions in the next fiscal year	$ 3,500,000
Medicare part D subsidy expected to received in 2017	$ 416,000

Fair Value of Financial Inst121

Fair Value of Financial Instruments - Long-term debt including current maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents
Short-Term Debt	(42,883)	(80,672)
Long-Term Debt including Current Maturities	(538,542)	(496,268)
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents
Short-Term Debt	(42,883)	(80,672)
Long-Term Debt including Current Maturities	$ (583,835)	$ (561,245)

Fair Value of Financial Inst122

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

Property, Plant and Equipmen123

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Total Gross Plant	$ 2,225,444	$ 2,101,718
Less Accumulated Depreciation and Amortization	748,219	713,904
Net Plant	1,477,225	1,387,814
Electric Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	2,010,354	1,884,880
Less Accumulated Depreciation and Amortization	622,657	592,001
Net Plant	1,387,697	1,292,879
Electric Plant | Production Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	891,330	879,121
Electric Plant | Transmission Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	410,679	391,941
Electric Plant | Distribution Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	466,285	451,820
Electric Plant | General Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	92,063	97,881
Electric Plant | Electric Plant In Service
Property, Plant and Equipment [Line Items]
Total Gross Plant	1,860,357	1,820,763
Electric Plant | Construction In Progress
Property, Plant and Equipment [Line Items]
Total Gross Plant	149,997	64,117
Nonelectric Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	215,090	216,838
Less Accumulated Depreciation and Amortization	125,562	121,903
Net Plant	89,528	94,935
Nonelectric Plant | Equipment
Property, Plant and Equipment [Line Items]
Total Gross Plant	155,809	155,715
Nonelectric Plant | Buildings And Leasehold Improvements
Property, Plant and Equipment [Line Items]
Total Gross Plant	51,323	41,149
Nonelectric Plant | Land
Property, Plant and Equipment [Line Items]
Total Gross Plant	4,694	4,479
Nonelectric Plant | Nonelectric Operations Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	211,826	201,343
Nonelectric Plant | Construction In Progress
Property, Plant and Equipment [Line Items]
Total Gross Plant	$ 3,264	$ 15,495

Property, Plant and Equipment -

Property, Plant and Equipment - Estimated Service Lives for Properties (Details 1)	12 Months Ended
	Dec. 31, 2016
Electric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Electric Plant | Minimum | Production Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	9 years
Electric Plant | Minimum | Transmission Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	42 years
Electric Plant | Minimum | Distribution Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Electric Plant | Minimum | General Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Electric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	82 years
Electric Plant | Maximum | Production Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	82 years
Electric Plant | Maximum | Transmission Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	70 years
Electric Plant | Maximum | Distribution Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	68 years
Electric Plant | Maximum | General Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Nonelectric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Nonelectric Plant | Minimum | Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Nonelectric Plant | Minimum | Buildings And Leasehold Improvements
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Nonelectric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Nonelectric Plant | Maximum | Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	12 years
Nonelectric Plant | Maximum | Buildings And Leasehold Improvements
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years

Property, Plant and Equipmen125

Property, Plant and Equipment (Detail Textuals)	12 Months Ended
	Dec. 31, 2016
Electric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Electric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	82 years
Nonelectric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Nonelectric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Tax Computed at Federal Statutory Rate - Continuing Operations	$ 28,741	$ 28,081	$ 25,704
Increases (Decreases) in Tax from:
Federal PTCs	(7,175)	(6,962)	(7,517)
State Income Taxes Net of Federal Income Tax Expense	2,848	4,945	1,993
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(850)	(850)	(849)
Corporate-owned Life Insurance	(680)	(167)	(354)
Dividend Received/Paid Deduction	(537)	(560)	(622)
Section 199 Domestic Production Activities Deduction	(482)		(1,026)
Investment Tax Credit Amortization	(350)	(571)	(597)
Allowance for Funds Used During Construction - Equity	(280)	(426)	(505)
Differences Reversing in Excess of Federal Rates	77	(1,143)	(106)
Permanent and Other Differences	(1,231)	(705)	436
Total Income Tax Expense - Continuing Operations	20,081	21,642	16,557
Income Tax Expense - Discontinued Operations - U.S.	138	2,991	3,952
Income Tax Expense - Continuing and Discontinued Operations	$ 20,219	$ 24,633	$ 20,509
Overall Effective Federal, State and Foreign Income Tax Rate	24.50%	29.30%	26.20%

