Otter Tail (OTTR) 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1466593
Trading Symbol	ottr
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Well-Known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		37,363,740
Entity Public Float			$1,048,982,831
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents		$2,007
Accounts Receivable:
Trade (less allowance for doubtful accounts of $1,048 for 2014 and $1,148 for 2013)	60,172	57,828
Other	13,179	9,787
Inventories	85,203	72,627
Deferred Income Taxes	49,482	35,325
Unbilled Revenues	17,996	17,926
Regulatory Assets	25,273	17,940
Other	7,187	7,581
Assets of Discontinued Operations	48,657	49,478
Total Current Assets	307,149	270,499
Investments	8,582	9,362
Other Assets	30,111	28,834
Goodwill	31,488	31,488
Other Intangibles--Net	11,251	12,228
Deferred Debits
Unamortized Debt Expense	4,300	4,188
Regulatory Assets	129,868	83,730
Total Deferred Debits	134,168	87,918
Plant
Electric Plant in Service	1,545,112	1,460,884
Nonelectric Operations	175,159	170,925
Construction Work in Progress	248,677	187,462
Total Gross Plant	1,968,948	1,819,271
Less Accumulated Depreciation and Amortization	700,418	663,581
Net Plant	1,268,530	1,155,690
Total Assets	1,791,279	1,596,019
Current Liabilities
Short-Term Debt	10,854	51,195
Current Maturities of Long-Term Debt	201	188
Accounts Payable	107,013	96,109
Accrued Salaries and Wages	19,256	18,957
Accrued Taxes	13,793	12,227
Derivative Liabilities	14,230	11,782
Other Accrued Liabilities	8,793	6,532
Liabilities of Discontinued Operations	27,559	39,283
Total Current Liabilities	201,699	236,273
Pensions Benefit Liability	102,711	69,743
Other Postretirement Benefits Liability	53,638	45,221
Other Noncurrent Liabilities	26,794	25,209
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	230,810	192,222
Deferred Tax Credits	26,384	28,288
Regulatory Liabilities	77,013	73,926
Other	975	718
Total Deferred Credits	335,182	295,154
Capitalization (page 69)
Long-Term Debt, Net of Current Maturities	498,489	389,589
Common Shares, Par Value $5 Per Share--Authorized, 50,000,000 Shares; Outstanding, 2014-37,218,053 Shares; 2013-36,271,696 Shares	186,090	181,358
Premium on Common Shares	278,436	255,759
Retained Earnings	112,903	99,441
Accumulated Other Comprehensive Loss	-4,663	-1,728
Total Common Equity	572,766	534,830
Total Capitalization	1,071,255	924,419
Total Liabilities and Equity	1,791,279	1,596,019
Cumulative Preferred Shares
Capitalization (page 69)
Cumulative Shares
Cumulative Preference Shares
Capitalization (page 69)
Cumulative Shares

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parentheticals) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Trade, allowance for doubtful accounts (in dollars)	$1,048	$1,148
Common shares, par value (in dollars per share)	$5	$5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	37,218,053	36,271,696
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding
Cumulative Preference Shares
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues
Electric	$407,629	$373,462	$350,689
Product Sales	391,633	369,952	359,476
Total Operating Revenues	799,262	743,414	710,165
Operating Expenses
Production Fuel - Electric	67,216	71,248	66,284
Purchased Power - Electric System Use	65,848	52,006	49,184
Electric Operation and Maintenance Expenses	141,936	133,395	121,069
Cost of Products Sold (depreciation included below)	308,069	283,267	270,045
Other Nonelectric Expenses	45,981	40,074	40,273
Asset Impairment Charge			432
Depreciation and Amortization	58,074	57,876	57,857
Property Taxes - Electric	12,607	11,311	10,720
Total Operating Expenses	699,731	649,177	615,864
Operating Income	99,531	94,237	94,301
Interest Charges	29,648	26,974	31,903
Loss on Early Retirement of Debt		10,252	13,106
Other Income	3,557	4,100	3,915
Income Before Income Taxes - Continuing Operations	73,440	61,111	53,207
Income Tax Expense - Continuing Operations	16,557	12,516	7,173
Net Income from Continuing Operations	56,883	48,595	46,034
Discontinued Operations
Income (Loss) - net of Income Tax Expense of $3,952 in 2014, $1,036 in 2013 and $1,190 in 2012	6,445	2,060	-13,669
Impairment Loss - net of Income Tax (Benefit) of $0 in 2014 and ($21,213) in 2012	-5,605		-32,107
Gain (Loss) on Disposition - net of Income Tax Expense of $6 in 2013 and $315 in 2012		210	-5,531
Net Gain (Loss) from Discontinued Operations	840	2,270	-51,307
Total Net Income (Loss)	57,723	50,865	-5,273
Preferred Dividend Requirement and Other Adjustments		513	736
Earnings (Loss) Available for Common Shares	$57,723	$50,352	($6,009)
Average Number of Common Shares Outstanding--Basic (in shares)	36,514	36,151	36,048
Average Number of Common Shares Outstanding--Diluted (in shares)	36,753	36,355	36,242
Basic Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement) (in dollars per share)	$1.56	$1.33	$1.25
Discontinued Operations (in dollars per share)	$0.02	$0.06	($1.42)
Earnings Per Share, Basic, Total (in dollars per share)	$1.58	$1.39	($0.17)
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (net of preferred dividend requirement) (in dollars per share)	$1.55	$1.33	$1.25
Discontinued Operations (in dollars per share)	$0.02	$0.06	($1.42)
Earnings Per Share, Diluted, Total (in dollars per share)	$1.57	$1.39	($0.17)
Dividends Declared Per Common Share (in dollars per share)	$1.21	$1.19	$1.19

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (Parentheticals) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Income tax expense (benefit) on income from discontinued operations	$3,952	$1,036	$1,190
Income tax (benefit) on impairment loss on discontinued operations	0		-21,213
Income tax expense of (loss) gain on disposition of discontinued operations		$6	$315

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement Of Income and Comprehensive Income [Abstract]
Net Income (Loss)	$57,723	$50,865	($5,273)
Unrealized (Loss) Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	-19	-27
(Losses) Gains Arising During Period	-14	-77	154
Income Tax Benefit (Expense)	12	36	-53
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	-21	-68	101
Pension and Postretirement Benefit Plans:
Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment	-5,048	3,986	-2,133
Amortization of Unrecognized Postretirement Benefit Costs (note 11)	192	555	376
Income Tax Benefit (Expense)	1,942	-1,816	703
Pension and Postretirement Benefit Plans - net-of-tax	-2,914	2,725	-1,054
Total Other Comprehensive (Loss) Income	-2,935	2,657	-953
Total Comprehensive Income (Loss)	$54,788	$53,522	($6,226)

Consolidated_Statements_of_Com1

Consolidated Statements of Common Shareholders' Equity (USD $)	Common Shares	Premium On Common Shares	Retained Earnings	Accumulated Other Comprehensive Income/(Loss)		Total
In Thousands, except Share data
Balance at Dec. 31, 2011	$180,509	$253,123	$141,248	($3,432)	[1]	$571,448
Balance (in shares) at Dec. 31, 2011	36,101,695
Common Stock Issuances, Net of Expenses	359	148				507
Common Stock Issuances, Net of Expenses (in shares)	71,745
Common Stock Retirements	-26	-85				-111
Common Stock Retirements (in shares)	-5,072
Net Income (Loss)			-5,273			-5,273
Other Comprehensive Income (Loss)				-953		-953
Tax Benefit - Stock Compensation		-103				-103
Employee Stock Incentive Plan Expense		435				435
Premium on Purchase of Stock for Employee Purchase Plan		-222				-222
Cumulative Preferred Dividends			-736			-736
Common Dividends ($1.19 per share for the year ended December 2012, 2013 and $1.21 per share for 2014)			-43,018			-43,018
Balance at Dec. 31, 2012	180,842	253,296	92,221	-4,385	[1]	521,974
Balance (in shares) at Dec. 31, 2012	36,168,368
Common Stock Issuances, Net of Expenses	562	2,095				2,657
Common Stock Issuances, Net of Expenses (in shares)	112,512
Common Stock Retirements	-46	-177				-223
Common Stock Retirements (in shares)	-9,184
Net Income (Loss)			50,865			50,865
Other Comprehensive Income (Loss)				2,657		2,657
Tax Benefit - Stock Compensation		299				299
Employee Stock Incentive Plan Expense		418				418
Premium on Purchase of Stock for Employee Purchase Plan		-258				-258
Cumulative Preferred Dividends			-427			-427
Preferred Stock Issuance Expenses Transferred to Retained Earnings on Redemption of Preferred Shares		86	-86
Common Dividends ($1.19 per share for the year ended December 2012, 2013 and $1.21 per share for 2014)			-43,132			-43,132
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					36,271,696
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 (Loss)			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 ($1.19 per share for the year ended December 2012, 2013 and $1.21 per share for 2014)			-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					37,218,053
[1]	Accumulated Other Comprehensive Loss on December 31 is comprised of the following: (in thousands) 2014 2013 2012 Unrealized Gain on Marketable Equity Securities: Before Tax $ 40 $ 73 $ 177 Tax Effect (14) (26) (62) Unrealized Gain on Marketable Equity Securities Net-of-Tax 26 47 115 Unamortized Actuarial Losses, Prior Service Costs and Transition Obligation Related to Pension and Postretirement Benefits: Before Tax (7,815) (2,959) (7,500) Tax Effect 3,126 1,184 3,000 Unamortized Actuarial Losses and Transition Obligation Related to Pension and Postretirement Benefits Net-of-Tax (4,689) (1,775) (4,500)Accumulated Other Comprehensive Loss: Before Tax (7,775) (2,886) (7,323) Tax Effect 3,112 1,158 2,938 Net Accumulated Other Comprehensive Loss $ (4,663) $ (1,728) $ (4,385) See accompanying notes to consolidated financial statements.

Consolidated_Statements_of_Com2

Consolidated Statements of Common Shareholders' Equity (Parentheticals) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	($7,775)	($2,886)	($7,323)
Accumulated Other Comprehensive Income (Loss), Tax Effect	3,112	1,158	2,938
Accumulated Other Comprehensive Income (Loss), Net-of-Tax	-4,663	-1,728	-4,385
Unrealized Gain on Marketable Equity Securities:
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	40	73	177
Accumulated Other Comprehensive Income (Loss), Tax Effect	-14	-26	-62
Accumulated Other Comprehensive Income (Loss), Net-of-Tax	26	47	115
Unamortized Actuarial Losses, Prior Service Costs and Transition Obligation Related to Pension and Postretirement Benefits:
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Before Tax	-7,815	-2,959	-7,500
Accumulated Other Comprehensive Income (Loss), Tax Effect	3,126	1,184	3,000
Accumulated Other Comprehensive Income (Loss), Net-of-Tax	($4,689)	($1,775)	($4,500)

Consolidated_Statements_of_Com3

Consolidated Statements of Common Shareholders' Equity (Parentheticals 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement Of Stockholders' Equity [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$1.21	$1.19	$1.19

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net Income (Loss)	$57,723	$50,865	($5,273)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Net (Gain) Loss from Sale of Discontinued Operations		-210	5,531
Net (Income) Loss from Discontinued Operations	-840	-2,060	45,776
Depreciation and Amortization	58,074	57,876	57,857
Asset Impairment Charge			432
Premium Paid for Early Retirement of Long-Term Debt		9,889	12,500
Deferred Tax Credits	-1,904	-1,925	-2,091
Deferred Income Taxes	28,204	15,333	11,755
Change in Deferred Debits and Other Assets	-50,361	56,720	-4,654
Discretionary Contribution to Pension Fund	-20,000	-10,000	-10,000
Change in Noncurrent Liabilities and Deferred Credits	58,442	-42,226	32,718
Allowance for Equity/Other Funds Used During Construction	-1,543	-1,823	-1,168
Change in Derivatives Net of Regulatory Deferral	519	8	718
Stock Compensation Expense - Equity Awards	1,783	1,456	1,311
Other-Net	601	1,222	5,666
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	-4,647	4,033	-4,041
Change in Inventories	-12,577	-3,371	-675
Change in Other Current Assets	-579	-3,911	-1,324
Change in Payables and Other Current Liabilities	10,296	11,045	26,134
Change in Interest Payable and Income Taxes Receivable/Payable	2,578	-513	-16,146
Net Cash Provided by Continuing Operations	125,769	142,408	155,026
Net Cash (Used in) Provided by Discontinued Operations	-13,295	5,373	78,521
Net Cash Provided by Operating Activities	112,474	147,781	233,547
Cash Flows from Investing Activities
Capital Expenditures	-163,582	-159,833	-114,186
Proceeds from Disposal of Noncurrent Assets	2,467	2,196	2,832
Net Increase in Other Investments	-2,785	-1,845	-1,184
Net Cash Used in Investing Activities - Continuing Operations	-163,900	-159,482	-112,538
Net Proceeds from Sale of Discontinued Operations		12,842	42,229
Net Cash Used in Investing Activities - Discontinued Operations	-596	-2,557	-13,268
Net Cash Used in Investing Activities	-164,496	-149,197	-83,577
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	1,236
Net Short-Term (Repayments) Borrowings	-40,341	51,195
Proceeds from Issuance of Common Stock	26,259	1,821
Common Stock Issuance Expenses	-673	-3	-370
Payments for Retirement of Capital Stock	-590	-15,723	-111
Proceeds from Issuance of Long-Term Debt	150,000	40,900
Short-Term and Long-Term Debt Issuance Expenses	-856	-522	-897
Payments for Retirement of Long-Term Debt	-41,088	-72,981	-50,224
Premium Paid for Early Retirement of Long-Term Debt		-9,889	-12,500
Dividends Paid and Other Distributions	-44,261	-43,818	-43,976
Net Cash Provided by (Used in) Financing Activities - Continuing Operations	49,686	-49,020	-108,078
Net Cash Provided by (Used in) Financing Activities - Discontinued Operations	1,178		-4,278
Net Cash Provided by (Used in) Financing Activities	50,864	-49,020	-112,356
Net Change in Cash and Cash Equivalents - Discontinued Operations	-849	-2,306	-1,033
Net Change in Cash and Cash Equivalents	-2,007	-52,742	36,581
Cash and Cash Equivalents at Beginning of Period	2,007	54,749	18,168
Cash and Cash Equivalents at End of Period		$2,007	$54,749

Consolidated_Statements_of_Cap

Consolidated Statements of Capitalization (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Schedule of Capitalization [Line Items]
Short-Term Debt	$10,854	$51,195
Long-Term Debt	498,691	389,778
Less: Current Maturities - Otter Tail Corporation	201	188
Unamortized Debt Discount - Otter Tail Corporation	1	1
Total Long-Term Debt	498,489	389,589
Total Common Shareholders' Equity	572,766	534,830
Total Capitalization	1,071,255	924,419
Cumulative Preferred Shares
Schedule of Capitalization [Line Items]
Cumulative Shares
Cumulative Preference Shares
Schedule of Capitalization [Line Items]
Cumulative Shares
Otter Tail Corporation Credit Agreement
Schedule of Capitalization [Line Items]
Short-Term Debt	10,854
Otter Tail Power Company Credit Agreement
Schedule of Capitalization [Line Items]
Short-Term Debt		51,195
9.000% Notes, due December 15, 2016
Schedule of Capitalization [Line Items]
Long-Term Debt	52,330	52,330
North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [Line Items]
Long-Term Debt	256	325
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	1,105	1,223
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Schedule of Capitalization [Line Items]
Long-Term Debt		40,900
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
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
Otter Tail Corporation
Schedule of Capitalization [Line Items]
Short-Term Debt	10,854
Long-Term Debt	53,691	53,878
Less: Current Maturities - Otter Tail Corporation	201	188
Unamortized Debt Discount - Otter Tail Corporation	1	1
Total Long-Term Debt	53,489	53,689
Total Capitalization	626,255	588,519
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Schedule of Capitalization [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Schedule of Capitalization [Line Items]
Long-Term Debt	256	325
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Schedule of Capitalization [Line Items]
Long-Term Debt	1,105	1,223
Otter Tail Power Company
Schedule of Capitalization [Line Items]
Short-Term Debt		51,195
Long-Term Debt	445,000	335,900
Less: Current Maturities - Otter Tail Corporation
Unamortized Debt Discount - Otter Tail Corporation
Total Long-Term Debt	445,000	335,900
Otter Tail Power Company | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Schedule of Capitalization [Line Items]
Long-Term Debt		40,900
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
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

Consolidated_Statements_of_Cap1

Consolidated Statements of Capitalization (Parentheticals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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	15-Dec-16	15-Dec-16
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	1-Apr-18	1-Apr-18
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	18-Mar-21	21-Mar-21
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Schedule of Capitalization [Line Items]
Long-Term Debt, Due Date		15-Jan-15
Debt Instrument Retirement Date		27-Feb-14
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	20-Aug-17	20-Aug-17
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	1-Dec-21	1-Dec-21
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	20-Aug-22	20-Aug-22
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	20-Aug-27	20-Aug-27
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	27-Feb-29	27-Feb-29
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	20-Aug-37	20-Aug-37
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	27-Feb-44	27-Feb-44
Cumulative Preferred Shares
Schedule of Capitalization [Line Items]
Cumulative shares, without par value (in dollars per share)
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, outstanding
Cumulative Preference Shares
Schedule of Capitalization [Line Items]
Cumulative shares, without par value (in dollars per share)
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, outstanding
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	15-Dec-16	15-Dec-16
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	1-Apr-18	1-Apr-18
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	18-Mar-21	18-Mar-21
Otter Tail Power Company | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Schedule of Capitalization [Line Items]
Long-Term Debt, Due Date		15-Jan-15
Debt Instrument Retirement Date	27-Feb-14	27-Feb-14
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	20-Aug-17	20-Aug-17
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	1-Dec-21	1-Dec-21
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	20-Aug-22	20-Aug-22
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	20-Aug-27	20-Aug-27
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	27-Feb-29	27-Feb-29
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	20-Aug-27	20-Aug-37
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	27-Feb-44	27-Feb-44

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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, (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
	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 $689,000 in 2014, $1,002,000 in 2013 and $656,000 in 2012. 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 service lives of the properties (5 to 70 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.89% in 2014, 2.96% in 2013 and 2.98% in 2012. 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 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 2014, 2013 or 2012. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
	Jointly Owned Facilities
	The consolidated balance sheets include OTP’s ownership interests in the assets and liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Big Stone Plant:
	Electric Plant in Service		$	143,746		$	142,780
	Construction Work in Progress			160,809			94,913
	Accumulated Depreciation			(86,211	)		(83,005	)
	Net Plant		$	218,344		$	154,688
	Coyote Station:
	Electric Plant in Service		$	163,824		$	162,095
	Construction Work in Progress			1,725			303
	Accumulated Depreciation			(99,364	)		(96,907	)
	Net Plant		$	66,185		$	65,491
	OTP is a joint owner, with other regional utilities, in three major transmission lines and two additional major planned transmission line projects with the following ownership interests: 14.8% in the Bemidji-Grand Rapids 230 kV line, approximately 14.1% in the Fargo-Monticello 345 kV line, approximately 4.8% in the Brookings-Southeast Twin Cities Multi-Value Project (MVP) 345 kV line, 50.0% in the Big Stone South to Brookings MVP 345 kV line and 50.0% in the Big Stone South to Ellendale MVP 345 kV line. The following amounts for the jointly-owned transmission facilities are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Electric Plant in Service		$	68,648		$	26,337
	Construction Work in Progress			59,163			71,205
	Accumulated Depreciation			(1,758	)		(837	)
	Net Plant		$	126,053		$	96,705
	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
	In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.
	Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through December 31, 2014 is $21.6 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2014 could be as high as $21.6 million.
	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.
	In June 2012, the Company entered into a nonbinding letter of interest with Trinity Industries, Inc. (Trinity) to sell the fixed assets of IMD for $20 million, with the Company retaining IMD’s net working capital—approximately $66 million on June 30, 2012. On September 6, 2012 the Company entered into definitive agreements with Trinity to sell the fixed assets of IMD for $20 million. The agreed on price for the fixed assets was an indicator of the fair value of the assets under level 2 of the ASC fair value hierarchy and an indication of a decrease in the market value of the assets being sold, which were significantly impacted by a decline in market conditions in the wind energy industry. IMD had no tower orders for 2013 due to the expected expiration, at the end of 2012, of the Federal Production Tax Credit (PTC) for investments in renewable energy resources. These factors resulted in IMD recording a fair value adjustment of its long-lived assets to the indicated market price of $20 million and an asset impairment charge of $45.6 million ($27.5 million net-of-tax benefits), or $0.76 per share, in June 2012 broken down as follows:
	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	45,285
	Goodwill			288
	Total Asset Impairment Charges		$	45,573
	The sales of IMD’s fixed assets were completed in 2012 with the effects of the related transactions reflected in discontinued operations in the Company’s 2012 consolidated financial statements. See note 16 to consolidated financial statements for further information.
	Otter Tail Energy Services Company (OTESCO) recorded an asset impairment charge of $0.4 million in 2012 related to wind farm development rights at its Sheridan Ridge and Stutsman County sites in North Dakota based on the fair value of these assets declining to $0 as of March 31, 2012.
	On February 8, 2013 the Company sold substantially all of the assets of Shrco, Inc. (Shrco), the Company’s former waterfront equipment manufacturer, subject to certain closing conditions. The Company recorded a $7.7 million ($4.6 million net-of-tax benefits), or $0.13 per share, asset impairment charge in December 2012 based on the indicated market value of Shrco’s assets broken down as follows:
	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	5,859
	Inventory			782
	Accrued Selling Costs			1,106
	Total Impairment Charges		$	7,747
	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, and has recognized in its consolidated financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for uncertain tax positions.
	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 and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 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 (ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.
	For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.
	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.
	OTP’s unrealized gains and losses on forward energy contracts that do not meet the definition of capacity contracts are marked to market and reflected on a net basis in electric revenue on the Company’s consolidated statement of income. Under ASC 815, OTP’s forward energy contracts that do not meet the definition of a capacity contract and are subject to unplanned netting do not qualify for the normal purchase and sales exception from mark-to-market accounting. See note 5 to consolidated financial statements for further discussion.
	Manufacturing operating revenues are recorded when products are shipped.
	The Company’s construction companies, reported under discontinued operations in the accompanying financial statements,   enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. The method used to determine the progress of completion is based on the ratio of costs incurred to total estimated costs on construction projects. See note 16 to consolidated financial statements.
	The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:
			December 31,			December 31,
	(in thousands)		2014			2013
	Costs Incurred on Uncompleted Contracts		$	402,332		$	361,487
	Less Billings to Date			(411,909	)		(377,608	)
	Plus Estimated Earnings Recognized			15,154			6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	5,577		$	(9,644	)
The following costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings are included in the Company’s consolidated balance sheets under assets of discontinued operations and liabilities of discontinued operations:
	December 31,	December 31,
(in thousands)	2014	2013
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$     8,133	$     4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(2,556)	(13,707)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$     5,577	$   (9,644)
The Company has a standard quarterly estimate at completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.
In 2012, Foley Company (Foley) experienced cost overruns in excess of estimated costs on several large projects. All of these projects were substantially completed as of December 31, 2012. Estimated costs on certain projects in excess of previous period estimates resulted in insignificant pretax charges in 2014 compared with $0.6 million in 2013 and $14.9 million in 2012.
Plastics operating revenues are recorded when the product is shipped.
Warranty Reserves
The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The warranty reserve balances as of December 31, 2014 and December 31, 2013 relate entirely to products that were produced by IMD and Shrco prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.
Retainage
Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction subsidiaries that have been retained by customers pending project completion:
		December 31,			December 31,
(in thousands)		2014			2013
Accounts Receivable Retained by Customers		$	6,759		$	7,125
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. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, accrued renewable resource, transmission and environmental cost recovery rider revenues, valuations of forward energy contracts, percentage-of-completion, warranty reserves and actuarially determined benefits costs and liabilities. 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, 2014 and 2013:
		December 31,			December 31,
(in thousands)		2014			2013
Cost Method:
Economic Development Loan Pools		$	174		$	219
Other			129			158
Equity Method - Affordable Housing and Other Partnerships			265			43
Marketable Securities Classified as Available-for-Sale			8,014			8,942
Total Investments		$	8,582		$	9,362
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, 2014. See further discussion below.
Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).
Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2014 and December 31, 2013:
December 31, 2014 (in thousands)		Level 1			Level 2			Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts		$	--		$	--		$	257
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company						6,761
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,253
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			593
Total Assets		$	713		$	8,014		$	257
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts		$	--		$	342		$	--
Derivative Liabilities - Forward Energy Contracts			--			--			13,888
Total Liabilities		$	--		$	342		$	13,888
December 31, 2013 (in thousands)		Level 1			Level 2			Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts		$	--		$	--		$	338
Forward Gasoline Purchase Contracts						62
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company						7,671
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,271
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			866
Total Assets		$	976		$	9,004		$	338
Liabilities:
Derivative Liabilities - Forward Energy Contracts		$	--		$	103		$	11,679
Total Liabilities		$	--		$	103		$	11,679
The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.
Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.
Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of December 31, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The December 31, 2014 Level 3 forward electric basis spreads ranged from $2.50 to $7.97 per megawatt-hour under the active trading hub price. The weighted average price was $34.95 per megawatt-hour.
In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of December 31, 2014 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the years ended December 31, 2014 and 2013.
The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the twelve-month periods ended December 31, 2014 and 2013:
(in thousands)		2014			2013
Forward Energy Contracts - Fair Values Beginning of Period		$	(11,341	)	$	(17,782	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods			2,785			7,943
Changes in Fair Value of Contracts Entered into in Prior Periods			166			(640	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period			(8,390	)		(10,479	)
Net Decrease in Value of Open Contracts Entered into in Current Period			(5,241	)		(862	)
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period		$	(13,631	)	$	(11,341	)
Inventories
The Electric segment inventories are reported at average cost. All other segments’ inventories are stated at the lower of cost (first‑in, first‑out) or market. Inventories consist of the following:
		December 31,			December 31,
(in thousands)		2014			2013
Finished Goods		$	27,998		$	20,649
Work in Process			10,628			9,942
Raw Material, Fuel and Supplies			46,577			42,036
Total Inventories		$	85,203		$	72,627
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, measuring its goodwill and indefinite-lived intangible assets for impairment annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine the fair value of the reporting unit.
In the fourth quarter of 2012 the Company sold Moorhead Electric, Inc. (MEI), a subsidiary company that provided electrical contracting services. In connection with this sale, the Company disposed of $147,000 in goodwill associated with the purchase of MEI in 1992. With the classification of Aevenia in discontinued operations in 2014, the 2012 results of operations and cash flows of MEI are now reflected in discontinued operations.
In the fourth quarter of 2014 the Company entered into negotiations to sell its wholly owned subsidiary, Foley, a mechanical and prime contractor on industrial projects. As a result of an impairment indicator during the fourth quarter of 2014, the Company recorded a $5.6 million, or $0.15 per share, goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. The goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.
The following tables summarize changes to goodwill by business segment during 2014 and 2013:
		Gross Balance			Accumulated			Balance				Adjustments		Balance
(in thousands)		31-Dec-13			Impairments			(net of impairments)				to Goodwill		(net of impairments)
								31-Dec-13				in 2014		31-Dec-14
Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
Plastics			19,302			--			19,302				--		19,302
Total		$	31,488		$	--		$	31,488			$	--	$	31,488
		Gross Balance			Accumulated			Balance				Adjustments		Balance
(in thousands)		31-Dec-12			Impairments			(net of impairments)				to Goodwill		(net of impairments)
								31-Dec-12				in 2013		31-Dec-13
Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
Plastics			19,302			--			19,302				--		19,302
Total		$	31,488		$	--		$	31,488			$	--	$	31,488
Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 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:
2014 (in thousands)		Gross Carrying			Accumulated			Net Carrying			Remaining
		Amount			Amortization			Amount			Amortization
											Periods
Amortizable Intangible Assets:
Customer Relationships		$	16,811		$	5,784		$	11,027		60-160 months
Other Intangible Assets Including Contracts			639			415			224		21 months
Total		$	17,450		$	6,199		$	11,251
2013 (in thousands)
Amortizable Intangible Assets:
Customer Relationships		$	16,811		$	4,935		$	11,876		72-172 months
Other Intangible Assets Including Contracts			772			420			352		33 months
Total		$	17,583		$	5,355		$	12,228
The amortization expense for these intangible assets was:
(in thousands)		2014			2013			2012
Amortization Expense – Intangible Assets		$	977		$	977		$	981
The estimated annual amortization expense for these intangible assets for the next five years is:
(in thousands)		2015			2016			2017				2018		2019
Estimated Amortization Expense – Intangible Assets		$	977		$	945		$	849			$	849	$	849
Supplemental Disclosures of Cash Flow Information
		As of December 31,
(in thousands)		2014			2013
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1		$	24,526		$	22,951
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2		$	4,594		$	3,264
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.
2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.
(in thousands)		2014			2013			2012
Cash Paid (Received) During the Year for:
Interest (net of amount capitalized)		$	26,364		$	26,789		$	30,741
Income Taxes		$	145		$	(453	)	$	(353	)
New Accounting Standards
Accounting Standards Update (ASU) 2013-11
In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis and transferred $4.3 million of unrecognized tax benefits from other long-term liabilities to long-term deferred income taxes.
ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.

Business_Combinations_Disposit

Business Combinations, Dispositions and Segment Information	12 Months Ended
	Dec. 31, 2014
Business Combinations, Dispositions and Segment Information [Abstract]
Business Combinations, Dispositions and Segment Information	2. Business Combinations, Dispositions and Segment Information
	The Company acquired no new businesses in 2014, 2013 or 2012.
	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 2013 and 2012, and was in the process of negotiating the sales of Foley, its mechanical and prime contractor on industrial projects, and Aevenia, Inc. (Aevenia), its electrical design and construction services company, on December 31, 2014, which resulted in the removal of its Construction segment from continuing operations. The sale of substantially all of Shrco’s assets closed on February 8, 2013. On November 30, 2012 the Company completed the sale of the fixed assets of IMD, eliminating its Wind Energy segment. On February 29, 2012 the Company completed the sale of DMS Health Technologies, Inc. (DMS), its health services company, eliminating its Health Services segment. On January 18, 2012 the Company sold the assets of Aviva Sports, Inc. (Aviva), a wholly owned subsidiary of Shrco that sold various recreational products.
	The results of operations of Shrco including Aviva, IMD, DMS, Wylie, Foley and Aevenia are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years ended December 31, 2014, 2013 and 2012, 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 an active wholesale participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Prior to 2013, the Electric segment included OTESCO, which provided technical and engineering services. OTESCO ceased operations and did not record any operating revenues, expenses or net income in 2013 or 2014.
	Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping and fabrication, and production of material and handling trays, horticultural containers and produce packaging. These businesses have manufacturing facilities in Illinois and Minnesota and sell products primarily in the United States.
	Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.
	OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.
	No single customer accounted for over 10% of the Company’s consolidated revenues in 2014, 2013 or 2012. All of the Company’s long-lived assets are within the United States.
	Percent of Sales Revenue by Country for the Year Ended December 31:	2014			2013			2012
	United States of America		95.9	%		97.2	%		97.3	%
	Mexico		3	%		1.7	%		1.3	%
	Canada		0.9	%		1	%		1.4	%
	All Other Countries (none greater than 0.05%)		0.2	%		0.1	%		0	%
	The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information on continuing operations for the business segments for 2014, 2013 and 2012 is presented in the following table:
	(in thousands)	2014			2013			2012
	Operating Revenue
	Electric	$	407,743		$	373,540		$	350,765
	Manufacturing		219,583			204,997			208,965
	Plastics		172,050			164,957			150,517
	Intersegment Eliminations		(114	)		(80	)		(82	)
	Total	$	799,262		$	743,414		$	710,165
	Cost of Products Sold
	Manufacturing	$	169,033		$	154,235		$	157,437
	Plastics		139,081			129,042			112,662
	Intersegment Eliminations		(45	)		(10	)		(54	)
	Total	$	308,069		$	283,267		$	270,045
	Other Nonelectric Expenses
	Manufacturing	$	23,340		$	18,820		$	18,233
	Plastics		9,292			8,571			8,784
	Corporate		13,418			12,753			13,284
	Intersegment Eliminations		(69	)		(70	)		(28	)
	Total	$	45,981		$	40,074		$	40,273
	Depreciation and Amortization
	Electric	$	44,076		$	43,125		$	42,051
	Manufacturing		10,518			11,194			12,208
	Plastics		3,364			3,350			3,118
	Corporate		116			207			480
	Total	$	58,074		$	57,876		$	57,857
	Operating Income (Loss)
	Electric	$	76,060		$	62,455		$	61,025
	Manufacturing		16,692			20,748			21,087
	Plastics		20,313			23,994			25,953
	Corporate		(13,534	)		(12,960	)		(13,764	)
	Total	$	99,531		$	94,237		$	94,301
	Interest Charges
	Electric	$	23,322		$	17,461		$	19,049
	Manufacturing		3,243			3,255			3,557
	Plastics		1,043			1,001			2,519
	Corporate and Intersegment Eliminations		2,040			5,257			6,778
	Total	$	29,648		$	26,974		$	31,903
	(in thousands)	2014			2013			2012
	Income Tax Expense (Benefit) – Continuing Operations
	Electric	$	11,029		$	9,278		$	5,862
	Manufacturing		4,117			6,047			6,954
	Plastics		7,301			9,249			9,393
	Corporate		(5,890	)		(12,058	)		(15,036	)
	Total	$	16,557		$	12,516		$	7,173
	Earnings (Loss) Available for Common Shares
	Electric	$	43,684		$	38,236		$	38,341
	Manufacturing		9,361			11,457			10,676
	Plastics		12,085			13,809			14,113
Corporate		(8,247	)		(15,420	)		(17,832	)
Discontinued Operations		840			2,270			(51,307	)
Total	$	57,723		$	50,352		$	(6,009	)
Capital Expenditures
Electric	$	148,719		$	149,467		$	101,919
Manufacturing		11,252			7,046			9,311
Plastics		3,567			3,273			2,819
Corporate		44			47			137
Total	$	163,582		$	159,833		$	114,186
Identifiable Assets
Electric	$	1,472,647		$	1,290,416		$	1,226,145
Manufacturing		130,701			119,302			114,933
Plastics		87,356			76,853			78,855
Corporate		51,918			59,970			112,616
Assets of Discontinued Operations		48,657			49,478			69,788
Total	$	1,791,279		$	1,596,019		$	1,602,337

Rate_and_Regulatory_Matters

Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 2014
Rate and Regulatory Matters [Abstract]
Rate and Regulatory Matters	3. Rate and Regulatory Matters
	Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2014, 2013 or 2012.
	Major Capital Expenditure Projects
	The Big Stone South – Brookings Project—This is a planned 345 kiloVolt (kV) transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013 and granted approval of a route permit for the southern portion of the line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017.
	The Big Stone South – Ellendale Project—This is a proposed 345 kV transmission line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU).  MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019.
	Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kV Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji–Grand Rapids 230 kV Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project. Recovery of OTP’s CapX2020 transmission investments is through the MISO Tariff (the Brookings Project as an MVP) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
	The Fargo Project—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. The St. Cloud to Alexandria portion of the Fargo Project was placed into service on April 23, 2014. Construction is underway for the remaining portion of the project, which is expected to be in service in 2015.
	The Brookings Project—The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized in April 2014. The entire project is expected to be in service in 2015.
	The Bemidji Project—The Bemidji-Grand Rapids transmission line was fully energized and put into service on September 17, 2012.
	Big Stone Plant Air Quality Control System (AQCS)—The South Dakota Department of Environment and Natural Resources determined that the Big Stone Plant is subject to Best-Available Retrofit Technology (BART) requirements of the Clean Air Act, based on air dispersion modeling indicating that Big Stone Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan.
	OTP is currently in the process of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through December 31, 2014 is $153 million, excluding Allowance for Funds Used During Construction (AFUDC).
	Big Stone II Project—On June 30, 2005 OTP and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. On September 11, 2009 OTP announced its withdrawal—both as a participating utility and as the project’s lead developer—from Big Stone II. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project. OTP requested jurisdictional recovery in Minnesota, North Dakota and South Dakota of amounts it had invested in the Big Stone II project at the time of its withdrawal, discussed below under the respective jurisdictional sections of this report.
	Minnesota
	2010 General Rate Case— OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (MNCIP) costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota Fuel Clause Adjustment. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.
	Renewable Energy Standards, Conservation, Renewable Resource Riders— Minnesota has a renewable energy standard which requires OTP to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, Minnesota law requires 1.5% of total Minnesota electric sales by public utilities to be supplied by solar energy by 2020. OTP is currently evaluating potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired sufficient renewable resources to comply with Minnesota renewable energy standards. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.
	Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.
	The costs for three major wind farms previously approved by the MPUC for recovery through OTP’s Minnesota Renewable Resource Adjustment (MNRRA) were moved to base rates as of October 1, 2011 under the MPUC’s April 25, 2011 general rate case order with the exception of the remaining balance of the MNRRA regulatory asset. OTP continued to collect the remaining regulatory asset balance through April 30, 2013, when the balance was near zero. On April 4, 2013 the MPUC authorized that any remaining unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. Effective May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs.
	Minnesota Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.
	The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.
	On January 11, 2012 the MPUC approved the recovery of $3.5 million for 2010 MNCIP financial incentives. Beginning in January 2012, OTP’s MNCIP Conservation Cost Recovery Adjustment increased from 3.0% to 3.8% for all Minnesota retail electric customers. On March 30, 2012 OTP recognized an additional $0.4 million of incentive related to 2011 and submitted its annual 2011 financial incentive filing request for $2.6 million. In December 2012, the MPUC approved the recovery of $2.6 million in financial incentives for 2011 and also ordered a change in the MNCIP cost recovery methodology used by OTP from a percentage of a customer’s bill to an amount per kwh consumed. On January 1, 2013 OTP’s MNCIP surcharge decreased from 3.8% of the customer’s bill to $0.00142 per kwh, which equates to approximately 1.9% of a customer’s bill. OTP recognized $2.6 million of MNCIP financial incentives in 2012 and an additional $0.1 million in 2013 relating to 2012 program results. On October 10, 2013 the MPUC approved OTP’s 2012 financial incentive request for $2.7 million as well as its request for an updated surcharge rate to be implemented on November 1, 2013. OTP recognized $3.9 million in MNCIP financial incentives in 2013 related to the results of its conservation improvement programs in Minnesota in 2013. On April 1, 2014 OTP submitted its annual 2013 financial incentive filing request for $4.0 million along with a request for an updated surcharge rate. On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. Based on preliminary results from the 2014 MNCIP program year, OTP is estimating a financial incentive for 2014 of $2.5 million. OTP is estimating a lower incentive for 2014 in response to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016.  Also, OTP estimates it saved approximately 3 million less kwhs in 2014 compared with 2013. OTP will request approval from the MPUC in an April 1, 2015 filing.
	OTP had a regulatory asset of $8.2 million for allowable costs and financial incentives eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of December 31, 2014. OTP’s Minnesota conservation recoverable costs and incentives totaled $7.8 million in 2014, $9.3 million in 2013 and $7.8 million in 2012.
	Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities Act (the Act) provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s initial request for approval of a TCR rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010.
	MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers. On March 26, 2012 the MPUC approved an update to OTP’s Minnesota TCR rider along with an all-in method for MISO regional cost allocations in which OTP’s retail customers would be responsible for the entire investment OTP made in transmission facilities that qualify for regional cost allocation under the MISO Tariff, with an offsetting credit for revenues received from other MISO utilities under the MISO Tariff for projects included in the TCR. OTP’s updated Minnesota TCR rider went into effect April 1, 2012.
	On May 24, 2012 OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery through the TCR rider. OTP filed its annual update to the TCR rider on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of CON estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC approval of OTP’s annual TCR update, OTP submitted 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. OTP filed its 2014 annual update on May 1, 2014. The MNDOC recommended approval of the 2014 update on September 24, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015.
	OTP had a regulatory asset of $3.4 million for amounts eligible for recovery through the Minnesota TCR rider that had not been billed to Minnesota customers as of December 31, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota TCR rider of $6.3 million in 2014, $2.9 million in 2013 and $2.4 million in 2012.
	Environmental Cost Recovery (ECR) Rider—In a written order issued on January 23, 2012 the MPUC granted OTP’s petition for Advance Determination of Prudence (ADP) for costs associated with the design, construction and operation of the BART-compliant AQCS at Big Stone Plant attributable to serving OTP’s Minnesota customers. On May 24, 2013 legislation was enacted in Minnesota which allowed OTP to file an emission-reduction rider for recovery of the revenue requirements of the AQCS. The legislation authorizes the rider to allow a current return on investment, including Construction Work in Progress (CWIP), at the level approved in OTP’s most recent general rate case, unless a different return is determined by the MPUC to be in the public interest. On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. OTP filed its 2014 annual update on July 31, 2014, requesting a $4.1 million annual increase in the rider from $6.1 million to $10.2 million. The MPUC approved OTP’s ECR rider annual update request on November 24, 2014, effective December 1, 2014. Because the effective date was two months behind the anticipated implementation date for the updated rate and a portion of the requested increase had been collected under the initial rate, the approved updated rate is based on a revenue requirement of $9.8 million. The rate will continue to be updated in annual filings with the MPUC until the costs are rolled into base rates at an undetermined future date.
	OTP had a regulatory asset of $0.2 million for amounts eligible for recovery through the Minnesota ECR rider that had not been billed to Minnesota customers as of December 31, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota ECR rider in 2014 of $6.9 million.
	Big Stone II Project Cost Recovery—OTP requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers as part of the rates established in that proceeding was $3.2 million. Because OTP was not allowed to earn a return on these deferred costs over the 60-month recovery period, the recoverable amount of $3.2 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate, in accordance with ASC Topic 980, Regulated Operations (ASC 980) accounting requirements. Transmission-related project costs of $3.2 million remained in CWIP as active project costs at the time of the order.
	Approximately $0.4 million of the total Minnesota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP transmission line project in the first quarter of 2013. The remaining transmission costs, along with accumulated AFUDC, were transferred from CWIP to a regulatory asset account in May 2013, based on recovery granted in the April 25, 2011 order. Because OTP was not allowed to earn a return on these deferred costs over their anticipated recovery period, the recoverable amount of approximately $3.5 million was discounted to its present value using OTP’s incremental borrowing rate. In May 2013, OTP recorded a charge of $0.7 million related to the discount in accordance with ASC 980 accounting requirements. In June 2014, OTP recorded an additional discount of $0.3 million to reflect changes in the end date of the anticipated recovery period from September 2020 to December 2022.
	North Dakota
	General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009.
	Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed. On March 21, 2012 the NDPSC approved an update to OTP’s NDRRA effective April 1, 2012. The updated NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the updated rates implemented on April 1, 2013. The NDPSC approved OTP’s most recent annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014. The update approved on March 12, 2014 resulted in a 13.5% reduction in the NDRRA rate. On December 31, 2014 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2015.
	OTP had a regulatory liability of $1.0 million as of December 31, 2014 for amounts billed to North Dakota customers that were subject to refund through the NDRRA rider. OTP recognized revenue for amounts eligible for recovery through the NDRRA rider of $7.5 million in 2014, $8.6 million in 2013 and $9.3 million in 2012.
	Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. On April 29, 2011 OTP filed a request for an initial North Dakota TCR rider with the NDPSC, which was approved on April 25, 2012 and effective May 1, 2012. On August 31, 2012 OTP filed its annual update to the North Dakota TCR rider rate to reflect updated cost information associated with projects currently in the rider, as well as proposing to include costs associated with ten additional projects for recovery within the rider. The NDPSC approved the annual update on December 12, 2012 with an effective date of January 1, 2013. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million. The NDPSC approved the annual update on December 17, 2014 with an effective date of January 1, 2015.
	OTP had a regulatory asset of $0.9 million for amounts eligible for recovery through the North Dakota TCR rider that had not been billed to North Dakota customers as of December 31, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota TCR rider of $5.8 million in 2014, $3.2 million in 2013 and $1.4 million in 2012.
	Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. On July 10, 2014 the NDPSC approved OTP’s 2014 ECR rider annual update request with an August 1, 2014 implementation date.
	OTP had a regulatory asset of $0.7 million for amounts eligible for recovery through the North Dakota ECR rider that had not been billed to North Dakota customers as of December 31, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota ECR rider of $5.9 million in 2014 and $2.3 million in 2013.
	Big Stone II Project—In an order issued June 25, 2010, the NDPSC authorized recovery of Big Stone II development costs from North Dakota ratepayers, pursuant to a final settlement agreement filed June 23, 2010, between the NDPSC advocacy staff, OTP and the North Dakota Large Industrial Energy Group, Interveners. The terms of the settlement agreement indicate that OTP’s discontinuation of participation in the project was prudent and OTP should be authorized to recover the portion of costs it incurred related to the Big Stone II generation project. The total amount of Big Stone II generation costs incurred by OTP (which excluded $2.6 million of project transmission-related costs) was determined to be $10.1 million, of which $4.1 million represents North Dakota’s jurisdictional share.
	OTP included in its total recovery amount a carrying charge of approximately $0.3 million on the North Dakota share of Big Stone II generation costs for the period from September 1, 2009 through the date the recovery of costs began based on OTP’s average 2009 AFUDC rate of 7.65%. Because OTP would not earn a return on these deferred costs over the 36-month recovery period, the recoverable amount of $4.3 million was discounted to its then present value of $3.9 million using OTP’s incremental borrowing rate, in accordance with ASC 980 accounting requirements. The North Dakota portion of Big Stone II generation costs was recovered over a 36-month period which began on August 1, 2010.
	The North Dakota jurisdictional share of Big Stone II costs incurred by OTP related to transmission was $1.1 million. Approximately $0.3 million of the total North Dakota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP during the first quarter of 2013. On July 30, 2013 the NDPSC approved OTP’s request to continue the Big Stone II cost recovery rates for an additional eight months through March 31, 2014 to recover the remaining North Dakota share of Big Stone II transmission-related costs plus accrued AFUDC totaling $1.0 million. As of April 1, 2014 North Dakota customer’s bills no longer include a charge for North Dakota share of Big Stone II costs. OTP had a regulatory liability of $0.1 million as of December 31, 2014 for amounts billed to North Dakota customers that will be refunded through the North Dakota TCR rider.
	South Dakota
	2010 General Rate Case—On April 21, 2011, the SDPUC issued a written order approving an overall revenue increase for OTP of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50%. Final rates were effective with bills rendered on and after June 1, 2011.
	Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP submitted a request for an initial South Dakota TCR rider to the SDPUC on November 5, 2010. The South Dakota TCR was approved by the SDPUC and implemented on December 1, 2011. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s following annual update to its South Dakota TCR on February 18, 2014 with an effective date of March 1, 2014. OTP filed another annual update on October 31, 2014, which was approved by the SDPUC on February 13, 2015 with an effective date of March 1, 2015.
	OTP had a regulatory liability of less than $0.1 million as of December 31, 2014 for amounts billed to South Dakota customers that were subject to refund through the South Dakota TCR rider. OTP recognized revenue for amounts eligible for recovery through the South Dakota TCR rider of $1.2 million in 2014, $0.8 million in 2013 and $0.4 million in 2012.
	Environmental Cost Recovery Rider—On March 30, 2012 OTP requested approval from the SDPUC for an ECR rider to recover costs associated with the Big Stone Plant AQCS. On April 17, 2013 OTP filed a request to either suspend or withdraw this filing. The SDPUC approved withdrawing this filing on April 23, 2013. On August 29, 2014 OTP filed a new request with the SDPUC for an ECR rider to recover costs associated with new environmental measures including costs to comply with mercury and air toxics standards. On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover the costs of the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects, with an effective date of December 1, 2014.
	OTP had a regulatory asset of less than $0.1 million for amounts eligible for recovery through the South Dakota ECR rider that had not been billed to South Dakota customers as of December 31, 2014. OTP recognized revenue for amounts eligible for recovery through the South Dakota ECR rider of $0.2 million in 2014.
	Big Stone II Project—OTP requested recovery of the South Dakota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in South Dakota on August 20, 2010. In the first quarter of 2011, the SDPUC approved recovery of the South Dakota portion of Big Stone II generation development costs totaling approximately $1.0 million from South Dakota ratepayers over a ten-year period beginning in February 2011 with the implementation of interim rates. OTP is allowed to earn a return on the amount subject to recovery over the ten-year recovery period. Therefore, the South Dakota settlement amount is not discounted. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP.
	A portion of the Big Stone II transmission costs were transferred out of CWIP in February 2013 to be included within the Big Stone South - Brookings MVP. On March 28, 2013 OTP filed a petition with the SDPUC requesting deferred accounting for the remaining unrecovered Big Stone II transmission costs until OTP’s next South Dakota general rate case. The petition was approved by the SDPUC on April 23, 2013 and in May 2013 OTP transferred the remaining South Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $0.2 million from CWIP to the Big Stone II Unrecovered Project Costs – South Dakota regulatory asset accounts.
	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.
	Effective January 1, 2010 the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Tariff. OTP was also authorized by the FERC to recover in its formula rate (1) 100% of prudently incurred CWIP in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects in which OTP is a joint owner: the Fargo Project, the Bemidji Project and the Brookings Project.
	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.
	Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. On June 7, 2013, in response to a challenge to the MVP cost allocation heard before the United States Court of Appeals, Seventh Circuit, the Court ruled in favor of MISO and MISO transmission owners, issuing an order affirming the FERC’s approval of the MVP cost allocation. On February 24, 2014 the U.S. Supreme Court denied petitions for a writ of certiorari of the Seventh Circuit’s decision upholding the FERC’s MVP orders. The petitioners did not seek rehearing.
	On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. Settlement discussions did not resolve the dispute and the FERC set the proceeding to a Track II Hearing for complex cases that can take several months to decide, with a FERC decision anticipated in fall 2016 at the earliest. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization (RTO) participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the resolution of the return on equity complaint proceeding.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	4. Regulatory Assets and Liabilities
	As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:
		31-Dec-14						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see note
	Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
	Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
	Minnesota Transmission Rider Accrued Revenues2		943		2,455		3,398	24 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
	Debt Reacquisition Premiums1		351		1,890		2,241	213 months
	Deferred Income Taxes1		--		2,086		2,086	asset lives
	Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
	North Dakota Transmission Rider Accrued Revenues2		859		--		859	12 months
	Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
	Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
	South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
	Total Regulatory Assets	$	25,273	$	129,868	$	155,141
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
	Deferred Income Taxes		--		1,550		1,550	asset lives
	North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see note
	Deferred Marked-to-Market Gains		--		257		257	67 months
	Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
	Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
	South Dakota Transmission Rider Accrued Refund		48		--		48	12 months
	South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
	Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
	Net Regulatory Asset  Position	$	24,115	$	52,855	$	76,970
	1Costs subject to recovery without a rate of return.
	2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
		31-Dec-13						Remaining
								Recovery/
	(in thousands)	Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	4,095	$	55,012	$	59,107	see note
	Deferred Marked-to-Market Losses1		3,008		8,674		11,682	60 months
	Conservation Improvement Program Costs and Incentives2		4,945		3,959		8,904	18 months
	Accumulated ARO Accretion/Depreciation Adjustment1		--		4,646		4,646	asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1		558		3,967		4,525	81 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		1,351		1,753		3,104	24 months
	Debt Reacquisition Premiums1		351		2,241		2,592	225 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2		2,331		--		2,331	12 months
	Deferred Income Taxes1		--		1,805		1,805	asset lives
	Big Stone II Unrecovered Project Costs – South Dakota2		101		843		944	113 months
	North Dakota Renewable Resource Rider Accrued Revenues2		--		762		762	15 months
	Recoverable Fuel and Purchased Power Costs1		760		--		760	12 months
	Big Stone II Unrecovered Project Costs – North Dakota1		375		--		375	3 months
	Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see note
	South Dakota Transmission Rider Accrued Revenues2		32		--		32	12 months
	Deferred Holding Company Formation Costs1		27		--		27	6 months
	General Rate Case Recoverable Expenses – South Dakota1		6		--		6	1 month
	Total Regulatory Assets	$	17,940	$	83,730	$	101,670
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	71,454	$	71,454	asset lives
	Deferred Income Taxes		--		1,960		1,960	asset lives
	Minnesota Transmission Rider Accrued Refund		670		--		670	12 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		289		289	see note
North Dakota Renewable Resource Rider Accrued Refund		261		--		261	12 months
North Dakota Transmission Rider Accrued Refund		215		--		215	12 months
Deferred Marked-to-Market Gains		6		117		123	56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		5		106		111	240 months
South Dakota – Nonasset-Based Margin Sharing Excess		38		--		38	12 months
Total Regulatory Liabilities	$	1,195	$	73,926	$	75,121
Net Regulatory Asset Position	$	16,745	$	9,804	$	26,549
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.
All Deferred Marked-to-Market Gains and Losses recorded as of December 31, 2014 are related to forward purchases of energy scheduled for delivery through December 2020.
Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.
The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.
Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.
Minnesota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of December 31, 2014.
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up relates to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-up also includes the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 213 months.
The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740.
North Dakota Transmission 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, 2014.
Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.
North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.
Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the Minnesota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.
Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.
South Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the South Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project and Hoot Lake Plant MATS project, net of amounts billed under the rider.
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of December 31, 2014.
Revenue for Rate Case Expenses Subject to Refund – Minnesota relate to revenues collected under general rates to recover   costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.
Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of the North Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project. The December 31, 2014 liability will be refunded to North Dakota customers through an adjustment to revenue requirements under the North Dakota TCR rider.
South Dakota Transmission Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of December 31, 2014.
South Dakota – Nonasset-Based Margin Sharing Excess represents 25% of OTP’s South Dakota share of actual profit margins on nonasset-based wholesale sales of electricity. The excess margins accumulated annually will be subject to refund through future retail rate adjustments in South Dakota in the following year.
If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases.