Income Taxes - Components of In

Income Taxes - Components of Income tax expense (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Expense From Continuing Operations Includes the Following:
Current Federal Income Taxes	$ 1,070	$ 211	$ 124
Current State Income Taxes	1,211	1	5
Deferred Federal Income Taxes	23,586	23,050	21,044
Deferred State Income Taxes	2,589	6,763	4,347
Federal PTCs	(7,175)	(6,962)	(7,517)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(850)	(850)	(849)
Investment Tax Credit Amortization	(350)	(571)	(597)
Total Income Tax Expense - Continuing Operations	20,081	21,642	16,557
Total Income Before Income Taxes - Continuing and Discontinued Operations	$ 82,540	$ 83,978	$ 78,232

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Tax Assets
Benefit Liabilities	$ 44,381	$ 41,788
Federal PTCs	43,433	39,505
Retirement Benefits Liabilities	38,390	41,958
North Dakota Wind Tax Credits	32,962	32,962
Cost of Removal	31,636	29,463
Differences Related to Property	9,876	10,177
Net Operating Loss Carryforward	3,865	22,824
Vacation Accrual	2,725	2,500
Investment Tax Credits	818	1,109
Other	7,793	7,617
Total Deferred Tax Assets	215,879	229,903
Deferred Tax Liabilities
Differences Related to Property	(371,761)	(366,234)
Retirement Benefits Regulatory Asset	(38,390)	(41,958)
Excess Tax over Book Pension	(15,509)	(13,775)
North Dakota Wind Tax Credits	(3,654)	(3,179)
Impact of State Net Operating Losses on Federal Taxes	(1,352)	(1,596)
Other	(11,804)	(10,830)
Total Deferred Tax Liabilities	(442,470)	(437,572)
Deferred Income Taxes	$ (226,591)	$ (207,669)

Income Taxes - Expiration of Ta

Income Taxes - Expiration of Tax Net Operating Losses and Tax Credits Available (Details 3) $ in Thousands	Dec. 31, 2016USD ($)
Federal Net Operating Losses
Net Operating Loss Carryforward [Abstract]
Net Operating Losses, Amount
Net Operating Losses, Year of Expiration 2017
Net Operating Losses, Year of Expiration 2027-36
State Net Operating Losses
Net Operating Loss Carryforward [Abstract]
Net Operating Losses, Amount	3,865
Net Operating Losses, Year of Expiration 2017
Net Operating Losses, Year of Expiration 2027-36	3,865
Federal Tax Credits
Tax Credit Carryforward [Abstract]
Tax Credits, Amount	46,435
Tax Credits, Year of Expiration 2017
Tax Credits, Year of Expiration 2027-36	46,435
State Tax Credits
Tax Credit Carryforward [Abstract]
Tax Credits, Amount	33,993
Tax Credits, Year of Expiration 2017	389
Tax Credits, Year of Expiration 2027-36	$ 33,604

Income Taxes - Summary of Activ

Income Taxes - Summary of Activity Related to Unrecognized Tax benefit (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance on January 1	$ 468	$ 222	$ 4,239
Increases Related to Tax Positions for Prior Years	406	236	120
Decreases Related to Tax Positions for Prior Years			(4,142)
Increases Related to Tax Positions for Current Year	114	10	5
Uncertain Positions Resolved During Year	(97)
Balance on December 31	$ 891	$ 468	$ 222

Income Taxes (Detail Textuals)

Income Taxes (Detail Textuals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal income tax rate	35.00%	35.00%	35.00%
Increase in percentage of production tax credits	3.60%
Wind tax credits amortization period	25 years
Carryforward period on a portion of the North Dakota wind tax credits from the Langdon wind project	5 years
Adjustment of deferred tax assets and deferred tax credits for unused North Dakota wind tax credits from Langdon wind project	$ 0.4
Period for unrecognized tax benefits not expected change	12 months