Forward_Contracts_Classified_a

Forward Contracts Classified as Derivatives	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Forward Contracts Classified as Derivatives	5. Forward Contracts Classified as Derivatives
	Electricity Contracts
	All of OTP’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. OTP’s objective in entering into forward contracts for the purchase and sale of energy is to meet the energy requirements of its retail customers and to optimize the use of its generating and transmission facilities. OTP’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. Prior to December 2014, OTP also entered into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales. Effective December 31, 2014 OTP discontinued its trading activities not directly associated with serving retail customers.
	Market prices used to value OTP’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties or brokers used by OTP’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange and CME Globex. For certain contracts, prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into Level 3 of the fair value hierarchy set forth in ASC 820.
	Electric operating revenues include wholesale electric sales and net unrealized derivative gains on forward energy contracts, the acquisition and settlement of financial transmission rights and congestion revenue rights options in the MISO and Electric Reliability Council of Texas (ERCOT) markets and daily settlements of virtual transactions in the MISO, ERCOT and California Independent Transmission System Operator markets, broken down as follows for the years ended December 31:
	(in thousands)	2014			2013			2012
	Wholesale Sales - Company-Owned Generation	$	11,160		$	14,846		$	12,951
	Revenue from Settled Contracts at Market Prices		131,952			133,238			160,987
	Market Cost of Settled Contracts		(130,908	)		(132,055	)		(159,500	)
	Net Margins on Settled Contracts at Market		1,044			1,183			1,487
	Marked-to-Market Gains on Settled Contracts		263			3,039			7,864
	Marked-to-Market Losses on Settled Contracts		(276	)		(2,722	)		(7,974	)
	Net Marked-to-Market (Losses) Gains on Settled Contracts		(13	)		317			(110	)
	Unrealized Marked-to-Market Gains on Open Contracts		--			215			284
	Unrealized Marked-to-Market Losses on Open Contracts		(--	)		(100	)		(235	)
	Net Unrealized Marked-to-Market Gains on Open Contracts		--			115			49
	Wholesale Electric Revenue	$	12,191		$	16,461		$	14,377
	The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of December 31, 2014 and December 31, 2013, and the change in the Company’s consolidated balance sheet position from December 31, 2013 to December 31, 2014 and December 31, 2012 to December 31, 2013:
	(in thousands)	31-Dec-14			31-Dec-13
	Other Current Asset – Marked-to-Market Gain	$	257		$	338
	Regulatory Asset – Current Deferred Marked-to-Market Loss		4,492			3,008
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,396			8,674
	Total Assets		14,145			12,020
	Current Liability – Marked-to-Market Loss		(13,888	)		(11,782	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(6	)
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(257	)		(117	)
	Total Liabilities		(14,145	)		(11,905	)
	Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	115
	(in thousands)	Year ended			Year ended
		31-Dec-14			31-Dec-13
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period	$	115		$	49
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
	Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
	Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
	Changes in Fair Value of Contracts Entered into in Current Period		--			115
	Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	115
	OTP has established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at December 31, 2014 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.
	Individual counterparty exposures for certain contracts can be offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of December 31, 2014 and December 31, 2013 are indicated in the following table:
	(in thousands)	31-Dec-14			31-Dec-13
	Derivative Assets Subject to Legally Enforceable Netting Arrangements	$	257		$	400
	Derivative Liabilities Subject to Legally Enforceable Netting Arrangements		(14,230	)		(11,782	)
	Net Balance Subject to Legally Enforceable Netting Arrangements	$	(13,973	)	$	(11,382	)
	The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of December 31, 2014 and December 31, 2013:
	Current Liability – Marked-to-Market Loss  (in thousands)	December 31,			December 31,
		2014			2013
	Loss Contracts Covered by Deposited Funds or Letters of Credit	$	45		$	--
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,888			11,679
	Loss Contracts with No Ratings Triggers or Deposit Requirements		297			103
	Total Current Liability – Marked-to-Market Loss	$	14,230		$	11,782
	1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,888		$	11,679
	Offsetting Gains with Counterparties under Master Netting Agreements		(257	)		(117	)
	Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	13,631		$	11,562

Common_Shares_and_Earnings_Per

Common Shares and Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares and Earnings Per Share	6. Common Shares and Earnings Per Share
	Shelf Registration
	On May 11, 2012 the Company filed a shelf registration statement with the U.S. Securities and Exchange Commission (SEC) under which it 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.
	Common Share Distribution Agreement
	On May 14, 2012 the Company entered into a Distribution Agreement (the Agreement) with J.P. Morgan Securities (JPMS) under which the Company may offer and sell its common shares from time to time through JPMS, as the Company’s distribution agent for the offer and sale of the shares, up to an aggregate sales price of $75 million.
	Under the 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. JPMS will receive from the Company a commission of 2% of the gross sales price per share for any shares sold through it as the Company’s distribution agent under the Agreement.
	The Company is not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement, as amended. In 2014, the Company began selling common shares using its At-the-Market offering program under the Agreement.
	2014 Common Stock Activity
	In 2014, in addition to selling common shares under the At-the-Market offering program, the Company also began issuing shares to meet the requirements of its Automatic Dividend Reinvestment and Share Purchase Plan, Employee Stock Purchase Plan and Employee Stock Ownership Plan, rather than purchasing shares in the open market. Following is a reconciliation of the Company’s common shares outstanding from December 31, 2013 through December 31, 2014:
	Common Shares Outstanding, December 31, 2013			36,271,696
	Issuances:
	At-the-Market Offering			519,636
	Automatic Dividend Reinvestment and Share Purchase Plan:
	Dividends Reinvested			180,818
	Cash Invested			81,533
	Employee Stock Purchase Plan:
	Cash Invested			39,222
	Dividends Reinvested			25,694
	Restricted Stock Issued to Employees			26,700
	Employee Stock Ownership Plan			22,650
	Executive Stock Performance Awards (2011-2013 shares earned)			22,630
	Stock Options Exercised			20,800
	Restricted Stock Issued to Directors			16,800
	Vesting of Restricted Stock Units			14,305
	Directors Deferred Compensation			498
	Retirements:
	Shares Withheld for Individual Income Tax Requirements			(20,554	)
	Forfeiture of Unvested Restricted Stock			(4,375	)
	Common Shares Outstanding, December 31, 2014			37,218,053
	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 1,685,653 were available for issuance as of December 31, 2014. 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. 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, 460,264 were available for purchase as of December 31, 2014. 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, 39,222 common shares were issued in 2014, 43,837 common shares were purchased in the open market in 2013 and 60,439 common shares were purchased in the open market in 2012. 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
	On May 11, 2012 the Company filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares pursuant to the Company’s Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by shareholders, customers or residents of certain states who participate in the Plan to be either new issue common shares or common shares purchased in the open market. In 2014, 288,045 new common shares were issued and 7,480 common shares were purchased in the open market to provide shares for the plan. Common shares purchased in the open market to provide shares for the Plan totaled 284,632 in 2013 and 258,092 in 2012, leaving 661,751 common shares available for issuance under the Plan as of December 31, 2014.
	Earnings Per Share
	The numerator used in the calculation of both basic and diluted earnings per common share is earnings available for common shares with no adjustments in 2014, 2013 or 2012. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting outstanding shares for the following: (1) all potentially dilutive stock options, (2) underlying shares related to nonvested restricted stock units granted to employees, (3) nonvested restricted shares, (4) shares expected to be awarded for stock performance awards granted to executive officers, and (5) shares expected to be issued under the deferred compensation program for directors. Adjustments to the denominator used to calculate diluted earnings per share of 238,162 shares, 203,583 shares and 194,240 shares in 2014, 2013 and 2012, respectively, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in each of the years ended December 31, 2014, 2013 and 2012.
	The following outstanding stock options with exercise prices greater than the average market price of the underlying shares were excluded from the calculation of diluted earnings per share for the years ended December 31, 2014, 2013 and 2012:
	Year	Options Outstanding	Range of Exercise Prices
	2014	--	--
	2013	--	--
	2012	92,497	$24.93 – $27.245

ShareBased_Payments

Share-Based Payments	12 Months Ended
	Dec. 31, 2014
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]
Share-Based Payments	7. Share-Based Payments
	Purchase Plan
	The Purchase Plan allows 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 (ASC 718), the Company is required to record compensation expense related to the 15% discount. The 15% discount resulted in compensation expense of $175,000 in 2014, $143,000 in 2013 and $179,000 in 2012. The 15% discount is not taxable to the employee and is not a deductible expense for tax purposes for the Company.
	Stock Options Granted Under the 1999 Incentive Plan
	The Company has granted 2,041,500 options for the purchase of the Company’s common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan). All of the options granted had vested or were forfeited as of December 31, 2007. 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.
	The following table provides information about options outstanding as of December 31, 2014:
	Exercise Price	Outstanding and	Remaining Contractual Life
		Exercisable as of
		12/31/14
	$24.93	12,750	Expire on April 10, 2015
	Presented below is a summary of the stock options activity:
	Stock Option Activity		2014						2013						2012
			Options			Average			Options			Average			Options			Average
						Exercise						Exercise						Exercise
						Price						Price						Price
	Outstanding, Beginning of Year			34,700		$	25.69			92,497		$	26.59			156,397		$	28.53
	Granted			--			--			--			--			--			--
	Exercised			20,800			26.11			56,109			27.12			--			--
	Forfeited or Expired			1,150			26.495			1,688			27.245			63,900			31.34
	Outstanding, End of Year			12,750			24.93			34,700			25.69			92,497			26.59
	Exercisable, End of Year			12,750			24.93			34,700			25.69			92,497			26.59
	Cash Received for Options Exercised						$543,000						$1,522,000						--
	Intrinsic Value of Options Exercised						89,000						152,000						--
	Fair Value of Options Granted During Year						none granted						none granted						none granted
	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 14, 2014 the Company’s board of directors granted 16,800 shares of restricted stock to the Company’s nonemployee directors. The grant-date fair value of each share of restricted stock granted on April 14, 2014 was $29.41 per share, the average of the high and low market price on the date of grant. The restricted shares granted in 2014 vest 25% per year on April 8 of each year in the period 2015 through 2018 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		2014						2013						2012
			Shares			Weighted			Shares			Weighted			Shares			Weighted
						Average						Average						Average
						Grant-Date						Grant-Date						Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			42,483		$	25.03			56,900		$	21.84			54,250		$	23.26
	Granted			16,800			29.41			17,333			30.77			24,000			21.32
	Vested			21,233			24.11			29,750			21.87			21,350			24.86
	Forfeited			--						2,000			31.03			--
	Nonvested, End of Year			38,050			27.47			42,483			25.03			56,900			21.84
	Compensation Expense Recognized						$416,000						$611,000						$552,000
	Fair Value of Shares Vested in Year						512,000						651,000						531,000
	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. On April 14, 2014 the Company’s board of directors granted 26,700 shares of restricted stock to the Company’s executive officers under the 2014 Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2015 through 2018 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. The grant-date fair value of each share of restricted stock granted in 2014 was $29.41 per share, the average of the high and low market price on the date of grant.
	Presented below is a summary of the status of employees’ restricted stock awards for the years ended December 31:
	Employees’ Restricted Stock Awards		2014						2013						2012
			Shares			Weighted			Shares			Weighted			Shares			Weighted
						Average						Average						Average
						Grant-Date						Grant-Date						Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			48,315		$	25.04			47,645		$	21.82			34,868		$	22.86
	Granted			26,700			29.41			17,000			31.03			26,120			21.48
	Awards Vested			25,360			24.8			16,330			21.89			11,518			24.14
	Forfeited			4,375			28.03			--						1,825			22.2
	Nonvested, End of Year			45,280			27.46			48,315			25.04			47,645			21.82
	Compensation Expense Recognized						$998,000						$427,000						$325,000
	Fair Value of Awards Vested						629,000						358,000						278,000
	Stock-based compensation expense recognized in 2014 for the Company’s restricted stock awards reflects the accelerated recognition of expense for outstanding and unvested restricted stock awards of executives who are, or will be, eligible for retirement, as defined in the restricted stock award agreements, prior to the vesting dates of the awards.
	Restricted Stock Units Granted to Employees
	On April 14, 2014 the Company’s board of directors granted 11,800 restricted stock units to key employees under the 2014 Incentive Plan payable in common shares on April 8, 2018, the date the units vest. The grant-date fair value of each restricted stock unit was $24.95 per share based on the average of the high and low market price of the Company’s common stock on April 14, 2014, discounted for the value of the dividend exclusion over the four-year vesting period.
	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		2014						2013						2012
			Restricted			Weighted			Restricted			Weighted			Restricted			Weighted
			Stock			Average			Stock			Average			Stock			Average
			Units			Grant-Date			Units			Grant-Date			Units			Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			56,180		$	19.79			60,665		$	18.11			73,815		$	20.95
Granted			11,800			24.95			15,150			25.3			15,800			17.66
Reinstated			75			30.81			--						--
Vested			14,305			18.05			17,535			18.73			20,750			27.13
Forfeited			7,850			18.9			2,100			19.88			8,200			19.97
Nonvested, End of Year			45,900			21.82			56,180			19.79			60,665			18.11
Compensation Expense Recognized						$194,000						$275,000						$256,000
Fair Value of Units Converted in Year						258,000						328,000						563,000
Stock Performance Awards granted to Executive Officers
The Compensation Committee of the Company’s board of directors has approved stock performance award agreements 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. 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. The terms of the outstanding awards dictate that these 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.
On April 14, 2014 the Company’s board of directors granted performance share awards to the Company’s executive officers under the 2014 Incentive Plan for the 2014-2016 performance measurement period.
The table below provides a summary of stock performance awards granted and amounts expensed related to the stock performance awards:
Performance			Maximum			Shares Used			Average			Expense Recognized								Shares
Period			Shares Subject			To Estimate			Grant-Date			in the Year Ended December 31,								Awarded
			To Award			Expense			Fair Value
												2014			2013			2012
2014-2016				159,450			106,300		$	22.94		$	1,422,000		$	--		$	--		--
2013-2015				90,600			45,300		$	37.51			458,000			580,000			--		--
2012-2014				148,400			74,200		$	21.75			142,000			1,686,000			1,001,000		89,991
2011-2013				90,600			45,300		$	23.61			--			412,000			254,000		48,730
2010-2012				138,800			69,400		$	20.97			--			--			--		49,500
Total												$	2,022,000		$	2,678,000		$	1,255,000		188,221
Stock-based payment expense recognized in 2014 reflects the accelerated recognition of expense for outstanding and unvested awards of executives who are, or will be, eligible for retirement, as defined in the performance award agreements, prior to the vesting dates of the awards.
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, 6,600 granted in 2012, 3,300 granted in 2011 and 4,000 granted in 2010.
The shares awarded 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 ranking of 21 out of 48 companies in its EEI peer group and a resulting payout at 121.28% of target.
The shares awarded shown in the table above for the 2011-2013 performance period include shares received in 2014 by active participants in the plan on December 31, 2013, based on the Company achieving a ranking of 22 out of 49 companies in its EEI peer group and a resulting payout at 117.86% of target. The shares awarded shown in the table above for the 2011-2013 performance period also include 26,100 shares received by a participant under an executive employment agreement on resignation in 2011.
The Company’s 2010-2012 total shareholder return ranking resulted in no incentive share awards for the Company’s active plan participants for the 2010-2012 performance measurement period. The shares awarded shown in the table above for the 2010-2012 performance periods reflect only shares received under executive employment agreements.
As of December 31, 2014 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 $3.0 million (before income taxes), which will be amortized over a weighted average period of 1.9 years.

Retained_Earnings_and_Dividend

Retained Earnings and Dividend Restriction	12 Months Ended
	Dec. 31, 2014
Retained Earnings Restrictions [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, 2014 the Company was in compliance with the debt 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, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.
	The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity‑to‑total‑capitalization ratio between 45.0% and 55.0%. OTP’s equity to total capitalization ratio including short-term debt was 49.8% as of December 31, 2014. Total capitalization for OTP cannot currently exceed $987 million.

Commitments_and_Contingencies_

Commitments and Contingencies of Continuing Operations	12 Months Ended
	Dec. 31, 2014
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, 2014 OTP had commitments under contracts in connection with construction programs extending into 2018 of approximately $106.6 million.
	Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts
	OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2039. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2015, 2016, 2017 and 2040. 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 $10,165,000, $8,560,000 and $7,951,000 for 2014, 2013 and 2012, respectively.
	The amounts of the Company’s construction program commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases for continuing operations as of December 31, 2014, are as follows:
		Construction Program Commitments		Capacity and Energy Requirements		Coal and Freight Purchase		Operating Leases
	(in thousands)					Commitments		OTP		Nonelectric		Total
	2015	$	48,708	$	34,383	$	49,739	$	1,958	$	5,114	$	7,072
	2016		40,653		22,812		22,943		1,371		4,056		5,427
	2017		17,163		22,123		28,146		978		3,333		4,311
	2018		100		22,729		23,135		990		2,744		3,734
	2019		--		24,532		23,072		1,002		1,223		2,225
	Beyond 2019		--		217,359		598,742		10,824		3,766		14,590
	Total	$	106,624	$	343,938	$	745,777	$	17,123	$	20,236	$	37,359
	Contingencies
	Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $2.0 million.
	On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes. Under the other proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for nonhazardous solid wastes. On December 19, 2014 the EPA announced a final rule following the Subtitle D nonhazardous provisions. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. Therefore, the cost impact of this rule will not be known until those actions are completed.  Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. The EPA is also considering future regulation of coal ash under Subtitle C. Publication of the final rule will open a 90-day window within which petitions for judicial review may be filed in the D.C. Circuit. Challenges by environmental groups are possible and the outcome of such challenges cannot be predicted. Thus, uncertainty regarding the status of this rule is likely to continue for some time.
	Other
	The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2014 will not be material.

ShortTerm_and_LongTerm_Borrowi

Short-Term and Long-Term Borrowings and Preferred Stock Redemption	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Short-Term and Long-Term Borrowings and Preferred Stock Redemption	10. Short-Term and Long-Term Borrowings and Preferred Stock Redemption
	Short-Term Debt
	The following table presents the status of the Company’s lines of credit as of December 31, 2014 and December 31, 2013:
	(in thousands)		Line Limit		In Use on		Restricted due to		Available on		Available on
					December 31,		Outstanding		December 31,		December 31,
					2014		Letters of Credit		2014		2013
	Otter Tail Corporation Credit Agreement		$	150,000	$	10,854	$	274	$	138,872	$	149,341
	OTP Credit Agreement			170,000		--		560		169,440		116,975
	Total		$	320,000	$	10,854	$	834	$	308,312	$	266,316
	Under the Otter Tail Corporation Credit Agreement (as defined below), the maximum amount of debt outstanding in 2014 was $41,348,000 on October 16, 2014 and the average daily balance of debt outstanding during 2014 was $17,868,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2014 was 1.9% compared with 1.9% in 2013. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2014 was $97,000,000 on February 13, 2014 and the average daily balance of debt outstanding during 2014 was $12,815,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2014 was 1.4% compared with 1.4% in 2013. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2014 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 $150 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On November 3, 2014 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2018 to October 29, 2019. 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 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 November 3, 2014 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2018 to October 29, 2019. 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 Retirements, Preferred Stock Redemption and Debt Issuances
	Debt Retirements and Preferred Stock Redemption
	On March 1, 2013 OTP entered into a Credit Agreement (the Loan Agreement) with JPMorgan Chase Bank, N.A. (JPMorgan) providing for a $40.9 million unsecured term loan (the Term Loan) to OTP originally due on June 1, 2014, which was fully drawn on March 1, 2013. The Loan Agreement was amended on October 29, 2013 to extend the due date on the Term Loan to January 15, 2015. Borrowings under the Loan Agreement bore interest at LIBOR plus 0.875%. On March 1, 2013 OTP utilized approximately $25.1 million of Term Loan proceeds to fund the redemption price for all of the 4.65% Grant County, South Dakota Pollution Control Refunding Revenue Bonds and 4.85% Mercer County, North Dakota Pollution Control Refunding Revenue Bonds outstanding on that date, in each case for which OTP paid debt service. All such bonds had been called for redemption in full on March 1, 2013. Also on March 1, 2013, OTP utilized approximately $15.7 million of Term Loan proceeds to satisfy an intercompany note to the Company that had a balance and interest rate designed to equate to the balances and dividend rates of the Company’s cumulative preferred shares. Those cumulative preferred shares were redeemed on March 1, 2013 for $15.7 million, including $0.2 million in call premiums charged to equity and included with preferred dividends paid and as part of the Company’s preferred dividend requirement for the year ended December 31, 2013. On February 27, 2014 OTP used a portion of the proceeds from the issuance of notes under the 2013 Note Purchase Agreement (as defined below) to retire early the Term Loan.
	On November 6 and 25, 2013 the Company purchased, in two separate transactions, $12,933,000 and $34,737,000, respectively, of its outstanding 9.000% notes due 2016 (the 2016 Notes), originally issued in the aggregate principal amount of $100 million. The purchased 2016 Notes (the Purchased 2016 Notes) were subsequently retired and are no longer outstanding. The remaining $52,300,000 principal amount of 2016 Notes outstanding, unless redeemed early or otherwise repaid, will mature and become due and payable on December 15, 2016. The price paid for the Purchased 2016 Notes was $59,404,000, which includes the principal amount of the Purchased 2016 Notes, plus accrued interest of $1,845,000 through the respective purchase dates and a negotiated premium of $9,889,000 (which is less than the premium the Company would have been required to pay to redeem them under the terms of the 2016 Notes). The Company used cash on hand to fund the purchase of the Purchased 2016 Notes. The amount of the debt retired as a result of these transactions is approximately equivalent to the remaining amount of debt that was associated with the operating companies the Company divested over the last two years. On repayment, $363,000 in unamortized debt expense related to the 2016 Notes was immediately recognized as expense along with the $9,889,000 negotiated premium which, in total, reduced diluted earnings per share by $0.17 in 2013.
	On July 13, 2012 the Company prepaid in full its outstanding $50 million, 8.89% Senior Unsecured Note due November 30, 2017 (the Cascade Note) issued pursuant to the Note Purchase Agreement dated as of February 23, 2007, as amended, between the Company and Cascade Investment, L.L.C. (Cascade). Immediately before the prepayment, the Cascade Note bore interest at 8.89% annually. The price paid by the Company to prepay the Cascade Note was $63,031,000, which included the principal amount of the Cascade Note plus accrued interest of $531,000 and a negotiated prepayment premium of $12,500,000. The Company used funds available under the Otter Tail Corporation Credit Agreement for the prepayment. This early retirement reflects the Company’s desire to lower its long-term debt outstanding given its recent divestitures. On repayment, $606,000 in unamortized debt expense related to this note was immediately recognized as expense along with the $12,500,000 negotiated prepayment premium which, in total, reduced diluted earnings per share by $0.22 in 2012.
	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 the Term Loan as discussed above 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, 2012 the Company filed a shelf registration statement with the SEC under which it may offer for sale, from time to time, either separately or together in any combination, equity and/or debt securities described in the shelf registration statement, which expires on May 10, 2015.
	The aggregate amounts of maturities on bonds outstanding and other long‑term obligations at December 31, 2014 for each of the next five years are:
	(in thousands)		2015		2016		2017		2018		2019
	Aggregate Amounts of Debt Maturities		$	201	$	52,544	$	33,228	$	187	$	172
	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, 2014 and December 31, 2013:
	December 31, 2014 (in thousands)		OTP		Otter Tail		Otter Tail
					Corporation		Corporation Consolidated
	Short-Term Debt		$	--	$	10,854	$	10,854
	Long-Term Debt:
	9.000% Notes, due December 15, 2016				$	52,330	$	52,330
	Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		$	33,000				33,000
	Senior Unsecured Notes 4.63%, due December 1, 2021			140,000				140,000
	Senior Unsecured Notes 6.15%, Series B, due August 20, 2022			30,000				30,000
	Senior Unsecured Notes 6.37%, Series C, due August 20, 2027			42,000				42,000
	Senior Unsecured Notes 4.68%, Series A, due February 27, 2029			60,000				60,000
	Senior Unsecured Notes 6.47%, Series D, due August 20, 2037			50,000				50,000
	Senior Unsecured Notes 5.47%, Series B, due February 27, 2044			90,000				90,000
	North Dakota Development Note, 3.95%, due April 1, 2018			--		256		256
	Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021			--		1,105		1,105
	Total		$	445,000	$	53,691	$	498,691
	Less: Current Maturities			--		201		201
	Unamortized Debt Discount			--		1		1
	Total Long-Term Debt		$	445,000	$	53,489	$	498,489
	Total Short-Term and Long-Term Debt (with current maturities)		$	445,000	$	64,544	$	509,544
	December 31, 2013 (in thousands)		OTP		Otter Tail		Otter Tail
					Corporation		Corporation Consolidated
	Short-Term Debt		$	51,195	$	--	$	51,195
	Long-Term Debt:
	Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015		$	40,900			$	40,900
	9.000% Notes, due December 15, 2016				$	52,330		52,330
	Senior Unsecured Notes 5.95%, Series A, due August 20, 2017			33,000				33,000
	Senior Unsecured Notes 4.63%, due December 1, 2021			140,000				140,000
	Senior Unsecured Notes 6.15%, Series B, due August 20, 2022			30,000				30,000
	Senior Unsecured Notes 6.37%, Series C, due August 20, 2027			42,000				42,000
	Senior Unsecured Notes 6.47%, Series D, due August 20, 2037			50,000				50,000
	North Dakota Development Note, 3.95%, due April 1, 2018			--		325		325
	Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021			--		1,223		1,223
	Total		$	335,900	$	53,878	$	389,778
	Less: Current Maturities			--		188		188
Unamortized Debt Discount			--		1		1
Total Long-Term Debt		$	335,900	$	53,689	$	389,589
Total Short-Term and Long-Term Debt (with current maturities)		$	387,095	$	53,877	$	440,972
Financial Covenants
The Company and OTP were in compliance with the financial covenants in their debt agreements as of December 31, 2014.
No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
The Company’s and OTP’s borrowing agreements are subject to certain financial covenants. Specifically:
	●	Under the Otter Tail Corporation Credit 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 Otter Tail Corporation Credit Agreement.
	●	Under the OTP Credit Agreement and the Loan Agreement (when in effect), 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.

Pension_Plan_and_Other_Postret

Pension Plan and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2014
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, 2014, the Company adopted updated and modified mortality tables and an updated and modified mortality improvement scale that reflect longer life expectancies for plan participants. The adoption of the updated and modified mortality tables and mortality improvement scale in 2014 increased 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 2005. Although the adoption of the updated and modified tables and improvement scale will have the effect of increasing 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 January 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.
	Components of net periodic pension benefit cost:
	(in thousands)		2014			2013			2012
	Service Cost–Benefit Earned During the Period		$	4,666		$	5,594		$	5,084
	Interest Cost on Projected Benefit Obligation			13,111			12,123			12,465
	Expected Return on Assets			(16,743	)		(14,521	)		(14,430	)
	Amortization of Prior Service Cost:
	From Regulatory Asset			257			333			398
	From Other Comprehensive Income1			7			9			11
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			3,400			6,600			4,910
	From Other Comprehensive Income1			83			176			131
	Net Periodic Pension Cost		$	4,781		$	10,314		$	8,569
	1Corporate cost included in Other Nonelectric Expenses.
	Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:
			2014			2013			2012
	Discount Rate			5.3	%		4.5	%		5.15	%
	Long-Term Rate of Return on Plan Assets			7.75	%		7.75	%		8	%
	Rate of Increase in Future Compensation Level			3.13	%		3.13	%		3.38	%
	The following table presents amounts recognized in the consolidated balance sheets as of December 31:
	(in thousands)		2014			2013
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	518		$	776
	Unrecognized Actuarial Loss			97,722			56,051
	Total Regulatory Assets		$	98,240		$	56,827
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	21		$	28
	Unrecognized Actuarial Loss			899			448
	Total Accumulated Other Comprehensive Loss		$	920		$	476
	Noncurrent Liability		$	67,061		$	40,422
	Funded status as of December 31:
	(in thousands)		2014			2013
	Accumulated Benefit Obligation		$	(273,903	)	$	(224,365	)
	Projected Benefit Obligation		$	(311,650	)	$	(254,039	)
	Fair Value of Plan Assets			244,589			213,617
	Funded Status		$	(67,061	)	$	(40,422	)
	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, 2014:
	(in thousands)		2014			2013
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	213,617		$	191,018
	Actual Return on Plan Assets			21,874			23,044
	Discretionary Company Contributions			20,000			10,000
	Benefit Payments			(10,902	)		(10,445	)
	Fair Value of Plan Assets at December 31		$	244,589		$	213,617
	Estimated Asset Return			9.6	%		11.8	%
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	254,039		$	275,634
	Service Cost			4,666			5,594
	Interest Cost			13,111			12,123
	Benefit Payments			(10,902	)		(10,445	)
	Actuarial Loss (Gain)			50,736			(28,867	)
	Projected Benefit Obligation at December 31		$	311,650		$	254,039
	Weighted average assumptions used to determine benefit obligations at December 31:
			2014			2013
	Discount Rate			4.35	%		5.3	%
	Rate of Increase in Future Compensation Level			3.13	%		3.13	%
	The assumed rate of return on pension fund assets used for the determination of 2015 net periodic pension cost is 7.75%. 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:	2014	2013
Net Periodic Pension Cost	1-Jan-14	1-Jan-13
End of Year Benefit Obligations	January 1, 2014 projected to December 31, 2014	January 1, 2013 projected to December 31, 2013
Market Value of Assets	31-Dec-14	31-Dec-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 in 2015 are:
(in thousands)		2015
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	189
Amortization of Unrecognized Actuarial Loss			6,529
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			5
Amortization of Unrecognized Actuarial Loss			161
Total Estimated Amortization		$	6,884
Cash flows—The Company had no minimum funding requirement as of December 31, 2014, but made a discretionary plan contribution of $10,000,000 in January 2015.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:
(in thousands)		2015			2016			2017			2018			2019		Years
																2020-2024
		$	11,858		$	12,462		$	13,116		$	13,941		$	14,665	$	85,322
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			>0% 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, 2014 and 2013, by asset category are as follows:
Asset Allocation		2014			2013
Large Capitalization Equity Securities			21	%		21	%
International Equity Securities			18.9	%		21.7	%
Small and Mid-Capitalization Equity Securities			7.9	%		8.5	%
SEI Dynamic Asset Allocation Fund			5.5	%		5.2	%
Equity Securities			53.3	%		56.4	%
Fixed-Income Securities and Cash			42.7	%		39.3	%
Other - SEI Special Situation Collective Investment Trust			4	%		4.3	%
			100	%		100	%
Fair Value Measurements of Pension Fund Assets
ASC 715, Compensation – Retirement Benefits, requires disclosures about pension plan assets identified by the three levels of the fair value hierarchy established by ASC 820-10-35. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.
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 table presents, for each of these hierarchy levels, the Company’s pension fund assets measured at fair value as of December 31, 2014 and 2013:
2014 (in thousands)		Level 1			Level 2			Level 3
Large Capitalization Equity Securities Mutual Fund		$	51,404
International Equity Securities Mutual Funds			46,287
Small and Mid-Capitalization Equity Securities Mutual Fund			19,189
SEI Dynamic Asset Allocation Mutual Fund			13,543
Fixed Income Securities Mutual Funds			104,360
Cash Management – Money Market Fund			5
SEI Special Situation Collective Investment Trust Fund					$	9,801
Total Assets		$	234,788		$	9,801		$	--
2013 (in thousands)
Large Capitalization Equity Securities Mutual Fund		$	44,882
International Equity Securities Mutual Funds			46,412
Small and Mid-Capitalization Equity Securities Mutual Fund			18,151
SEI Dynamic Asset Allocation Mutual Fund			11,159
Fixed Income Securities Mutual Funds			83,843
Cash Management – Money Market Fund			--
SEI Special Situation Collective Investment Trust Fund					$	9,170
Total Assets		$	204,447		$	9,170		$	--
The investments held by the SEI Special Situation Collective Investment Trust on December 31, 2014 and 2013 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 net asset value 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.
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.
Components of net periodic pension benefit cost:
(in thousands)		2014			2013			2012
Service Cost–Benefit Earned During the Period		$	51		$	51		$	45
Interest Cost on Projected Benefit Obligation			1,520			1,408			1,479
Amortization of Prior Service Cost:
From Regulatory Asset			22			22			22
From Other Comprehensive Income1			51			51			51
Amortization of Net Actuarial Loss:
From Regulatory Asset			142			208			175
From Other Comprehensive Income2			46			313			152
Net Periodic Pension Cost		$	1,832		$	2,053		$	1,924
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses		$	20		$	20		$	20
Other Nonelectric Expenses			31			31			31
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses		$	132		$	193		$	162
Other Nonelectric Expenses			(86	)		120			(10	)
Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:
		2014			2013			2012
Discount Rate			5.3	%		4.5	%		5.15	%
Rate of Increase in Future Compensation Level			3.18	%		3.19	%		4.59	%
The following table presents amounts recognized in the consolidated balance sheets as of December 31:
(in thousands)		2014			2013
Regulatory Assets:
Unrecognized Prior Service Cost		$	91		$	113
Unrecognized Actuarial Loss			3,238			1,971
Total Regulatory Assets		$	3,329		$	2,084
Projected Benefit Obligation Liability – Net Amount Recognized		$	(35,650	)	$	(29,321	)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost		$	210		$	261
Unrecognized Actuarial Loss			6,881			2,465
Total Accumulated Other Comprehensive Loss		$	7,091		$	2,726
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, 2014 and a statement of the funded status as of December 31 of both years:
(in thousands)		2014			2013
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1		$	--		$	--
Actual Return on Plan Assets			--			--
Employer Contributions			1,113			1,137
Benefit Payments			(1,113	)		(1,137	)
Fair Value of Plan Assets at December 31		$	--		$	--
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1		$	29,321		$	31,925
Service Cost			51			51
Interest Cost			1,520			1,408
Benefit Payments			(1,113	)		(1,137	)
Plan Amendments			--			--
Actuarial Loss (Gain)			5,871			(2,926	)
Projected Benefit Obligation at December 31		$	35,650		$	29,321
Reconciliation of Funded Status:
Funded Status at December 31		$	(35,650	)	$	(29,321	)
Unrecognized Net Actuarial Loss			10,119			4,436
Unrecognized Prior Service Cost			301			374
Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost		$	(25,230	)	$	(24,511	)
Weighted average assumptions used to determine benefit obligations at December 31:
		2014			2013
Discount Rate			4.35	%		5.3	%
Rate of Increase in Future Compensation Level			3.15	%		3.18	%
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 2015 are:
(in thousands)		2015
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	16
Amortization of Unrecognized Actuarial Loss			334
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			38
Amortization of Unrecognized Actuarial Loss			602
Total Estimated Amortization		$	990
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)		2015			2016			2017			2018			2019		2020-2024
		$	1,178		$	1,399		$	1,376		$	1,423		$	1,516	$	10,904
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. On adoption of Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, in January 1993, the Company elected to recognize its transition obligation related to postretirement benefits earned of approximately $14,964,000 over a period of 20 years. The transition obligation was fully recognized by December 31, 2012. There are no plan assets.
Components of net periodic postretirement benefit cost:
(in thousands)		2014			2013			2012
Service Cost–Benefit Earned During the Period		$	1,055		$	1,421		$	1,544
Interest Cost on Projected Benefit Obligation			2,200			2,050			2,574
Amortization of Transition Obligation
From Regulatory Asset			--			--			729
From Other Comprehensive Income1			--			--			19
Amortization of Prior Service Cost
From Regulatory Asset			205			205			206
From Other Comprehensive Income1			5			5			5
Amortization of Net Actuarial Loss
From Regulatory Asset			--			24			642
From Other Comprehensive Income1			--			1			17
Net Periodic Postretirement Benefit Cost		$	3,465		$	3,706		$	5,736
Effect of Medicare Part D Subsidy		$	(948	)	$	(1,806	)	$	(2,039	)
1Corporate cost included in Other Nonelectric Expenses.
Weighted average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:
		2014			2013			2012
Discount Rate			5.1	%		4.25	%		5.05	%
The following table presents amounts recognized in the consolidated balance sheets as of December 31:
(in thousands)		2014			2013
Regulatory Asset:
Unrecognized Prior Service Cost		$	335		$	540
Unrecognized Net Actuarial Loss (Gain)			7,086			(344	)
Net Regulatory Asset		$	7,421		$	196
Projected Benefit Obligation Liability – Net Amount Recognized		$	(53,638	)	$	(45,221	)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost		$	13		$	18
Unrecognized Net Actuarial Gain			(209	)		(261	)
Accumulated Other Comprehensive Gain		$	(196	)	$	(243	)
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, 2014:
(in thousands)		2014			2013
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1		$	--		$	--
Actual Return on Plan Assets			--			--
Company Contributions			2,320			2,012
Benefit Payments (Net of Medicare Part D Subsidy)			(5,017	)		(4,626	)
Participant Premium Payments			2,697			2,614
Fair Value of Plan Assets at December 31		$	--		$	--
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1		$	45,221		$	58,883
Service Cost (Net of Medicare Part D Subsidy)			1,055			1,421
Interest Cost (Net of Medicare Part D Subsidy)			2,200			2,050
Benefit Payments (Net of Medicare Part D Subsidy)			(5,017	)		(4,626	)
Participant Premium Payments			2,697			2,614
Actuarial Loss (Gain)			7,482			(15,121	)
Projected Benefit Obligation at December 31		$	53,638		$	45,221
Reconciliation of Accrued Postretirement Cost:
Accrued Postretirement Cost at January 1		$	(45,268	)	$	(43,574	)
Expense			(3,465	)		(3,706	)
Net Company Contribution			2,320			2,012
Accrued Postretirement Cost at December 31		$	(46,413	)	$	(45,268	)
Weighted average assumptions used to determine benefit obligations at December 31:
		2014			2013
Discount Rate			4.2	%		5.1	%
Assumed healthcare cost-trend rates as of December 31:
		2014			2013
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65			6.32	%		6.47	%
Healthcare Cost-Trend Rate Assumed for Next Year Post-65			6.63	%		6.82	%
Rate at Which the Cost-Trend Rate is Assumed to Decline			5	%		5	%
Year the Rate Reaches the Ultimate Trend Rate			2025			2025
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 2014 would have the following effects:
(in thousands)		1 Point			1 Point
		Increase			Decrease
Effect on the Postretirement Benefit Obligation		$	7,442		$	(6,088	)
Effect on Total of Service and Interest Cost		$	516		$	(414	)
Effect on Expense		$	516		$	(606	)
Measurement Dates:	2014	2013
Net Periodic Postretirement Benefit Cost	1-Jan-14	1-Jan-13
End of Year Benefit Obligations	January 1, 2014 projected to December 31, 2014	January 1, 2013 projected to December 31, 2013
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 2015 are:
(in thousands)		2015
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	205
Amortization of Unrecognized Actuarial Loss			191
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			5
Amortization of Unrecognized Actuarial Loss			5
Total Estimated Amortization		$	406
Cash flows—The Company expects to contribute $2.6 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2015. The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $456,000 in 2015. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
																Years
(in thousands)		2015			2016			2017			2018			2019		2020-2024
		$	2,638		$	2,762		$	2,925		$	3,086		$	3,247	$	17,281
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 $3,171,000 for 2014, $2,748,000 for 2013 and $2,283,000 for 2012.
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 $696,000 for 2014, $705,000 for 2013 and $735,000 for 2012.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	12. Fair Value of Financial Instruments
	The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
	Cash and Short‑Term Investments—The carrying amount approximates fair value because of the short‑term maturity of those instruments.
	Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of December 31, 2014 and December 31, 2013 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.
	Long‑Term Debt including Current Maturities—The fair value of the Company’s and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.
		31-Dec-14						31-Dec-13
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Cash and Cash Equivalents	$	--		$	--		$	2,007		$	2,007
	Short‑Term Debt		(10,854	)		(10,854	)		(51,195	)		(51,195	)
	Long‑Term Debt including Current Maturities		(498,690	)		(600,828	)		(389,777	)		(427,796	)