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliations of Carrying Amounts of Present Value of Legal AROs, Capitalized Asset Retirement Costs and Related Accumulated Depreciation and Summary of Settlement Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations
Beginning Balance	$ 8,084	$ 7,721
New Obligations Recognized		451
Adjustments Due to Revisions in Cash Flow Estimates	(103)	(424)
Accrued Accretion	360	336
Settlements
Ending Balance	8,341	8,084
Asset Retirement Costs Capitalized
Beginning Balance	3,086	3,059
New Obligations Recognized		451
Adjustments Due to Revisions in Cash Flow Estimates	(103)	(424)
Settlements
Ending Balance	2,983	3,086
Accumulated Depreciation - Asset Retirement Costs Capitalized
Beginning Balance	673	527
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense	122	146
Settlements
Ending Balance	795	673
Settlements
Original Capitalized Asset Retirement Cost - Retired
Accumulated Depreciation
Asset Retirement Obligation
Settlement Cost
Gain on Settlement - Deferred Under Regulatory Accounting

Asset Retirement Obligations (D

Asset Retirement Obligations (Detail Textuals) $ in Thousands	Dec. 31, 2016USD ($)Turbine	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation	$ 8,341	$ 8,084	$ 7,721
Otter Tail Power Company
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation	$ 500
North Dakota
Asset Retirement Obligations [Line Items]
Number of wind turbines | Turbine	92

Discontinued Operations - Resul

Discontinued Operations - Results of Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		$ 24,623	$ 149,860
Operating Expenses	$ (422)	31,635	140,002
Asset Impairment Charge		1,000	5,605
Interest Expense
Other Income (Deductions)		69	539
Income Tax (Benefit) Expense	138	(1,539)	3,952
Net (Loss) Income from Operations	284	(6,404)	840
(Loss) Gain on Disposition Before Taxes		11,690
Income Tax (Benefit) Expense		4,530
Net Gain on Disposition		7,160
Net (Loss) Income	284	756	840
Foley | Disposal Group, 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		21,625	105,333
Operating Expenses	250	26,839	100,826
Asset Impairment Charge		1,000	5,605
Interest Expense		177	510
Other Income (Deductions)		(42)	(38)
Income Tax (Benefit) Expense	(136)	(921)	1,388
Net (Loss) Income from Operations	(114)	(5,512)	(3,034)
(Loss) Gain on Disposition Before Taxes		(204)
Income Tax (Benefit) Expense		(227)
Net Gain on Disposition		23
Net (Loss) Income		(5,489)
AEV, Inc. | Disposal Group, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		2,998	44,527
Operating Expenses		4,532	40,297
Asset Impairment Charge
Interest Expense		27	184
Other Income (Deductions)		2	304
Income Tax (Benefit) Expense	5	(638)	1,729
Net (Loss) Income from Operations	(5)	(921)	2,621
(Loss) Gain on Disposition Before Taxes		11,894
Income Tax (Benefit) Expense		4,757
Net Gain on Disposition		7,137
Net (Loss) Income		6,216
Wind Tower Business | Disposal Group, 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
Operating Expenses	(757)	(462)	19
Asset Impairment Charge
Interest Expense
Other Income (Deductions)		111
Income Tax (Benefit) Expense	303	229	(8)
Net (Loss) Income from Operations	454	344	(11)
(Loss) Gain on Disposition Before Taxes
Income Tax (Benefit) Expense
Net Gain on Disposition
Net (Loss) Income		344
Dock and Boatlift Business | Disposal Group, 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
Operating Expenses	85	966	(180)
Asset Impairment Charge
Interest Expense
Other Income (Deductions)			277
Income Tax (Benefit) Expense	(34)	(386)	183
Net (Loss) Income from Operations	(51)	(580)	274
(Loss) Gain on Disposition Before Taxes
Income Tax (Benefit) Expense
Net Gain on Disposition
Net (Loss) Income		(580)
Intercompany Transactions Adjustment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues
Operating Expenses		(240)	(960)
Asset Impairment Charge
Interest Expense		(204)	(694)
Other Income (Deductions)		(2)	(4)
Income Tax (Benefit) Expense		177	660
Net (Loss) Income from Operations		265	$ 990
(Loss) Gain on Disposition Before Taxes
Income Tax (Benefit) Expense
Net Gain on Disposition
Net (Loss) Income		$ 265