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	13. Property, Plant and Equipment
	(in thousands)	December 31,		December 31,
		2014		2013
	Electric Plant in Service
	Production	$	690,024	$	679,067
	Transmission		323,496		270,606
	Distribution		438,489		421,803
	General		93,103		89,408
	Electric Plant in Service		1,545,112		1,460,884
	Construction Work in Progress		240,170		184,780
	Total Gross Electric Plant		1,785,282		1,645,664
	Less Accumulated Depreciation and Amortization		584,956		554,818
	Net Electric Plant	$	1,200,326	$	1,090,846
	Nonelectric Operations Plant
	Equipment	$	135,007	$	131,075
	Buildings and Leasehold Improvements		36,558		36,420
	Land		3,594		3,430
	Nonelectric Operations Plant		175,159		170,925
	Construction Work in Progress		8,507		2,682
	Total Gross Nonelectric Plant		183,666		173,607
	Less Accumulated Depreciation and Amortization		115,462		108,763
	Net Nonelectric Operations Plant	$	68,204	$	64,844
	Net Plant	$	1,268,530	$	1,155,690
	The estimated service lives for rate-regulated properties is 5 to 70 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		34		62
	Transmission Plant		40		55
	Distribution Plant		15		55
	General Plant		5		70
	Nonelectric Fixed Assets:
	Equipment		3		12
	Buildings and Leasehold Improvements		7		40

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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 2014, 2013 and 2012) to net income before total income tax expense for the following reasons:
	(in thousands)	2014			2013			2012
	Tax Computed at Federal Statutory Rate – Continuing Operations	$	25,704		$	21,389		$	18,622
	Increases (Decreases) in Tax from:
	Federal PTCs		(7,517	)		(6,612	)		(6,695	)
	State Income Taxes Net of Federal Income Tax Expense (Benefit)		1,993			1,561			(249	)
	Section 199 Domestic Production Activities Deduction		(1,026	)		--			--
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(849	)		(863	)		(891	)
	Dividend Received/Paid Deduction		(622	)		(632	)		(656	)
	Investment Tax Credit Amortization		(597	)		(597	)		(720	)
	Allowance for Funds Used During Construction - Equity		(505	)		(638	)		(409	)
	Corporate Owned Life Insurance		(354	)		(856	)		(585	)
	Tax Depreciation - Treasury Grant for Wind Farms		(152	)		(304	)		(304	)
	Differences Reversing in Excess of Federal Rates		(106	)		(100	)		(143	)
	Impact of Medicare Part D Change		--			--			(584	)
	Permanent and Other Differences		588			168			(213	)
	Total Income Tax Expense – Continuing Operations	$	16,557		$	12,516		$	7,173
	Income Tax Expense (Benefit) – Discontinued Operations – U.S.		3,952			1,042			(19,707	)
	Income Tax Expense (Benefit) – Continuing and Discontinued Operations	$	20,509		$	13,558		$	(12,534	)
	Overall Effective Federal, State and Foreign Income Tax Rate		26.2	%		21	%		70.4	%
	Income Tax Expense From Continuing Operations Includes the Following:
	Current Federal Income Taxes	$	124		$	146		$	(3,198	)
	Current State Income Taxes		5			37			(361	)
	Deferred Federal Income Taxes		21,044			17,488			15,877
	Deferred State Income Taxes		4,347			2,917			3,161
	Federal PTCs		(7,517	)		(6,612	)		(6,695	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(849	)		(863	)		(891	)
	Investment Tax Credit Amortization		(597	)		(597	)		(720	)
	Total	$	16,557		$	12,516		$	7,173
	Income (Loss) Before Income Taxes – U.S.	$	78,232		$	63,924		$	(13,426	)
	Income (Loss) Before Income Taxes – Foreign (Discontinued Operations)		--			499			(4,381	)
	Total Income (Loss) Before Income Taxes – Continuing and Discontinued Operations	$	78,232		$	64,423		$	(17,807	)
	The Company’s deferred tax assets and liabilities were composed of the following on December 31:
	(in thousands)	2014			2013
	Deferred Tax Assets
	Retirement Benefits Liabilities	$	42,706		$	39,524
	Benefit Liabilities		42,479			39,480
	North Dakota Wind Tax Credits		41,783			42,241
	Federal PTCs		30,189			33,620
	Cost of Removal		29,089			27,926
	Differences Related to Property		10,505			9,462
	Net Operating Loss Carryforward		7,842			15,151
	Vacation Accrual		2,154			1,843
	Investment Tax Credits		1,549			1,960
	Other		1,915			4,045
	Total Deferred Tax Assets	$	210,211		$	215,252
	Deferred Tax Liabilities
	Differences Related to Property	$	(313,959	)	$	(302,852	)
	Retirement Benefits Regulatory Asset		(42,706	)		(39,524	)
	Excess Tax over Book Pension		(12,928	)		(6,977	)
	North Dakota Wind Tax Credits		(11,543	)		(11,543	)
	Impact of State Net Operating Losses on Federal Taxes		(2,745	)		(3,088	)
	Regulatory Asset		(2,087	)		(1,805	)
	Other		(5,571	)		(6,360	)
	Total Deferred Tax Liabilities	$	(391,539	)	$	(372,149	)
	Deferred Income Taxes	$	(181,328	)	$	(156,897	)
	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 13.8% in 2014 compared with 2013. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.
	Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2014:
	(in thousands)	Amount			2015			2016			2017			2024-33
	United States
	Federal Tax Credits	$	31,913		$	--		$	--		$	--	$	31,913
	State Net Operating Losses		5,829			--			--			--		5,829
	State Tax Credits		38,654			2,339			2,339			389		33,587
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 $5.1 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)	2014			2013			2012
Balance on January 1	$	4,239		$	4,436		$	12,138
Increases Related to Tax Positions for Prior Years		120			98			--
Decreases Related to Tax Positions for Prior Years		(4,142	)		(295	)		(6,802	)
Increases Related to Tax Positions for Current Year		5			--			--
Uncertain Positions Resolved During Year		--			--			(900	)
Balance on December 31	$	222		$	4,239		$	4,436
The balance of unrecognized tax benefits as of December 31, 2014 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2014 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, 2014.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of December 31, 2014, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2011. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at December 31, 2014 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014.

Asset_Retirement_Obligations_A

Asset Retirement Obligations (AROs)	12 Months Ended
	Dec. 31, 2014
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.
	OTP recorded no new AROs in 2014.
	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, 2014 and 2013 are presented in the following table:
	(in thousands)	2014		2013
	Asset Retirement Obligations
	Beginning Balance	$	5,661	$	5,207
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		1,582		--
	Accrued Accretion		478		454
	Settlements		--		--
	Ending Balance	$	7,721	$	5,661
	Asset Retirement Costs Capitalized
	Beginning Balance	$	1,477	$	1,477
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		1,582		--
	Settlements		--		--
	Ending Balance	$	3,059	$	1,477
	Accumulated Depreciation - Asset Retirement Costs Capitalized
	Beginning Balance	$	462	$	407
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		--
	Depreciation Expense		65		55
	Settlements		--		--
	Ending Balance	$	527	$	462
	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, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	16. Discontinued Operations
	On December 31, 2014 the Company was in the process of negotiating the sales of Foley and Aevenia, our Construction segment subsidiaries. The Company has entered into signed letters of intent to sell Aevenia and Foley and expects to close on the respective transactions by the end of the first quarter of 2015. These companies’ assets met the criteria to be classified as held for sale on December 31, 2014 and, as such, the companies are being reported as discontinued operations as of December 31, 2014.
	On February 8, 2013 the Company sold substantially all the assets of Shrco, formerly included in the Company’s Manufacturing segment, for approximately $13.0 million in cash and received a working capital true-up of approximately $2.4 million in June 2013. On January 18, 2012 the Company sold the assets of Aviva, a subsidiary of Shrco, for $0.3 million in cash. For discontinued operations reporting, Aviva’s results are included in Shrco’s consolidated results.
	On November 30, 2012 the Company completed the sale of the assets of IMD for total proceeds, net of commissions and selling costs, of $18.1 million. Prior to the sale, IMD was the only remaining entity in the Company’s former Wind Energy segment.
	On February 29, 2012 the Company completed the sale of DMS, its health services company, for $24.0 million in cash net of commissions and selling costs, which was reduced by a $1.7 million working capital settlement paid to the buyer in February 2013. The DMS working capital settlement was estimated to be $1.9 million at the time of the sale. The final settlement resulted in the Company recording a $0.2 million gain on the sale of DMS in the first quarter of 2013. DMS was the only business in the Company’s former Health Services segment.
	On December 29, 2011 the Company completed the sale of Wylie for approximately $25.0 million in cash. Wylie and IMD made up the Company’s former Wind Energy segment.
	On May 6, 2011 the Company completed the sale of IPH for approximately $86.0 million in cash. IPH was the only business in the Company’s former Food Ingredient Processing segment.
	The Company’s Wind Energy, Health Services, Food Ingredient Processing and Construction segments were eliminated as a result of the sales of IMD, DMS and IPH and the classifications of Foley and Aevenia as discontinued operations. The financial position, results of operations, and cash flows of Foley, Aevenia, IMD, Wylie, Shrco, DMS and IPH 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, 2014, 2013 and 2012 and major components of assets and liabilities of discontinued operations as of December 31, 2014 and 2013:
		For the Year Ended December 31, 2014
	(in thousands)	Foley			Aevenia			IMD			Shrco			Intercompany Transactions Adjustment			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
		For the Year Ended December 31, 2013
	(in thousands)	Foley			Aevenia			IMD			Wylie			Shrco			DMS			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	110,097		$	39,813		$	--		$	--		$	2,016		$	--		$	(11	)	$	151,915
	Operating Expenses		109,036			38,257			(988	)		640			2,622			(269	)		(11	)		149,287
	Interest Expense		249			207			--			--			--			--			(452	)		4
	Other Income (Deductions)		4			(5	)		412			--			67			--			(5	)		473
	Income Tax Expense (Benefit)		331			518			370			(256	)		(213	)		108			179			1,037
	Net Income (Loss) from Operations		485			826			1,030			(384	)		(326	)		161			268			2,060
	Gain on Disposition Before Taxes		--			--			--			--			16			200			--			216
	Income Tax Expense on Disposition		--			--			--			--			6			--			--			6
	Net Gain on Disposition		--			--			--			--			10			200			--			210
	Net Income (Loss)	$	485		$	826		$	1,030		$	(384	)	$	(316	)	$	361		$	268		$	2,270
		For the Year Ended December 31, 2012
	(in thousands)	Foley			Aevenia			IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	93,598		$	55,494		$	186,151		$	--		$	32,563		$	16,362		$	--		$	(2,032	)	$	382,136
	Operating Expenses		109,493			51,873			184,462			179			36,163			14,741			--			(2,032	)		394,879
	Asset Impairment Charge		--			--			45,573			--			7,747			--			--			--			53,320
	Interest Expense		689			351			5,787			--			1,553			279			--			(8,482	)		177
	Other Income		--			169			135			--			15			122			--			--			441
	Income Tax (Benefit) Expense		(6,630	)		1,174			(15,792	)		13			(4,021	)		1,734			106			3,393			(20,023	)
	Net (Loss) Income from Operations		(9,954	)		2,265			(33,744	)		(192	)		(8,864	)		(270	)		(106	)		5,089			(45,776	)
	Loss on Disposition Before Taxes		--			--			--			(62	)		--			(5,154	)		--			--			(5,216	)
	Income Tax Expense (Benefit) on Disposition		--			--			--			460			--			(145	)		--			--			315
	Net Loss on Disposition		--			--			--			(522	)		--			(5,009	)		--			--			(5,531	)
	Net (Loss) Income	$	(9,954	)	$	2,265		$	(33,744	)	$	(714	)	$	(8,864	)	$	(5,279	)	$	(106	)	$	5,089		$	(51,307	)
		31-Dec-14
	(in thousands)	Foley			Aevenia			IMD			Shrco			Total
	Current Assets	$	29,897		$	5,277		$	--		$	--		$	35,174
	Goodwill and Intangibles		2,814			--			--			--			2,814
	Net Plant		4,445			6,224			--			--			10,669
	Assets of Discontinued Operations	$	37,156		$	11,501		$	--		$	--		$	48,657
	Current Liabilities	$	17,114		$	2,916		$	1,840		$	994		$	22,864
	Deferred Income Taxes		2,065			2,630			--			--			4,695
	Liabilities of Discontinued Operations	$	19,179		$	5,546		$	1,840		$	994		$	27,559
		31-Dec-13
	(in thousands)	Foley			Aevenia			IMD			Shrco			Total
	Current Assets	$	21,408		$	8,123		$	--		$	38		$	29,569
	Goodwill and Intangibles		8,420			163			--			--			8,583
	Net Plant		5,225			6,101			--			--			11,326
	Assets of Discontinued Operations	$	35,053		$	14,387		$	--		$	38		$	49,478
	Current Liabilities	$	29,766		$	2,499		$	2,196		$	1,441		$	35,902
	Deferred Income Taxes		1,892			1,489			--			--			3,381
	Liabilities of Discontinued Operations	$	31,658		$	3,988		$	2,196		$	1,441		$	39,283
	Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:
	(in thousands)	2014			2013
	Warranty Reserve Balance, Beginning of Year	$	3,087		$	5,027
	Provision for Warranties Issued During the Year		--			188
Less Settlements Made During the Year		(372	)		(715	)
Decrease in Warranty Estimates for Prior Years		(188	)		(1,413	)
Warranty Reserve Balance, End of Year	$	2,527		$	3,087
The warranty reserve balances as of December 31, 2014 and December 31, 2013 relate entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.
Commitments under operating lease obligations for Foley and Aevenia totaled $1.9 million on December 31, 2014.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events
	Stock Incentive Awards
	On February 6, 2015 the Company’s board of directors granted the following stock incentive awards to the Company’s executive officers under the 2014 Stock Incentive Plan:
	Award	Shares/Units Granted		Weighted Average		Vesting
				Grant-Date
				Fair Value
				per Award
	Restricted Stock Units Granted to Executive Officers		20,900	$	31.675	25% per year through February 6, 2019
	Restricted Stock Units Granted to Executive Officer		6,400	$	31.675	100% on February 6, 2020
	Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	31-Dec-17
	The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement or, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.
	Under the performance share awards the aggregate award for performance at target is 77,500 shares. For target performance the Company’s executive officers would earn an aggregate of 51,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2015 through December 31, 2017, 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, 2015 and the average closing price for the 20 trading days immediately preceding January 1, 2018. The Company’s executive officers would also earn an aggregate of 25,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 116,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC 718, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.
	Under the 2015 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event.
	The 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.
	Sale of Aevenia
	On February 24, 2015 the Company entered into an agreement to sell Aevenia for $25 million in cash plus adjustments for working capital and final assets to be determined within 90 days of closing. The sale of Aevenia is subject to certain closing conditions and is expected to close by February 28, 2015.

SCHEDULE_1_CONDENSED_FINANCIAL

SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2014
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)	2014			2013
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	--		$	7,907
	Accounts Receivable from Subsidiaries		4,651			1,736
	Interest Receivable from Subsidiaries		191			192
	Notes Receivable from Subsidiaries		13,553			5,703
	Deferred Income Taxes		13,895			28,853
	Other		1,105			947
	Total Current Assets		33,395			45,338
	Investments in Subsidiaries		605,242			541,291
	Notes Receivable from Subsidiaries		52,060			52,249
	Deferred Income Taxes		36,632			25,861
	Other Assets		27,365			25,456
	Total Assets	$	754,694		$	690,195
	LIABILITIES AND EQUITY
	Current Liabilities
	Accounts Payable to Subsidiaries	$	5,990		$	5,961
	Notes Payable to Subsidiaries		67,218			62,562
	Other		18,371			5,122
	Total Current Liabilities		91,579			73,645
	Other Noncurrent Liabilities		36,860			28,031
	Commitments and Contingencies
	Capitalization
	Long-Term Debt, Net of Current Maturities		53,489			53,689
	Common Shareholder Equity		572,766			534,830
	Total Capitalization		626,255			588,519
	Total Liabilities and Equity	$	754,694		$	690,195
	See accompanying notes to condensed financial statements.
	OTTER TAIL CORPORATION (PARENT COMPANY)
	Condensed Statements of Income--For the Years Ended December 31
	(in thousands)	2014			2013			2012
	Operating Loss
	Revenue	$	--		$	--		$	--
	Operating Expenses		12,593			14,150			15,197
	Operating Loss		(12,593	)		(14,150	)		(15,197	)
	Other Income (Expense)
	Equity Income in Earnings of Subsidiaries		64,926			66,468			8,430
	Loss on Early Retirement of Debt		--			(10,252	)		(13,106	)
	Interest Charges		(6,326	)		(9,940	)		(13,994	)
	Interest Charges to Subsidiaries		(117	)		(494	)		(512	)
	Interest Income from Subsidiaries		4,980			5,318			15,700
	Other Income		1,379			1,413			1,426
	Total Other Income (Expense)		64,842			52,513			(2,056	)
	Income Before Income Taxes – Continuing Operations		52,249			38,363			(17,253	)
	Income Tax Benefit		(5,474	)		(12,502	)		(11,980	)
	Net Income (Loss) from Continuing Operations		57,723			50,865			(5,273	)
	Net Income (Loss) from Discontinued Operations		--			--			--
	Total Net Income (Loss)		57,723			50,865			(5,273	)
	Preferred Dividend Requirement and Other Adjustments		--			513			736
	Income (Loss) Available for Common Shares	$	57,723		$	50,352		$	(6,009	)
	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)	2014			2013			2012
	Cash Flows from Operating Activities
	Net Cash Provided by Operating Activities	$	47,697		$	70,376		$	43,904
	Cash Flows from Investing Activities
	(Investment in Subsidiaries) Return of Capital		(44,000	)		150,381			(137,726	)
	Debt (Issued to) Repaid by Subsidiaries		(7,662	)		(141,919	)		239,452
	Cash Used in Investing Activities		(44	)		(37	)		(69	)
Net Cash (Used in) Provided by Investing Activities		(51,706	)		8,425			101,657
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		215			-			-
Net Short-Term Borrowings		10,854			-			-
Borrowings from Subsidiaries		4,656			-			-
Proceeds from Issuance of Common Stock		26,259			1,821			-
Common Stock Issuance Expenses		(673	)		(3	)		(370	)
Payments for Retirement of Capital Stock		(590	)		(15,723	)		(111	)
Short-Term and Long-Term Debt Issuance Expenses		(170	)		(238	)		(700	)
Payments for Retirement of Long-Term Debt		(188	)		(47,846	)		(50,164	)
Premium Paid for Early Retirement of Long-Term Debt		--			(9,889	)		(12,500	)
Dividends Paid and Other Distributions		(44,261	)		(43,818	)		(43,976	)
Net Cash Used in Financing Activities		(3,898	)		(115,696	)		(107,821	)
Net Change in Cash and Cash Equivalents		(7,907	)		(36,895	)		37,740
Cash and Cash Equivalents at Beginning of Period		7,907			44,802			7,062
Cash and Cash Equivalents at End of Period	$	--		$	7,907		$	44,802
See accompanying notes to condensed financial statements.
Otter Tail Corporation (Parent Company)
Notes to Condensed Financial Statements
For the years ended December 31, 2014, 2013 and 2012
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, 2014:
(in thousands)	Accounts			Interest			Current			Long-Term		Accounts		Current
	Receivable			Receivable			Notes			Notes		Payable		Notes
							Receivable			Receivable				Payable
Otter Tail Power Company	$	3,599		$	--		$	--		$	--	$	42	$	--
Vinyltech Corporation		2			32			--			8,500		--		13,995
Northern Pipe Products, Inc.		--			8			--			3,360		--		9,233
BTD Manufacturing, Inc.		33			107			--			28,500		--		55
IMD, Inc.		--			--			1,602			--		--		--
Shrco, Inc.		--			--			--			--		--		378
T.O. Plastics, Inc.		--			28			--			7,400		--		6,477
Aevenia, Inc.		86			7			--			1,800		--		--
Foley Company		35			9			11,951			2,500		--		6,004
Varistar Corporation		816			--			--			--		5,948		31,076
Otter Tail Assurance Limited		80			--			--			--		--		--
	$	4,651		$	191		$	13,553		$	52,060	$	5,990	$	67,218
As of December 31, 2013:
(in thousands)	Accounts			Interest			Current			Long-Term		Accounts		Current
	Receivable			Receivable			Notes			Notes		Payable		Notes
							Receivable			Receivable				Payable
Otter Tail Power Company	$	1,346		$	--		$	--		$	--	$	11	$	--
Vinyltech Corporation		--			32			--			8,500		--		17,285
Northern Pipe Products, Inc.		--			9			--			3,549		--		11,948
BTD Manufacturing, Inc.		7			107			--			28,500		--		3,985
IMD, Inc.		--			--			1,266			--		--		--
Shrco, Inc.		2			--			3,889			--		--		--
T.O. Plastics, Inc.		--			28			--			7,400		1		4,705
Aevenia, Inc.		--			7			548			1,800		1		--
Foley Company		44			9			--			2,500		--		5,343
Varistar Corporation		--			--			--			--		5,948		19,296
Otter Tail Assurance Limited		337			--			--			--		--		--
	$	1,736		$	192		$	5,703		$	52,249	$	5,961	$	62,562
Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:
(in thousands)	2014			2013			2012
Cash Dividends Paid to Parent by Subsidiaries	$	44,261		$	91,693		$	43,018