Discontinued Operations - Major

Discontinued Operations - Major Components of Assets and Liabilities of Discontinued Operations (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Liabilities	$ 1,363	$ 2,098
Liabilities of Discontinued Operations	1,363	2,098
Foley | Disposal Group, 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
Liabilities of Discontinued Operations
AEV, Inc. | Disposal Group, 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
Liabilities of Discontinued Operations
Wind Tower Business | Disposal Group, 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	589	1,299
Liabilities of Discontinued Operations	589	1,299
Dock and Boatlift Business | Disposal Group, 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	774	799
Liabilities of Discontinued Operations	$ 774	$ 799

Discontinued Operations - Warra

Discontinued Operations - Warranty Reserves (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Movement in Standard Product Warranty Accrual [Roll Forward]
Warranty Reserve Balance, Beginning of Year	$ 2,103	$ 2,527
Additional Provision for Warranties Made During the Year
Less Settlements Made During the Year	(24)	(124)
Decrease in Warranty Estimates for Prior Years	(710)	(300)
Warranty Reserve Balance, End of Year	$ 1,369	$ 2,103

Discontinued Operations (Detail

Discontinued Operations (Detail Textuals) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended		12 Months Ended
	Apr. 30, 2015	Feb. 28, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business					$ 39,401
Disposal Group, Held-for-sale or Disposed of by Sale | Foley
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business	$ 12,000
Amount of working capital received	6,300
Selling expenses	$ 1,000
Goodwill impairment charge			$ 1,000	$ 5,600
Disposal Group, Held-for-sale or Disposed of by Sale | AEV, Inc.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business		$ 22,300
Amount of working capital received		600
Selling expenses		$ 800
Disposal Group, Held-for-sale or Disposed of by Sale | Foley and Aevenia
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pretax charges					$ 4,400

Subsequent Events - Summary of

Subsequent Events - Summary of stock incentive awards to executive officers under the 2014 Stock Incentive Plan (Details) - Subsequent Event - 2014 Stock Incentive Plan - Executive Officers	Feb. 02, 2017$ / sharesshares
Restricted Stock Units (RSU) | 25% per year through February 6, 2021
Subsequent Event [Line Items]
Shares/UnitsGranted | shares	15,900
Weighted Average Grant-Date Fair Value per Award | $ / shares	$ 37.65
Vesting percentage	25.00%
Vesting date	Feb. 6, 2021
Stock Performance Awards | December 31, 2019
Subsequent Event [Line Items]
Shares/UnitsGranted | shares	59,500
Weighted Average Grant-Date Fair Value per Award | $ / shares	$ 31
Vesting date	Dec. 31, 2019

Subsequent Events (Detail Textu

Subsequent Events (Detail Textuals) - 2014 Stock Incentive Plan - shares	Feb. 02, 2017	Feb. 04, 2016	Dec. 31, 2016
Subsequent Event [Line Items]
Target number of shares awarded			1,900,000
Executive Officers | Stock Performance Awards
Subsequent Event [Line Items]
Target number of shares awarded		81,500
Basis for achieving performance target, description		Common shares for achieving the target set for the Company's 3-year average adjusted return on equity
Executive Officers | Stock Performance Awards | Maximum
Subsequent Event [Line Items]
Actual payment percentage of target amount		150.00%
Executive Officers | Stock Performance Awards | Performance Target One
Subsequent Event [Line Items]
Target number of shares awarded		54,333
Basis for achieving performance target, description		Common shares based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018.
Executive Officers | Stock Performance Awards | Performance Target Two
Subsequent Event [Line Items]
Target number of shares awarded		27,167
Basis for achieving performance target, description		Common shares for achieving the target set for the Company's 3-year average adjusted return on equity.
Subsequent Event | Stock Performance Awards
Subsequent Event [Line Items]
Number of trading days	20 days
Period specified for average adjusted return	3 years
Subsequent Event | Executive Officers | Stock Performance Awards
Subsequent Event [Line Items]
Target number of shares awarded	59,500
Maximum number of common shares authorized for payment	89,250
Subsequent Event | Executive Officers | Stock Performance Awards | Minimum
Subsequent Event [Line Items]
Actual payment percentage of target amount	0.00%
Subsequent Event | Executive Officers | Stock Performance Awards | Maximum
Subsequent Event [Line Items]
Actual payment percentage of target amount	150.00%
Subsequent Event | Executive Officers | Stock Performance Awards | Performance Target One
Subsequent Event [Line Items]
Target number of shares awarded	39,667
Basis for achieving performance target, description	Based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2017 through December 31, 2019, 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, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020.
Subsequent Event | Executive Officers | Stock Performance Awards | Performance Target Two
Subsequent Event [Line Items]
Target number of shares awarded	19,833