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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, (ASC 980).
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 $689,000 in 2014, $1,002,000 in 2013 and $656,000 in 2012. 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 service lives of the properties (5 to 70 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.89% in 2014, 2.96% in 2013 and 2.98% in 2012. 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 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 2014, 2013 or 2012. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
Jointly Owned Facilities	Jointly Owned Facilities
	The consolidated balance sheets include OTP’s ownership interests in the assets and liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Big Stone Plant:
	Electric Plant in Service		$	143,746		$	142,780
	Construction Work in Progress			160,809			94,913
	Accumulated Depreciation			(86,211	)		(83,005	)
	Net Plant		$	218,344		$	154,688
	Coyote Station:
	Electric Plant in Service		$	163,824		$	162,095
	Construction Work in Progress			1,725			303
	Accumulated Depreciation			(99,364	)		(96,907	)
	Net Plant		$	66,185		$	65,491
	OTP is a joint owner, with other regional utilities, in three major transmission lines and two additional major planned transmission line projects with the following ownership interests: 14.8% in the Bemidji-Grand Rapids 230 kV line, approximately 14.1% in the Fargo-Monticello 345 kV line, approximately 4.8% in the Brookings-Southeast Twin Cities Multi-Value Project (MVP) 345 kV line, 50.0% in the Big Stone South to Brookings MVP 345 kV line and 50.0% in the Big Stone South to Ellendale MVP 345 kV line. The following amounts for the jointly-owned transmission facilities are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Electric Plant in Service		$	68,648		$	26,337
	Construction Work in Progress			59,163			71,205
	Accumulated Depreciation			(1,758	)		(837	)
	Net Plant		$	126,053		$	96,705
	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
	In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.
	Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through December 31, 2014 is $21.6 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2014 could be as high as $21.6 million.
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.
	In June 2012, the Company entered into a nonbinding letter of interest with Trinity Industries, Inc. (Trinity) to sell the fixed assets of IMD for $20 million, with the Company retaining IMD’s net working capital—approximately $66 million on June 30, 2012. On September 6, 2012 the Company entered into definitive agreements with Trinity to sell the fixed assets of IMD for $20 million. The agreed on price for the fixed assets was an indicator of the fair value of the assets under level 2 of the ASC fair value hierarchy and an indication of a decrease in the market value of the assets being sold, which were significantly impacted by a decline in market conditions in the wind energy industry. IMD had no tower orders for 2013 due to the expected expiration, at the end of 2012, of the Federal Production Tax Credit (PTC) for investments in renewable energy resources. These factors resulted in IMD recording a fair value adjustment of its long-lived assets to the indicated market price of $20 million and an asset impairment charge of $45.6 million ($27.5 million net-of-tax benefits), or $0.76 per share, in June 2012 broken down as follows:
	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	45,285
	Goodwill			288
	Total Asset Impairment Charges		$	45,573
	The sales of IMD’s fixed assets were completed in 2012 with the effects of the related transactions reflected in discontinued operations in the Company’s 2012 consolidated financial statements. See note 16 to consolidated financial statements for further information.
	Otter Tail Energy Services Company (OTESCO) recorded an asset impairment charge of $0.4 million in 2012 related to wind farm development rights at its Sheridan Ridge and Stutsman County sites in North Dakota based on the fair value of these assets declining to $0 as of March 31, 2012.
	On February 8, 2013 the Company sold substantially all of the assets of Shrco, Inc. (Shrco), the Company’s former waterfront equipment manufacturer, subject to certain closing conditions. The Company recorded a $7.7 million ($4.6 million net-of-tax benefits), or $0.13 per share, asset impairment charge in December 2012 based on the indicated market value of Shrco’s assets broken down as follows:
	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	5,859
	Inventory			782
	Accrued Selling Costs			1,106
	Total Impairment Charges		$	7,747
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, and has recognized in its consolidated financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for uncertain tax positions.
	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 and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 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 (ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.
	For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.
	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.
	OTP’s unrealized gains and losses on forward energy contracts that do not meet the definition of capacity contracts are marked to market and reflected on a net basis in electric revenue on the Company’s consolidated statement of income. Under ASC 815, OTP’s forward energy contracts that do not meet the definition of a capacity contract and are subject to unplanned netting do not qualify for the normal purchase and sales exception from mark-to-market accounting. See note 5 to consolidated financial statements for further discussion.
	Manufacturing operating revenues are recorded when products are shipped.
	The Company’s construction companies, reported under discontinued operations in the accompanying financial statements,   enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. The method used to determine the progress of completion is based on the ratio of costs incurred to total estimated costs on construction projects. See note 16 to consolidated financial statements.
	The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:
			December 31,			December 31,
	(in thousands)		2014			2013
	Costs Incurred on Uncompleted Contracts		$	402,332		$	361,487
	Less Billings to Date			(411,909	)		(377,608	)
	Plus Estimated Earnings Recognized			15,154			6,477
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	5,577		$	(9,644	)
	The following costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings are included in the Company’s consolidated balance sheets under assets of discontinued operations and liabilities of discontinued operations:
		December 31,	December 31,
	(in thousands)	2014	2013
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$     8,133	$     4,063
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(2,556)	(13,707)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$     5,577	$   (9,644)
	The Company has a standard quarterly estimate at completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.
	In 2012, Foley Company (Foley) experienced cost overruns in excess of estimated costs on several large projects. All of these projects were substantially completed as of December 31, 2012. Estimated costs on certain projects in excess of previous period estimates resulted in insignificant pretax charges in 2014 compared with $0.6 million in 2013 and $14.9 million in 2012.
	Plastics operating revenues are recorded when the product is shipped.
Warranty Reserves	Warranty Reserves
	The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The warranty reserve balances as of December 31, 2014 and December 31, 2013 relate entirely to products that were produced by IMD and Shrco prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.
Retainage	Retainage
	Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction subsidiaries that have been retained by customers pending project completion:
			December 31,			December 31,
	(in thousands)		2014			2013
	Accounts Receivable Retained by Customers		$	6,759		$	7,125
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. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, accrued renewable resource, transmission and environmental cost recovery rider revenues, valuations of forward energy contracts, percentage-of-completion, warranty reserves and actuarially determined benefits costs and liabilities. 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, 2014 and 2013:
			December 31,			December 31,
	(in thousands)		2014			2013
	Cost Method:
	Economic Development Loan Pools		$	174		$	219
	Other			129			158
	Equity Method - Affordable Housing and Other Partnerships			265			43
	Marketable Securities Classified as Available-for-Sale			8,014			8,942
	Total Investments		$	8,582		$	9,362
	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, 2014. See further discussion below.
Fair Value Measurements	Fair Value Measurements
	The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).
	Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
	Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
	The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2014 and December 31, 2013:
	December 31, 2014 (in thousands)		Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts		$	--		$	--		$	257
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			120
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company						6,761
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,253
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			593
	Total Assets		$	713		$	8,014		$	257
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts		$	--		$	342		$	--
	Derivative Liabilities - Forward Energy Contracts			--			--			13,888
	Total Liabilities		$	--		$	342		$	13,888
	December 31, 2013 (in thousands)		Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts		$	--		$	--		$	338
	Forward Gasoline Purchase Contracts						62
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			110
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company						7,671
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,271
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			866
	Total Assets		$	976		$	9,004		$	338
	Liabilities:
	Derivative Liabilities - Forward Energy Contracts		$	--		$	103		$	11,679
	Total Liabilities		$	--		$	103		$	11,679
	The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
	Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.
	Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.
	Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
	Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of December 31, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The December 31, 2014 Level 3 forward electric basis spreads ranged from $2.50 to $7.97 per megawatt-hour under the active trading hub price. The weighted average price was $34.95 per megawatt-hour.
	In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of December 31, 2014 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the years ended December 31, 2014 and 2013.
	The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the twelve-month periods ended December 31, 2014 and 2013:
	(in thousands)		2014			2013
	Forward Energy Contracts - Fair Values Beginning of Period		$	(11,341	)	$	(17,782	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods			2,785			7,943
	Changes in Fair Value of Contracts Entered into in Prior Periods			166			(640	)
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period			(8,390	)		(10,479	)
	Net Decrease in Value of Open Contracts Entered into in Current Period			(5,241	)		(862	)
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period		$	(13,631	)	$	(11,341	)
Inventories	Inventories
	The Electric segment inventories are reported at average cost. All other segments’ inventories are stated at the lower of cost (first‑in, first‑out) or market. Inventories consist of the following:
			December 31,			December 31,
	(in thousands)		2014			2013
	Finished Goods		$	27,998		$	20,649
	Work in Process			10,628			9,942
	Raw Material, Fuel and Supplies			46,577			42,036
	Total Inventories		$	85,203		$	72,627
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, measuring its goodwill and indefinite-lived intangible assets for impairment annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine the fair value of the reporting unit.
	In the fourth quarter of 2012 the Company sold Moorhead Electric, Inc. (MEI), a subsidiary company that provided electrical contracting services. In connection with this sale, the Company disposed of $147,000 in goodwill associated with the purchase of MEI in 1992. With the classification of Aevenia in discontinued operations in 2014, the 2012 results of operations and cash flows of MEI are now reflected in discontinued operations.
	In the fourth quarter of 2014 the Company entered into negotiations to sell its wholly owned subsidiary, Foley, a mechanical and prime contractor on industrial projects. As a result of an impairment indicator during the fourth quarter of 2014, the Company recorded a $5.6 million, or $0.15 per share, goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. The goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.
	The following tables summarize changes to goodwill by business segment during 2014 and 2013:
			Gross Balance			Accumulated			Balance				Adjustments		Balance
	(in thousands)		31-Dec-13			Impairments			(net of impairments)				to Goodwill		(net of impairments)
									31-Dec-13				in 2014		31-Dec-14
	Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
	Plastics			19,302			--			19,302				--		19,302
	Total		$	31,488		$	--		$	31,488			$	--	$	31,488
			Gross Balance			Accumulated			Balance				Adjustments		Balance
	(in thousands)		31-Dec-12			Impairments			(net of impairments)				to Goodwill		(net of impairments)
									31-Dec-12				in 2013		31-Dec-13
	Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
	Plastics			19,302			--			19,302				--		19,302
	Total		$	31,488		$	--		$	31,488			$	--	$	31,488
	Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 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:
	2014 (in thousands)		Gross Carrying			Accumulated			Net Carrying			Remaining
			Amount			Amortization			Amount			Amortization
												Periods
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811		$	5,784		$	11,027		60-160 months
	Other Intangible Assets Including Contracts			639			415			224		21 months
	Total		$	17,450		$	6,199		$	11,251
	2013 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811		$	4,935		$	11,876		72-172 months
	Other Intangible Assets Including Contracts			772			420			352		33 months
	Total		$	17,583		$	5,355		$	12,228
	The amortization expense for these intangible assets was:
	(in thousands)		2014			2013			2012
	Amortization Expense – Intangible Assets		$	977		$	977		$	981
	The estimated annual amortization expense for these intangible assets for the next five years is:
	(in thousands)		2015			2016			2017				2018		2019
	Estimated Amortization Expense – Intangible Assets		$	977		$	945		$	849			$	849	$	849
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information
			As of December 31,
	(in thousands)		2014			2013
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1		$	24,526		$	22,951
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2		$	4,594		$	3,264
	1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.
	2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.
	(in thousands)		2014			2013			2012
	Cash Paid (Received) During the Year for:
	Interest (net of amount capitalized)		$	26,364		$	26,789		$	30,741
	Income Taxes		$	145		$	(453	)	$	(353	)
New Accounting Standards	New Accounting Standards
	Accounting Standards Update (ASU) 2013-11
	In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis and transferred $4.3 million of unrecognized tax benefits from other long-term liabilities to long-term deferred income taxes.
	ASU 2014-09
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
	ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Schedule for ownership share of jointly owned facilities	The consolidated balance sheets include OTP’s ownership interests in the assets and liabilities of Big Stone Plant (53.9%) and Coyote Station (35.0%). The following amounts are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Big Stone Plant:
	Electric Plant in Service		$	143,746		$	142,780
	Construction Work in Progress			160,809			94,913
	Accumulated Depreciation			(86,211	)		(83,005	)
	Net Plant		$	218,344		$	154,688
	Coyote Station:
	Electric Plant in Service		$	163,824		$	162,095
	Construction Work in Progress			1,725			303
	Accumulated Depreciation			(99,364	)		(96,907	)
	Net Plant		$	66,185		$	65,491
	OTP is a joint owner, with other regional utilities, in three major transmission lines and two additional major planned transmission line projects with the following ownership interests: 14.8% in the Bemidji-Grand Rapids 230 kV line, approximately 14.1% in the Fargo-Monticello 345 kV line, approximately 4.8% in the Brookings-Southeast Twin Cities Multi-Value Project (MVP) 345 kV line, 50.0% in the Big Stone South to Brookings MVP 345 kV line and 50.0% in the Big Stone South to Ellendale MVP 345 kV line. The following amounts for the jointly-owned transmission facilities are included in the Company’s December 31, 2014 and 2013 consolidated balance sheets:
	(in thousands)		2014			2013
	Electric Plant in Service		$	68,648		$	26,337
	Construction Work in Progress			59,163			71,205
	Accumulated Depreciation			(1,758	)		(837	)
	Net Plant		$	126,053		$	96,705
Schedule of costs incurred and billings and estimated earnings			December 31,			December 31,
	(in thousands)		2014			2013
	Costs Incurred on Uncompleted Contracts		$	402,332		$	361,487
	Less Billings to Date			(411,909	)		(377,608	)
	Plus Estimated Earnings Recognized			15,154			6,477
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	5,577		$	(9,644	)
Schedule of costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings		December 31,	December 31,
	(in thousands)	2014	2013
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$     8,133	$     4,063
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(2,556)	(13,707)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$     5,577	$   (9,644)
Schedule of accounts receivable retained by customers pending project completion			December 31,			December 31,
	(in thousands)		2014			2013
	Accounts Receivable Retained by Customers		$	6,759		$	7,125
Schedule of breakdown of Investments			December 31,			December 31,
	(in thousands)		2014			2013
	Cost Method:
	Economic Development Loan Pools		$	174		$	219
	Other			129			158
	Equity Method - Affordable Housing and Other Partnerships			265			43
	Marketable Securities Classified as Available-for-Sale			8,014			8,942
	Total Investments		$	8,582		$	9,362
Schedule of assets and liabilities that are measured at fair value on a recurring basis	December 31, 2014 (in thousands)		Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts		$	--		$	--		$	257
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			120
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company						6,761
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,253
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			593
	Total Assets		$	713		$	8,014		$	257
	Liabilities:
	Derivative Liabilities - Forward Gasoline Purchase Contracts		$	--		$	342		$	--
	Derivative Liabilities - Forward Energy Contracts			--			--			13,888
	Total Liabilities		$	--		$	342		$	13,888
	December 31, 2013 (in thousands)		Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts		$	--		$	--		$	338
	Forward Gasoline Purchase Contracts						62
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			110
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company						7,671
	U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company						1,271
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			866
	Total Assets		$	976		$	9,004		$	338
	Liabilities:
	Derivative Liabilities - Forward Energy Contracts		$	--		$	103		$	11,679
	Total Liabilities		$	--		$	103		$	11,679
Schedule of derivative asset and liability fair valuations	(in thousands)		2014			2013
	Forward Energy Contracts - Fair Values Beginning of Period		$	(11,341	)	$	(17,782	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods			2,785			7,943
	Changes in Fair Value of Contracts Entered into in Prior Periods			166			(640	)
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period			(8,390	)		(10,479	)
	Net Decrease in Value of Open Contracts Entered into in Current Period			(5,241	)		(862	)
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period		$	(13,631	)	$	(11,341	)
Schedule of inventories			December 31,			December 31,
	(in thousands)		2014			2013
	Finished Goods		$	27,998		$	20,649
	Work in Process			10,628			9,942
	Raw Material, Fuel and Supplies			46,577			42,036
	Total Inventories		$	85,203		$	72,627
Schedule of changes to goodwill by business segment			Gross Balance			Accumulated			Balance				Adjustments		Balance
	(in thousands)		31-Dec-13			Impairments			(net of impairments)				to Goodwill		(net of impairments)
									31-Dec-13				in 2014		31-Dec-14
	Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
	Plastics			19,302			--			19,302				--		19,302
	Total		$	31,488		$	--		$	31,488			$	--	$	31,488
			Gross Balance			Accumulated			Balance				Adjustments		Balance
	(in thousands)		31-Dec-12			Impairments			(net of impairments)				to Goodwill		(net of impairments)
									31-Dec-12				in 2013		31-Dec-13
	Manufacturing		$	12,186		$	--		$	12,186			$	--	$	12,186
	Plastics			19,302			--			19,302				--		19,302
	Total		$	31,488		$	--		$	31,488			$	--	$	31,488
Schedule of components of intangible assets	2014 (in thousands)		Gross Carrying			Accumulated			Net Carrying			Remaining
			Amount			Amortization			Amount			Amortization
												Periods
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811		$	5,784		$	11,027		60-160 months
	Other Intangible Assets Including Contracts			639			415			224		21 months
	Total		$	17,450		$	6,199		$	11,251
	2013 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811		$	4,935		$	11,876		72-172 months
	Other Intangible Assets Including Contracts			772			420			352		33 months
	Total		$	17,583		$	5,355		$	12,228
Schedule of amortization expense for intangible assets	(in thousands)		2014			2013			2012
	Amortization Expense – Intangible Assets		$	977		$	977		$	981
Schedule of estimated annual amortization expense for intangible assets	(in thousands)		2015			2016			2017				2018		2019
	Estimated Amortization Expense – Intangible Assets		$	977		$	945		$	849			$	849	$	849
Schedule of supplemental disclosure of cash flow information			As of December 31,
	(in thousands)		2014			2013
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1		$	24,526		$	22,951
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2		$	4,594		$	3,264
	1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.
	2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.
	(in thousands)		2014			2013			2012
	Cash Paid (Received) During the Year for:
	Interest (net of amount capitalized)		$	26,364		$	26,789		$	30,741
	Income Taxes		$	145		$	(453	)	$	(353	)
IMD, Inc.
Significant Accounting Policies [Line Items]
Schedule of impairment charges	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	45,285
	Goodwill			288
	Total Asset Impairment Charges		$	45,573
Shrco, Inc.
Significant Accounting Policies [Line Items]
Schedule of impairment charges	(in thousands)
	Long-Lived Assets (net of accumulated depreciation)		$	5,859
	Inventory			782
	Accrued Selling Costs			1,106
	Total Impairment Charges		$	7,747

Business_Combinations_Disposit1

Business Combinations, Dispositions and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations, Dispositions and Segment Information [Abstract]
Schedule of percent of consolidated sales revenue by country	Percent of Sales Revenue by Country for the Year Ended December 31:	2014			2013			2012
	United States of America		95.9	%		97.2	%		97.3	%
	Mexico		3	%		1.7	%		1.3	%
	Canada		0.9	%		1	%		1.4	%
	All Other Countries (none greater than 0.05%)		0.2	%		0.1	%		0	%
Schedule of information by business segments	(in thousands)	2014			2013			2012
	Operating Revenue
	Electric	$	407,743		$	373,540		$	350,765
	Manufacturing		219,583			204,997			208,965
	Plastics		172,050			164,957			150,517
	Intersegment Eliminations		(114	)		(80	)		(82	)
	Total	$	799,262		$	743,414		$	710,165
	Cost of Products Sold
	Manufacturing	$	169,033		$	154,235		$	157,437
	Plastics		139,081			129,042			112,662
	Intersegment Eliminations		(45	)		(10	)		(54	)
	Total	$	308,069		$	283,267		$	270,045
	Other Nonelectric Expenses
	Manufacturing	$	23,340		$	18,820		$	18,233
	Plastics		9,292			8,571			8,784
	Corporate		13,418			12,753			13,284
	Intersegment Eliminations		(69	)		(70	)		(28	)
	Total	$	45,981		$	40,074		$	40,273
	Depreciation and Amortization
	Electric	$	44,076		$	43,125		$	42,051
	Manufacturing		10,518			11,194			12,208
	Plastics		3,364			3,350			3,118
	Corporate		116			207			480
	Total	$	58,074		$	57,876		$	57,857
	Operating Income (Loss)
	Electric	$	76,060		$	62,455		$	61,025
	Manufacturing		16,692			20,748			21,087
	Plastics		20,313			23,994			25,953
	Corporate		(13,534	)		(12,960	)		(13,764	)
	Total	$	99,531		$	94,237		$	94,301
	Interest Charges
	Electric	$	23,322		$	17,461		$	19,049
	Manufacturing		3,243			3,255			3,557
	Plastics		1,043			1,001			2,519
	Corporate and Intersegment Eliminations		2,040			5,257			6,778
	Total	$	29,648		$	26,974		$	31,903
	(in thousands)	2014			2013			2012
	Income Tax Expense (Benefit) – Continuing Operations
	Electric	$	11,029		$	9,278		$	5,862
	Manufacturing		4,117			6,047			6,954
	Plastics		7,301			9,249			9,393
	Corporate		(5,890	)		(12,058	)		(15,036	)
	Total	$	16,557		$	12,516		$	7,173
	Earnings (Loss) Available for Common Shares
	Electric	$	43,684		$	38,236		$	38,341
	Manufacturing		9,361			11,457			10,676
	Plastics		12,085			13,809			14,113
	Corporate		(8,247	)		(15,420	)		(17,832	)
	Discontinued Operations		840			2,270			(51,307	)
	Total	$	57,723		$	50,352		$	(6,009	)
	Capital Expenditures
	Electric	$	148,719		$	149,467		$	101,919
	Manufacturing		11,252			7,046			9,311
	Plastics		3,567			3,273			2,819
	Corporate		44			47			137
	Total	$	163,582		$	159,833		$	114,186
	Identifiable Assets
	Electric	$	1,472,647		$	1,290,416		$	1,226,145
	Manufacturing		130,701			119,302			114,933
	Plastics		87,356			76,853			78,855
	Corporate		51,918			59,970			112,616
	Assets of Discontinued Operations		48,657			49,478			69,788
	Total	$	1,791,279		$	1,596,019		$	1,602,337