SCHEDULE 1 Condensed Balance Sh

SCHEDULE 1 Condensed Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and Cash Equivalents				$ 2,007
Accounts Receivable	68,242	62,974
Income Taxes Receivable	662	4,000
Other	8,144	8,453
Total Current Assets	208,015	206,689
Investments in Subsidiaries	8,417	8,284
Other Assets	34,104	32,784
Total Assets	1,912,385	1,818,683	$ 1,738,116
Current Liabilities
Short-Term Debt	42,883	80,672
Current Maturities of Long-Term Debt	33,201	52,422
Other	15,377	15,416
Total Current Liabilities	215,671	271,116
Other Noncurrent Liabilities	21,706	23,854
Commitments and Contingencies
Capitalization
Long-Term Debt, Net of Current Maturities	505,341	443,846
Common Shareholder Equity	196,741	189,286
Total Capitalization	1,175,445	1,048,869
Total Liabilities and Equity	1,912,385	1,818,683
Otter Tail Corporation
Current Assets
Cash and Cash Equivalents	6,218			$ 7,907
Accounts Receivable	12	38
Accounts Receivable from Subsidiaries	1,706	2,311
Interest Receivable from Subsidiaries	141	175
Income Taxes Receivable	662	4,000
Notes Receivable from Subsidiaries	1,671	5,645
Other	936	1,096
Total Current Assets	11,346	13,265
Investments in Subsidiaries	692,723	713,344
Notes Receivable from Subsidiaries	79,843	72,560
Deferred Income Taxes	35,387	37,406
Other Assets	29,079	26,957
Total Assets	848,378	863,532
Current Liabilities
Short-Term Debt		59,666
Current Maturities of Long-Term Debt	231	52,422
Accounts Payable to Subsidiaries	5,958	5,959
Notes Payable to Subsidiaries	38,519	99,467
Other	5,838	6,035
Total Current Liabilities	50,546	223,549
Other Noncurrent Liabilities	32,556	34,015
Commitments and Contingencies
Capitalization
Long-Term Debt, Net of Current Maturities	95,172	945
Common Shareholder Equity	670,104	605,023
Total Capitalization	765,276	605,968
Total Liabilities and Equity	$ 848,378	$ 863,532

SCHEDULE 1 Condensed Statements

SCHEDULE 1 Condensed Statements of Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss
Revenue	$ 803,539	$ 779,804	$ 799,262
Operating Expenses	692,440	670,590	699,731
Operating Loss	111,099	109,214	99,531
Other Income (Expense)
Interest Charges	(31,886)	(31,160)	(29,648)
Other Income	2,905	2,177	3,557
Income Tax Benefit	20,081	21,642	16,557
Net Income	62,321	59,345	57,723
Otter Tail Corporation
Operating Loss
Revenue
Operating Expenses	9,689	10,188	12,593
Operating Loss	(9,689)	(10,188)	(12,593)
Other Income (Expense)
Equity Income in Earnings of Subsidiaries	67,047	66,067	64,926
Interest Charges	(6,817)	(6,786)	(6,326)
Interest Charges to Subsidiaries	(173)	(193)	(117)
Interest Income from Subsidiaries	4,897	4,786	4,980
Other Income	1,621	421	1,379
Total Other Income	66,575	64,295	64,842
Income Before Income Taxes	56,886	54,107	52,249
Income Tax Benefit	(5,435)	(5,238)	(5,474)
Net Income	$ 62,321	$ 59,345	$ 57,723