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of amount of regulatory assets and liabilities		31-Dec-14							Remaining
									Recovery/
	(in thousands)		Current		Long-Term		Total		Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1		$	7,464	$	101,526	$	108,990		see note
	Deferred Marked-to-Market Losses1			4,492		9,396		13,888		72 months
	Conservation Improvement Program Costs and Incentives2			5,843		2,500		8,343		18 months
	Accumulated ARO Accretion/Depreciation Adjustment1			--		5,190		5,190		asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1			592		3,207		3,799		96 months
	Minnesota Transmission Rider Accrued Revenues2			943		2,455		3,398		24 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1			2,585		807		3,392		24 months
	Debt Reacquisition Premiums1			351		1,890		2,241		213 months
	Deferred Income Taxes1			--		2,086		2,086		asset lives
	Recoverable Fuel and Purchased Power Costs1			1,114		--		1,114		12 months
	North Dakota Transmission Rider Accrued Revenues2			859		--		859		12 months
	Big Stone II Unrecovered Project Costs – South Dakota2			100		743		843		101 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2			706		--		706		12 months
	Minnesota Environmental Cost Recovery Rider Accrued Revenues2			186		--		186		12 months
	Minnesota Renewable Resource Rider Accrued Revenues2			--		68		68		see note
	South Dakota Environmental Cost Recovery Rider Accrued Revenues2			38		--		38		12 months
	Total Regulatory Assets		$	25,273	$	129,868	$	155,141
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage		$	--	$	74,237	$	74,237		asset lives
	Deferred Income Taxes			--		1,550		1,550		asset lives
	North Dakota Renewable Resource Rider Accrued Refund			933		85		1,018		15 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota			--		784		784		see note
	Deferred Marked-to-Market Gains			--		257		257		67 months
	Big Stone II Over Recovered Project Costs – North Dakota			147		--		147		12 months
	Deferred Gain on Sale of Utility Property – Minnesota Portion			6		100		106		228 months
	South Dakota Transmission Rider Accrued Refund			48		--		48		12 months
	South Dakota – Nonasset-Based Margin Sharing Excess			24		--		24		12 months
	Total Regulatory Liabilities		$	1,158	$	77,013	$	78,171
	Net Regulatory Asset  Position		$	24,115	$	52,855	$	76,970
	1Costs subject to recovery without a rate of return.
	2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
			31-Dec-13							Remaining
										Recovery/
	(in thousands)		Current		Long-Term		Total			Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1		$	4,095	$	55,012	$	59,107		see note
	Deferred Marked-to-Market Losses1			3,008		8,674		11,682		60 months
	Conservation Improvement Program Costs and Incentives2			4,945		3,959		8,904		18 months
	Accumulated ARO Accretion/Depreciation Adjustment1			--		4,646		4,646		asset lives
	Big Stone II Unrecovered Project Costs – Minnesota1			558		3,967		4,525		81 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1			1,351		1,753		3,104		24 months
	Debt Reacquisition Premiums1			351		2,241		2,592		225 months
	North Dakota Environmental Cost Recovery Rider Accrued Revenues2			2,331		--		2,331		12 months
	Deferred Income Taxes1			--		1,805		1,805		asset lives
	Big Stone II Unrecovered Project Costs – South Dakota2			101		843		944		113 months
	North Dakota Renewable Resource Rider Accrued Revenues2			--		762		762		15 months
	Recoverable Fuel and Purchased Power Costs1			760		--		760		12 months
	Big Stone II Unrecovered Project Costs – North Dakota1			375		--		375		3 months
	Minnesota Renewable Resource Rider Accrued Revenues2			--		68		68		see note
	South Dakota Transmission Rider Accrued Revenues2			32		--		32		12 months
	Deferred Holding Company Formation Costs1			27		--		27		6 months
	General Rate Case Recoverable Expenses – South Dakota1			6		--		6		1 month
	Total Regulatory Assets		$	17,940	$	83,730	$	101,670
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage		$	--	$	71,454	$	71,454		asset lives
	Deferred Income Taxes			--		1,960		1,960		asset lives
	Minnesota Transmission Rider Accrued Refund			670		--		670		12 months
	Revenue for Rate Case Expenses Subject to Refund – Minnesota			--		289		289		see note
	North Dakota Renewable Resource Rider Accrued Refund			261		--		261		12 months
	North Dakota Transmission Rider Accrued Refund			215		--		215		12 months
Deferred Marked-to-Market Gains			6		117		123		56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion			5		106		111		240 months
South Dakota – Nonasset-Based Margin Sharing Excess			38		--		38		12 months
Total Regulatory Liabilities		$	1,195	$	73,926	$	75,121
Net Regulatory Asset Position		$	16,745	$	9,804	$	26,549
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Forward_Contracts_Classified_a1

Forward Contracts Classified as Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of electric wholesale revenues	(in thousands)	2014			2013			2012
	Wholesale Sales - Company-Owned Generation	$	11,160		$	14,846		$	12,951
	Revenue from Settled Contracts at Market Prices		131,952			133,238			160,987
	Market Cost of Settled Contracts		(130,908	)		(132,055	)		(159,500	)
	Net Margins on Settled Contracts at Market		1,044			1,183			1,487
	Marked-to-Market Gains on Settled Contracts		263			3,039			7,864
	Marked-to-Market Losses on Settled Contracts		(276	)		(2,722	)		(7,974	)
	Net Marked-to-Market (Losses) Gains on Settled Contracts		(13	)		317			(110	)
	Unrealized Marked-to-Market Gains on Open Contracts		--			215			284
	Unrealized Marked-to-Market Losses on Open Contracts		(--	)		(100	)		(235	)
	Net Unrealized Marked-to-Market Gains on Open Contracts		--			115			49
	Wholesale Electric Revenue	$	12,191		$	16,461		$	14,377
Schedule for fair value amounts of the company's forward energy contracts classified as derivatives and reconciliation of changes in balance sheet position	(in thousands)	31-Dec-14			31-Dec-13
	Other Current Asset – Marked-to-Market Gain	$	257		$	338
	Regulatory Asset – Current Deferred Marked-to-Market Loss		4,492			3,008
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,396			8,674
	Total Assets		14,145			12,020
	Current Liability – Marked-to-Market Loss		(13,888	)		(11,782	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain		--			(6	)
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(257	)		(117	)
	Total Liabilities		(14,145	)		(11,905	)
	Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	115
	(in thousands)	Year ended			Year ended
		31-Dec-14			31-Dec-13
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period	$	115		$	49
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72	)		(49	)
	Changes in Fair Value of Contracts Entered into in Prior Periods		(43	)		--
	Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--			--
	Changes in Fair Value of Contracts Entered into in Current Period		--			115
	Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--		$	115
Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements	(in thousands)	31-Dec-14			31-Dec-13
	Derivative Assets Subject to Legally Enforceable Netting Arrangements	$	257		$	400
	Derivative Liabilities Subject to Legally Enforceable Netting Arrangements		(14,230	)		(11,782	)
	Net Balance Subject to Legally Enforceable Netting Arrangements	$	(13,973	)	$	(11,382	)
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions	Current Liability – Marked-to-Market Loss  (in thousands)	December 31,			December 31,
		2014			2013
	Loss Contracts Covered by Deposited Funds or Letters of Credit	$	45		$	--
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,888			11,679
	Loss Contracts with No Ratings Triggers or Deposit Requirements		297			103
	Total Current Liability – Marked-to-Market Loss	$	14,230		$	11,782
	1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,888		$	11,679
	Offsetting Gains with Counterparties under Master Netting Agreements		(257	)		(117	)
	Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	13,631		$	11,562

Common_Shares_and_Earnings_Per1

Common Shares and Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Schedule of reconciliation of Company's common shares outstanding	Common Shares Outstanding, December 31, 2013			36,271,696
	Issuances:
	At-the-Market Offering			519,636
	Automatic Dividend Reinvestment and Share Purchase Plan:
	Dividends Reinvested			180,818
	Cash Invested			81,533
	Employee Stock Purchase Plan:
	Cash Invested			39,222
	Dividends Reinvested			25,694
	Restricted Stock Issued to Employees			26,700
	Employee Stock Ownership Plan			22,650
	Executive Stock Performance Awards (2011-2013 shares earned)			22,630
	Stock Options Exercised			20,800
	Restricted Stock Issued to Directors			16,800
	Vesting of Restricted Stock Units			14,305
	Directors Deferred Compensation			498
	Retirements:
	Shares Withheld for Individual Income Tax Requirements			(20,554	)
	Forfeiture of Unvested Restricted Stock			(4,375	)
	Common Shares Outstanding, December 31, 2014			37,218,053
Schedule of outstanding stock options excluded from the calculation of diluted earnings per share	Year	Options Outstanding	Range of Exercise Prices
	2014	--	--
	2013	--	--
	2012	92,497	$24.93 – $27.245

ShareBased_Payments_Tables

Share-Based Payments (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of stock options outstanding	Exercise Price	Outstanding and	Remaining Contractual Life
		Exercisable as of
		12/31/14
	$24.93	12,750	Expire on April 10, 2015
Schedule of stock options activity	Stock Option Activity		2014						2013						2012
			Options			Average			Options			Average			Options			Average
						Exercise						Exercise						Exercise
						Price						Price						Price
	Outstanding, Beginning of Year			34,700		$	25.69			92,497		$	26.59			156,397		$	28.53
	Granted			--			--			--			--			--			--
	Exercised			20,800			26.11			56,109			27.12			--			--
	Forfeited or Expired			1,150			26.495			1,688			27.245			63,900			31.34
	Outstanding, End of Year			12,750			24.93			34,700			25.69			92,497			26.59
	Exercisable, End of Year			12,750			24.93			34,700			25.69			92,497			26.59
	Cash Received for Options Exercised						$543,000						$1,522,000						--
	Intrinsic Value of Options Exercised						89,000						152,000						--
	Fair Value of Options Granted During Year						none granted						none granted						none granted
Schedule of the status of directors' restricted stock awards	Directors’ Restricted Stock Awards		2014						2013						2012
			Shares			Weighted			Shares			Weighted			Shares			Weighted
						Average						Average						Average
						Grant-Date						Grant-Date						Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			42,483		$	25.03			56,900		$	21.84			54,250		$	23.26
	Granted			16,800			29.41			17,333			30.77			24,000			21.32
	Vested			21,233			24.11			29,750			21.87			21,350			24.86
	Forfeited			--						2,000			31.03			--
	Nonvested, End of Year			38,050			27.47			42,483			25.03			56,900			21.84
	Compensation Expense Recognized						$416,000						$611,000						$552,000
	Fair Value of Shares Vested in Year						512,000						651,000						531,000
Schedule of status of employees' restricted stock awards
	Employees’ Restricted Stock Awards		2014						2013						2012
			Shares			Weighted			Shares			Weighted			Shares			Weighted
						Average						Average						Average
						Grant-Date						Grant-Date						Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			48,315		$	25.04			47,645		$	21.82			34,868		$	22.86
	Granted			26,700			29.41			17,000			31.03			26,120			21.48
	Awards Vested			25,360			24.8			16,330			21.89			11,518			24.14
	Forfeited			4,375			28.03			--						1,825			22.2
	Nonvested, End of Year			45,280			27.46			48,315			25.04			47,645			21.82
	Compensation Expense Recognized						$998,000						$427,000						$325,000
	Fair Value of Awards Vested						629,000						358,000						278,000
Schedule of status of employees' restricted stock unit awards
	Employees’ Restricted Stock Unit Awards		2014						2013						2012
			Restricted			Weighted			Restricted			Weighted			Restricted			Weighted
			Stock			Average			Stock			Average			Stock			Average
			Units			Grant-Date			Units			Grant-Date			Units			Grant-Date
						Fair Value						Fair Value						Fair Value
	Nonvested, Beginning of Year			56,180		$	19.79			60,665		$	18.11			73,815		$	20.95
	Granted			11,800			24.95			15,150			25.3			15,800			17.66
	Reinstated			75			30.81			--						--
	Vested			14,305			18.05			17,535			18.73			20,750			27.13
	Forfeited			7,850			18.9			2,100			19.88			8,200			19.97
	Nonvested, End of Year			45,900			21.82			56,180			19.79			60,665			18.11
	Compensation Expense Recognized						$194,000						$275,000						$256,000
	Fair Value of Units Converted in Year						258,000						328,000						563,000
Executive Officers
Schedule of stock performance awards granted and amounts expensed related to the stock performance awards	Performance			Maximum			Shares Used			Average			Expense Recognized								Shares
	Period			Shares Subject			To Estimate			Grant-Date			in the Year Ended December 31,								Awarded
				To Award			Expense			Fair Value
													2014			2013			2012
	2014-2016				159,450			106,300		$	22.94		$	1,422,000		$	--		$	--		--
	2013-2015				90,600			45,300		$	37.51			458,000			580,000			--		--
	2012-2014				148,400			74,200		$	21.75			142,000			1,686,000			1,001,000		89,991
	2011-2013				90,600			45,300		$	23.61			--			412,000			254,000		48,730
	2010-2012				138,800			69,400		$	20.97			--			--			--		49,500
	Total												$	2,022,000		$	2,678,000		$	1,255,000		188,221

Commitments_and_Contingencies_1

Commitments and Contingencies of Continuing Operations (Tables)	12 Months Ended
	Dec. 31, 2014
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 Program Commitments		Capacity and Energy Requirements		Coal and Freight Purchase		Operating Leases
	(in thousands)					Commitments		OTP		Nonelectric		Total
	2015	$	48,708	$	34,383	$	49,739	$	1,958	$	5,114	$	7,072
	2016		40,653		22,812		22,943		1,371		4,056		5,427
	2017		17,163		22,123		28,146		978		3,333		4,311
	2018		100		22,729		23,135		990		2,744		3,734
	2019		--		24,532		23,072		1,002		1,223		2,225
	Beyond 2019		--		217,359		598,742		10,824		3,766		14,590
	Total	$	106,624	$	343,938	$	745,777	$	17,123	$	20,236	$	37,359

ShortTerm_and_LongTerm_Borrowi1

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of lines of credit	(in thousands)	Line Limit		In Use on		Restricted due to		Available on		Available on
				December 31,		Outstanding		December 31,		December 31,
				2014		Letters of Credit		2014		2013
	Otter Tail Corporation Credit Agreement	$	150,000	$	10,854	$	274	$	138,872	$	149,341
	OTP Credit Agreement		170,000		--		560		169,440		116,975
	Total	$	320,000	$	10,854	$	834	$	308,312	$	266,316
Schedule of aggregate amounts of maturities on bonds outstanding and other long-term obligations	(in thousands)	2015		2016		2017		2018		2019
	Aggregate Amounts of Debt Maturities	$	201	$	52,544	$	33,228	$	187	$	172
Schedule of short-term and long-term debt outstanding	December 31, 2014 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation Consolidated
	Short-Term Debt	$	--	$	10,854	$	10,854
	Long-Term Debt:
	9.000% Notes, due December 15, 2016			$	52,330	$	52,330
	Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
	Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
	Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
	Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
	Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
	Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
	Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
	North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
	Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,105		1,105
	Total	$	445,000	$	53,691	$	498,691
	Less: Current Maturities		--		201		201
	Unamortized Debt Discount		--		1		1
	Total Long-Term Debt	$	445,000	$	53,489	$	498,489
	Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544
	December 31, 2013 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation Consolidated
	Short-Term Debt	$	51,195	$	--	$	51,195
	Long-Term Debt:
	Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	$	40,900			$	40,900
	9.000% Notes, due December 15, 2016			$	52,330		52,330
	Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000				33,000
	Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
	Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
	Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
	Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
	North Dakota Development Note, 3.95%, due April 1, 2018		--		325		325
	Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,223		1,223
	Total	$	335,900	$	53,878	$	389,778
	Less: Current Maturities		--		188		188
	Unamortized Debt Discount		--		1		1
	Total Long-Term Debt	$	335,900	$	53,689	$	389,589
	Total Short-Term and Long-Term Debt (with current maturities)	$	387,095	$	53,877	$	440,972