SCHEDULE 1 Condensed Stateme142

SCHEDULE 1 Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	$ 163,386	$ 117,540	$ 112,474
Cash Flows from Investing Activities
Return of Capital (Investment in Subsidiaries)	4,402	6,302	2,785
Net Cash Provided by (Used in) Investing Activities	(159,324)	(155,970)	(164,496)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(3,363)	2,857	1,236
Net Short-Term (Repayments) Borrowings	(37,789)	69,818	(40,341)
Proceeds from Issuance of Common Stock	44,435	14,233	26,259
Common Stock Issuance Expenses	(562)	(451)	(673)
Payments for Retirement of Capital Stock	(104)	(1,596)	(590)
Proceeds from the Issuance of Long-Term Debt	130,000		150,000
Short-Term and Long-Term Debt Issuance Expenses	(888)	(312)	(856)
Payments for Retirement of Long-Term Debt	(87,547)	(212)	(41,088)
Dividends Paid and Other Distributions	(48,244)	(46,223)	(44,261)
Net Cash (Used in) Provided by Financing Activities	(4,062)	38,430	50,864
Net Change in Cash and Cash Equivalents			(2,007)
Cash and Cash Equivalents at Beginning of Period			2,007
Cash and Cash Equivalents at End of Period
Otter Tail Corporation
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	83,296	53,958	47,697
Cash Flows from Investing Activities
Return of Capital (Investment in Subsidiaries)	9,912	(88,079)	(44,000)
Debt Issued to Subsidiaries	(3,309)	(12,592)	(7,662)
Cash Provided by (Used in) Investing Activities	106	(11)	(44)
Net Cash Provided by (Used in) Investing Activities	6,709	(100,682)	(51,706)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(428)	213	215
Net Short-Term (Repayments) Borrowings	(59,666)	48,812	10,854
(Repayments to) Borrowings from Subsidiaries	(60,948)	32,249	4,656
Proceeds from Issuance of Common Stock	44,435	14,233	26,259
Common Stock Issuance Expenses	(562)	(451)	(673)
Payments for Retirement of Capital Stock	(104)	(1,596)	(590)
Proceeds from the Issuance of Long-Term Debt	130,000
Short-Term and Long-Term Debt Issuance Expenses	(723)	(312)	(170)
Payments for Retirement of Long-Term Debt	(87,547)	(201)	(188)
Dividends Paid and Other Distributions	(48,244)	(46,223)	(44,261)
Net Cash (Used in) Provided by Financing Activities	(83,787)	$ 46,724	(3,898)
Net Change in Cash and Cash Equivalents	6,218		(7,907)
Cash and Cash Equivalents at Beginning of Period			$ 7,907
Cash and Cash Equivalents at End of Period	$ 6,218

SCHEDULE 1 Related Party Transa

SCHEDULE 1 Related Party Transactions (Details) - Otter Tail Corporation - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	$ 1,706	$ 2,311
Interest Receivable	141	175
Current Notes Receivable	1,671	5,645
Long-Term Notes Receivable	79,843	72,560
Accounts Payable	5,958	5,959
Current Notes Payable	38,519	99,467
Otter Tail Power Company
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	1,572	1,928
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable	10	11
Current Notes Payable
Vinyltech Corporation
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	3
Interest Receivable	20	32
Current Notes Receivable
Long-Term Notes Receivable	11,500	8,500
Accounts Payable
Current Notes Payable	15,951	14,844
Northern Pipe Products, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable	10	8
Current Notes Receivable
Long-Term Notes Receivable	5,943	3,160
Accounts Payable
Current Notes Payable	6,560	7,088
BTD Manufacturing, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable		13
Interest Receivable	92	107
Current Notes Receivable		3,924
Long-Term Notes Receivable	52,000	53,500
Accounts Payable
Current Notes Payable	2,342
Wind Tower Business
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable
Current Notes Receivable	1,441	1,444
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
Dock and Boatlift Business
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable
Current Notes Receivable	230	277
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
T.O. Plastics, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable	19	28
Current Notes Receivable
Long-Term Notes Receivable	10,400	7,400
Accounts Payable
Current Notes Payable	12,378	6,405
Varistar Corporation
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	60	60
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable	5,948	5,948
Current Notes Payable	1,288	71,130
Otter Tail Assurance Limited
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	71	310
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable

SCHEDULE 1 Dividends (Details)

SCHEDULE 1 Dividends (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Cash Dividends Paid to Parent by Subsidiaries	$ 77,779	$ 46,188	$ 44,261