Pension_Plan_and_Other_Postret1

Pension Plan and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Pension Plan
Schedule of components of net periodic benefit cost	(in thousands)		2014			2013			2012
	Service Cost–Benefit Earned During the Period		$	4,666		$	5,594		$	5,084
	Interest Cost on Projected Benefit Obligation			13,111			12,123			12,465
	Expected Return on Assets			(16,743	)		(14,521	)		(14,430	)
	Amortization of Prior Service Cost:
	From Regulatory Asset			257			333			398
	From Other Comprehensive Income1			7			9			11
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			3,400			6,600			4,910
	From Other Comprehensive Income1			83			176			131
	Net Periodic Pension Cost		$	4,781		$	10,314		$	8,569
	1Corporate cost included in Other Nonelectric Expenses.
Schedule of weighted-average assumptions used to determine net periodic benefit cost			2014			2013			2012
	Discount Rate			5.3	%		4.5	%		5.15	%
	Long-Term Rate of Return on Plan Assets			7.75	%		7.75	%		8	%
	Rate of Increase in Future Compensation Level			3.13	%		3.13	%		3.38	%
Schedule of amounts recognized in consolidated balance sheets	(in thousands)		2014			2013
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	518		$	776
	Unrecognized Actuarial Loss			97,722			56,051
	Total Regulatory Assets		$	98,240		$	56,827
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	21		$	28
	Unrecognized Actuarial Loss			899			448
	Total Accumulated Other Comprehensive Loss		$	920		$	476
	Noncurrent Liability		$	67,061		$	40,422
Schedule of funded status	(in thousands)		2014			2013
	Accumulated Benefit Obligation		$	(273,903	)	$	(224,365	)
	Projected Benefit Obligation		$	(311,650	)	$	(254,039	)
	Fair Value of Plan Assets			244,589			213,617
	Funded Status		$	(67,061	)	$	(40,422	)
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	(in thousands)		2014			2013
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	213,617		$	191,018
	Actual Return on Plan Assets			21,874			23,044
	Discretionary Company Contributions			20,000			10,000
	Benefit Payments			(10,902	)		(10,445	)
	Fair Value of Plan Assets at December 31		$	244,589		$	213,617
	Estimated Asset Return			9.6	%		11.8	%
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	254,039		$	275,634
	Service Cost			4,666			5,594
	Interest Cost			13,111			12,123
	Benefit Payments			(10,902	)		(10,445	)
	Actuarial Loss (Gain)			50,736			(28,867	)
	Projected Benefit Obligation at December 31		$	311,650		$	254,039
Schedule of weighted average assumptions used to determine benefit obligations			2014			2013
	Discount Rate			4.35	%		5.3	%
	Rate of Increase in Future Compensation Level			3.13	%		3.13	%
Schedule of measurement dates	Measurement Dates:	2014	2013
	Net Periodic Pension Cost	1-Jan-14	1-Jan-13
	End of Year Benefit Obligations	January 1, 2014 projected to December 31, 2014	January 1, 2013 projected to December 31, 2013
	Market Value of Assets	31-Dec-14	31-Dec-13
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands)		2015
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	189
	Amortization of Unrecognized Actuarial Loss			6,529
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			5
	Amortization of Unrecognized Actuarial Loss			161
	Total Estimated Amortization		$	6,884
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	(in thousands)		2015			2016			2017			2018			2019		Years
																	2020-2024
			$	11,858		$	12,462		$	13,116		$	13,941		$	14,665	$	85,322
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			>0% 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		2014			2013
	Large Capitalization Equity Securities			21	%		21	%
	International Equity Securities			18.9	%		21.7	%
	Small and Mid-Capitalization Equity Securities			7.9	%		8.5	%
	SEI Dynamic Asset Allocation Fund			5.5	%		5.2	%
	Equity Securities			53.3	%		56.4	%
	Fixed-Income Securities and Cash			42.7	%		39.3	%
	Other - SEI Special Situation Collective Investment Trust			4	%		4.3	%
				100	%		100	%
Schedule of pension fund assets measured at fair value	2014 (in thousands)		Level 1			Level 2			Level 3
	Large Capitalization Equity Securities Mutual Fund		$	51,404
	International Equity Securities Mutual Funds			46,287
	Small and Mid-Capitalization Equity Securities Mutual Fund			19,189
	SEI Dynamic Asset Allocation Mutual Fund			13,543
	Fixed Income Securities Mutual Funds			104,360
	Cash Management – Money Market Fund			5
	SEI Special Situation Collective Investment Trust Fund					$	9,801
	Total Assets		$	234,788		$	9,801		$	--
	2013 (in thousands)
	Large Capitalization Equity Securities Mutual Fund		$	44,882
	International Equity Securities Mutual Funds			46,412
	Small and Mid-Capitalization Equity Securities Mutual Fund			18,151
	SEI Dynamic Asset Allocation Mutual Fund			11,159
	Fixed Income Securities Mutual Funds			83,843
	Cash Management – Money Market Fund			--
	SEI Special Situation Collective Investment Trust Fund					$	9,170
	Total Assets		$	204,447		$	9,170		$	--
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Schedule of components of net periodic benefit cost	(in thousands)		2014			2013			2012
	Service Cost–Benefit Earned During the Period		$	51		$	51		$	45
	Interest Cost on Projected Benefit Obligation			1,520			1,408			1,479
	Amortization of Prior Service Cost:
	From Regulatory Asset			22			22			22
	From Other Comprehensive Income1			51			51			51
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			142			208			175
	From Other Comprehensive Income2			46			313			152
	Net Periodic Pension Cost		$	1,832		$	2,053		$	1,924
	1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses		$	20		$	20		$	20
	Other Nonelectric Expenses			31			31			31
	2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses		$	132		$	193		$	162
	Other Nonelectric Expenses			(86	)		120			(10	)
Schedule of weighted-average assumptions used to determine net periodic benefit cost			2014			2013			2012
	Discount Rate			5.3	%		4.5	%		5.15	%
	Rate of Increase in Future Compensation Level			3.18	%		3.19	%		4.59	%
Schedule of amounts recognized in consolidated balance sheets	(in thousands)		2014			2013
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	91		$	113
	Unrecognized Actuarial Loss			3,238			1,971
	Total Regulatory Assets		$	3,329		$	2,084
	Projected Benefit Obligation Liability – Net Amount Recognized		$	(35,650	)	$	(29,321	)
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	210		$	261
	Unrecognized Actuarial Loss			6,881			2,465
	Total Accumulated Other Comprehensive Loss		$	7,091		$	2,726
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	(in thousands)		2014			2013
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	--		$	--
	Actual Return on Plan Assets			--			--
	Employer Contributions			1,113			1,137
	Benefit Payments			(1,113	)		(1,137	)
	Fair Value of Plan Assets at December 31		$	--		$	--
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	29,321		$	31,925
	Service Cost			51			51
	Interest Cost			1,520			1,408
	Benefit Payments			(1,113	)		(1,137	)
	Plan Amendments			--			--
	Actuarial Loss (Gain)			5,871			(2,926	)
	Projected Benefit Obligation at December 31		$	35,650		$	29,321
	Reconciliation of Funded Status:
	Funded Status at December 31		$	(35,650	)	$	(29,321	)
	Unrecognized Net Actuarial Loss			10,119			4,436
	Unrecognized Prior Service Cost			301			374
	Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost		$	(25,230	)	$	(24,511	)
Schedule of weighted average assumptions used to determine benefit obligations			2014			2013
	Discount Rate			4.35	%		5.3	%
	Rate of Increase in Future Compensation Level			3.15	%		3.18	%
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands)		2015
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	16
	Amortization of Unrecognized Actuarial Loss			334
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			38
	Amortization of Unrecognized Actuarial Loss			602
	Total Estimated Amortization		$	990
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets																	Years
	(in thousands)		2015			2016			2017			2018			2019		2020-2024
			$	1,178		$	1,399		$	1,376		$	1,423		$	1,516	$	10,904
Other Postretirement Benefits
Schedule of components of net periodic benefit cost	(in thousands)		2014			2013			2012
	Service Cost–Benefit Earned During the Period		$	1,055		$	1,421		$	1,544
	Interest Cost on Projected Benefit Obligation			2,200			2,050			2,574
	Amortization of Transition Obligation
	From Regulatory Asset			--			--			729
	From Other Comprehensive Income1			--			--			19
	Amortization of Prior Service Cost
	From Regulatory Asset			205			205			206
	From Other Comprehensive Income1			5			5			5
	Amortization of Net Actuarial Loss
	From Regulatory Asset			--			24			642
	From Other Comprehensive Income1			--			1			17
	Net Periodic Postretirement Benefit Cost		$	3,465		$	3,706		$	5,736
	Effect of Medicare Part D Subsidy		$	(948	)	$	(1,806	)	$	(2,039	)
	1Corporate cost included in Other Nonelectric Expenses.
Schedule of weighted-average assumptions used to determine net periodic benefit cost			2014			2013			2012
	Discount Rate			5.1	%		4.25	%		5.05	%
Schedule of amounts recognized in consolidated balance sheets	(in thousands)		2014			2013
	Regulatory Asset:
	Unrecognized Prior Service Cost		$	335		$	540
	Unrecognized Net Actuarial Loss (Gain)			7,086			(344	)
	Net Regulatory Asset		$	7,421		$	196
	Projected Benefit Obligation Liability – Net Amount Recognized		$	(53,638	)	$	(45,221	)
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	13		$	18
	Unrecognized Net Actuarial Gain			(209	)		(261	)
	Accumulated Other Comprehensive Gain		$	(196	)	$	(243	)
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	(in thousands)		2014			2013
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	--		$	--
	Actual Return on Plan Assets			--			--
	Company Contributions			2,320			2,012
	Benefit Payments (Net of Medicare Part D Subsidy)			(5,017	)		(4,626	)
	Participant Premium Payments			2,697			2,614
	Fair Value of Plan Assets at December 31		$	--		$	--
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	45,221		$	58,883
	Service Cost (Net of Medicare Part D Subsidy)			1,055			1,421
	Interest Cost (Net of Medicare Part D Subsidy)			2,200			2,050
	Benefit Payments (Net of Medicare Part D Subsidy)			(5,017	)		(4,626	)
	Participant Premium Payments			2,697			2,614
	Actuarial Loss (Gain)			7,482			(15,121	)
	Projected Benefit Obligation at December 31		$	53,638		$	45,221
	Reconciliation of Accrued Postretirement Cost:
	Accrued Postretirement Cost at January 1		$	(45,268	)	$	(43,574	)
	Expense			(3,465	)		(3,706	)
	Net Company Contribution			2,320			2,012
	Accrued Postretirement Cost at December 31		$	(46,413	)	$	(45,268	)
Schedule of weighted average assumptions used to determine benefit obligations			2014			2013
	Discount Rate			4.2	%		5.1	%
Schedule of healthcare cost-trend rates			2014			2013
	Healthcare Cost-Trend Rate Assumed for Next Year Pre-65			6.32	%		6.47	%
	Healthcare Cost-Trend Rate Assumed for Next Year Post-65			6.63	%		6.82	%
	Rate at Which the Cost-Trend Rate is Assumed to Decline			5	%		5	%
	Year the Rate Reaches the Ultimate Trend Rate			2025			2025
Schedule of effects of one percentage change in assumed healthcare cost-trend rates	(in thousands)		1 Point			1 Point
			Increase			Decrease
	Effect on the Postretirement Benefit Obligation		$	7,442		$	(6,088	)
	Effect on Total of Service and Interest Cost		$	516		$	(414	)
	Effect on Expense		$	516		$	(606	)
Schedule of measurement dates	Measurement Dates:	2014	2013
	Net Periodic Postretirement Benefit Cost	1-Jan-14	1-Jan-13
	End of Year Benefit Obligations	January 1, 2014 projected to December 31, 2014	January 1, 2013 projected to December 31, 2013
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	(in thousands)		2015
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	205
	Amortization of Unrecognized Actuarial Loss			191
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			5
	Amortization of Unrecognized Actuarial Loss			5
	Total Estimated Amortization		$	406
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets																	Years
	(in thousands)		2015			2016			2017			2018			2019		2020-2024
			$	2,638		$	2,762		$	2,925		$	3,086		$	3,247	$	17,281

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of long-term debt including current maturities		31-Dec-14						31-Dec-13
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Cash and Cash Equivalents	$	--		$	--		$	2,007		$	2,007
	Short‑Term Debt		(10,854	)		(10,854	)		(51,195	)		(51,195	)
	Long‑Term Debt including Current Maturities		(498,690	)		(600,828	)		(389,777	)		(427,796	)

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of property, plant and equipment	(in thousands)	December 31,		December 31,
		2014		2013
	Electric Plant in Service
	Production	$	690,024	$	679,067
	Transmission		323,496		270,606
	Distribution		438,489		421,803
	General		93,103		89,408
	Electric Plant in Service		1,545,112		1,460,884
	Construction Work in Progress		240,170		184,780
	Total Gross Electric Plant		1,785,282		1,645,664
	Less Accumulated Depreciation and Amortization		584,956		554,818
	Net Electric Plant	$	1,200,326	$	1,090,846
	Nonelectric Operations Plant
	Equipment	$	135,007	$	131,075
	Buildings and Leasehold Improvements		36,558		36,420
	Land		3,594		3,430
	Nonelectric Operations Plant		175,159		170,925
	Construction Work in Progress		8,507		2,682
	Total Gross Nonelectric Plant		183,666		173,607
	Less Accumulated Depreciation and Amortization		115,462		108,763
	Net Nonelectric Operations Plant	$	68,204	$	64,844
	Net Plant	$	1,268,530	$	1,155,690
Schedule of estimated service lives for properties		Service Life Range
	(years)	Low		High
	Electric Fixed Assets:
	Production Plant		34		62
	Transmission Plant		40		55
	Distribution Plant		15		55
	General Plant		5		70
	Nonelectric Fixed Assets:
	Equipment		3		12
	Buildings and Leasehold Improvements		7		40

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of income from continuing operations before income taxes and income tax expense	(in thousands)	2014			2013			2012
	Tax Computed at Federal Statutory Rate – Continuing Operations	$	25,704		$	21,389		$	18,622
	Increases (Decreases) in Tax from:
	Federal PTCs		(7,517	)		(6,612	)		(6,695	)
	State Income Taxes Net of Federal Income Tax Expense (Benefit)		1,993			1,561			(249	)
	Section 199 Domestic Production Activities Deduction		(1,026	)		--			--
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(849	)		(863	)		(891	)
	Dividend Received/Paid Deduction		(622	)		(632	)		(656	)
	Investment Tax Credit Amortization		(597	)		(597	)		(720	)
	Allowance for Funds Used During Construction - Equity		(505	)		(638	)		(409	)
	Corporate Owned Life Insurance		(354	)		(856	)		(585	)
	Tax Depreciation - Treasury Grant for Wind Farms		(152	)		(304	)		(304	)
	Differences Reversing in Excess of Federal Rates		(106	)		(100	)		(143	)
	Impact of Medicare Part D Change		--			--			(584	)
	Permanent and Other Differences		588			168			(213	)
	Total Income Tax Expense – Continuing Operations	$	16,557		$	12,516		$	7,173
	Income Tax Expense (Benefit) – Discontinued Operations – U.S.		3,952			1,042			(19,707	)
	Income Tax Expense (Benefit) – Continuing and Discontinued Operations	$	20,509		$	13,558		$	(12,534	)
	Overall Effective Federal, State and Foreign Income Tax Rate		26.2	%		21	%		70.4	%
	Income Tax Expense From Continuing Operations Includes the Following:
	Current Federal Income Taxes	$	124		$	146		$	(3,198	)
	Current State Income Taxes		5			37			(361	)
	Deferred Federal Income Taxes		21,044			17,488			15,877
	Deferred State Income Taxes		4,347			2,917			3,161
	Federal PTCs		(7,517	)		(6,612	)		(6,695	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(849	)		(863	)		(891	)
	Investment Tax Credit Amortization		(597	)		(597	)		(720	)
	Total	$	16,557		$	12,516		$	7,173
	Income (Loss) Before Income Taxes – U.S.	$	78,232		$	63,924		$	(13,426	)
	Income (Loss) Before Income Taxes – Foreign (Discontinued Operations)		--			499			(4,381	)
	Total Income (Loss) Before Income Taxes – Continuing and Discontinued Operations	$	78,232		$	64,423		$	(17,807	)
Schedule of deferred tax assets and liabilities	(in thousands)	2014			2013
	Deferred Tax Assets
	Retirement Benefits Liabilities	$	42,706		$	39,524
	Benefit Liabilities		42,479			39,480
	North Dakota Wind Tax Credits		41,783			42,241
	Federal PTCs		30,189			33,620
	Cost of Removal		29,089			27,926
	Differences Related to Property		10,505			9,462
	Net Operating Loss Carryforward		7,842			15,151
	Vacation Accrual		2,154			1,843
	Investment Tax Credits		1,549			1,960
	Other		1,915			4,045
	Total Deferred Tax Assets	$	210,211		$	215,252
	Deferred Tax Liabilities
	Differences Related to Property	$	(313,959	)	$	(302,852	)
	Retirement Benefits Regulatory Asset		(42,706	)		(39,524	)
	Excess Tax over Book Pension		(12,928	)		(6,977	)
	North Dakota Wind Tax Credits		(11,543	)		(11,543	)
	Impact of State Net Operating Losses on Federal Taxes		(2,745	)		(3,088	)
	Regulatory Asset		(2,087	)		(1,805	)
	Other		(5,571	)		(6,360	)
	Total Deferred Tax Liabilities	$	(391,539	)	$	(372,149	)
	Deferred Income Taxes	$	(181,328	)	$	(156,897	)
Schedule of tax credits and tax net operating losses available	(in thousands)	Amount			2015			2016			2017			2024-33
	United States
	Federal Tax Credits	$	31,913		$	--		$	--		$	--	$	31,913
	State Net Operating Losses		5,829			--			--			--		5,829
	State Tax Credits		38,654			2,339			2,339			389		33,587
Schedule of activity related to unrecognized tax benefits	(in thousands)	2014			2013			2012
	Balance on January 1	$	4,239		$	4,436		$	12,138
	Increases Related to Tax Positions for Prior Years		120			98			--
	Decreases Related to Tax Positions for Prior Years		(4,142	)		(295	)		(6,802	)
	Increases Related to Tax Positions for Current Year		5			--			--
	Uncertain Positions Resolved During Year		--			--			(900	)
	Balance on December 31	$	222		$	4,239		$	4,436

Asset_Retirement_Obligations_A1

Asset Retirement Obligations (AROs) (Tables)	12 Months Ended
	Dec. 31, 2014
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)	2014		2013
	Asset Retirement Obligations
	Beginning Balance	$	5,661	$	5,207
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		1,582		--
	Accrued Accretion		478		454
	Settlements		--		--
	Ending Balance	$	7,721	$	5,661
	Asset Retirement Costs Capitalized
	Beginning Balance	$	1,477	$	1,477
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		1,582		--
	Settlements		--		--
	Ending Balance	$	3,059	$	1,477
	Accumulated Depreciation - Asset Retirement Costs Capitalized
	Beginning Balance	$	462	$	407
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		--
	Depreciation Expense		65		55
	Settlements		--		--
	Ending Balance	$	527	$	462
	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, 2014
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations		For the Year Ended December 31, 2014
	(in thousands)	Foley			Aevenia			IMD			Shrco			Intercompany Transactions Adjustment			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
		For the Year Ended December 31, 2013
	(in thousands)	Foley			Aevenia			IMD			Wylie			Shrco			DMS			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	110,097		$	39,813		$	--		$	--		$	2,016		$	--		$	(11	)	$	151,915
	Operating Expenses		109,036			38,257			(988	)		640			2,622			(269	)		(11	)		149,287
	Interest Expense		249			207			--			--			--			--			(452	)		4
	Other Income (Deductions)		4			(5	)		412			--			67			--			(5	)		473
	Income Tax Expense (Benefit)		331			518			370			(256	)		(213	)		108			179			1,037
	Net Income (Loss) from Operations		485			826			1,030			(384	)		(326	)		161			268			2,060
	Gain on Disposition Before Taxes		--			--			--			--			16			200			--			216
	Income Tax Expense on Disposition		--			--			--			--			6			--			--			6
	Net Gain on Disposition		--			--			--			--			10			200			--			210
	Net Income (Loss)	$	485		$	826		$	1,030		$	(384	)	$	(316	)	$	361		$	268		$	2,270
		For the Year Ended December 31, 2012
	(in thousands)	Foley			Aevenia			IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	93,598		$	55,494		$	186,151		$	--		$	32,563		$	16,362		$	--		$	(2,032	)	$	382,136
	Operating Expenses		109,493			51,873			184,462			179			36,163			14,741			--			(2,032	)		394,879
	Asset Impairment Charge		--			--			45,573			--			7,747			--			--			--			53,320
	Interest Expense		689			351			5,787			--			1,553			279			--			(8,482	)		177
	Other Income		--			169			135			--			15			122			--			--			441
	Income Tax (Benefit) Expense		(6,630	)		1,174			(15,792	)		13			(4,021	)		1,734			106			3,393			(20,023	)
	Net (Loss) Income from Operations		(9,954	)		2,265			(33,744	)		(192	)		(8,864	)		(270	)		(106	)		5,089			(45,776	)
	Loss on Disposition Before Taxes		--			--			--			(62	)		--			(5,154	)		--			--			(5,216	)
	Income Tax Expense (Benefit) on Disposition		--			--			--			460			--			(145	)		--			--			315
	Net Loss on Disposition		--			--			--			(522	)		--			(5,009	)		--			--			(5,531	)
	Net (Loss) Income	$	(9,954	)	$	2,265		$	(33,744	)	$	(714	)	$	(8,864	)	$	(5,279	)	$	(106	)	$	5,089		$	(51,307	)
		31-Dec-14
	(in thousands)	Foley			Aevenia			IMD			Shrco			Total
	Current Assets	$	29,897		$	5,277		$	--		$	--		$	35,174
	Goodwill and Intangibles		2,814			--			--			--			2,814
	Net Plant		4,445			6,224			--			--			10,669
	Assets of Discontinued Operations	$	37,156		$	11,501		$	--		$	--		$	48,657
	Current Liabilities	$	17,114		$	2,916		$	1,840		$	994		$	22,864
	Deferred Income Taxes		2,065			2,630			--			--			4,695
	Liabilities of Discontinued Operations	$	19,179		$	5,546		$	1,840		$	994		$	27,559
		31-Dec-13
	(in thousands)	Foley			Aevenia			IMD			Shrco			Total
	Current Assets	$	21,408		$	8,123		$	--		$	38		$	29,569
	Goodwill and Intangibles		8,420			163			--			--			8,583
	Net Plant		5,225			6,101			--			--			11,326
	Assets of Discontinued Operations	$	35,053		$	14,387		$	--		$	38		$	49,478
	Current Liabilities	$	29,766		$	2,499		$	2,196		$	1,441		$	35,902
	Deferred Income Taxes		1,892			1,489			--			--			3,381
	Liabilities of Discontinued Operations	$	31,658		$	3,988		$	2,196		$	1,441		$	39,283
Schedule of warranty reserves	(in thousands)	2014			2013
	Warranty Reserve Balance, Beginning of Year	$	3,087		$	5,027
	Provision for Warranties Issued During the Year		--			188
	Less Settlements Made During the Year		(372	)		(715	)
	Decrease in Warranty Estimates for Prior Years		(188	)		(1,413	)
	Warranty Reserve Balance, End of Year	$	2,527		$	3,087

Subsequent_Events_Tables

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Schedule of stock incentive awards under the 2014 Stock Incentive Plan	Award	Shares/Units Granted		Weighted Average		Vesting
				Grant-Date
				Fair Value
				per Award
	Restricted Stock Units Granted to Executive Officers		20,900	$	31.675	25% per year through February 6, 2019
	Restricted Stock Units Granted to Executive Officer		6,400	$	31.675	100% on February 6, 2020
	Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	31-Dec-17

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - OTP's Ownership Interests in Jointly Owned Facilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Big Stone Plant
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	$143,746	$142,780
Construction Work in Progress	160,809	94,913
Accumulated Depreciation	-86,211	-83,005
Net Plant	218,344	154,688
Coyote Station
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	163,824	162,095
Construction Work in Progress	1,725	303
Accumulated Depreciation	-99,364	-96,907
Net Plant	66,185	65,491
Jointly-owned transmission facilities
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	68,648	26,337
Construction Work in Progress	59,163	71,205
Accumulated Depreciation	-1,758	-837
Net Plant	$126,053	$96,705

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Asset impairment charge of IMD (Details 1) (USD $)	12 Months Ended	1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Jun. 30, 2012
Significant Accounting Policies [Line Items]
Total Asset Impairment Charges	$432
IMD, Inc.
Significant Accounting Policies [Line Items]
Long-Lived Assets (net of accumulated depreciation)		45,285
Goodwill		288
Total Asset Impairment Charges		$45,573

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Asset impairment charge of Shrco (Details 2) (USD $)	12 Months Ended	1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Total Asset Impairment Charges	$432
Shrco, Inc.
Significant Accounting Policies [Line Items]
Long-Lived Assets (net of accumulated depreciation)		5,859
Inventory		782
Accrued Selling Costs		1,106
Total Asset Impairment Charges		$7,747

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$402,332	$361,487
Less Billings to Date	-411,909	-377,608
Plus Estimated Earnings Recognized	15,154	6,477
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$5,577	($9,644)

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Costs and Estimated Earnings in Excess of Billings that are Included in Consolidated Balance Sheets (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$8,133	$4,063
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	-2,556	-13,707
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$5,577	($9,644)

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Accounts Receivable Retained by Customers Pending Project Completion (Details 5) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Accounts Receivable Retained by Customers	$6,759	$7,125

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - Breakdown of Investments (Details 6) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Schedule of Investments [Line Items]
Marketable Securities Classified as Available-for-Sale	$8,014	$8,942
Total Investments	8,582	9,362
Economic Development Loan Pools
Schedule of Investments [Line Items]
Cost Method	174	219
Other
Schedule of Investments [Line Items]
Cost Method	129	158
Affordable Housing and Other Partnerships
Schedule of Investments [Line Items]
Equity Method	$265	$43

Recovered_Sheet1

Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details 7) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Level 1
Assets:
Total Assets	$713	$976
Liabilities:
Derivative Liabilities
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Total Assets
Liabilities:
Derivative Liabilities
Level 1 | Money Market and Mutual Funds
Assets:
Other Current Assets - Nonqualified Retirement Savings Plan	120	110
Other Assets - Nonqualified Retirement Savings Plan	593	866
Level 2
Assets:
Total Assets	8,014	9,004
Liabilities:
Total Liabilities	342	103
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets
Total Assets
Liabilities:
Derivative Liabilities		103
Level 2 | Forward Gasoline Purchase Contracts
Assets:
Derivative Assets		62
Liabilities:
Derivative Liabilities	342
Level 2 | Corporate Debt Securities
Assets:
Investments of Captive Insurance Company	6,761	7,671
Level 2 | U.S. Government-Sponsored Enterprises' Debt Securities
Assets:
Investments of Captive Insurance Company	1,253	1,271
Level 3
Assets:
Total Assets	257	338
Liabilities:
Total Liabilities	13,888	11,679
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	257	338
Liabilities:
Derivative Liabilities	$13,888	$11,679

Recovered_Sheet2

Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 8) (Forward Energy Contracts, Level 3, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Forward Energy Contracts | Level 3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Energy Contracts - Fair Values Beginning of Period	($11,341)	($17,782)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	2,785	7,943
Changes in Fair Value of Contracts Entered into in Prior Periods	166	-640
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	-8,390	-10,479
Net Decrease in Value of Open Contracts Entered into in Current Period	-5,241	-862
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	($13,631)	($11,341)

Recovered_Sheet3

Summary of Significant Accounting Policies - Inventories (Details 9) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Finished Goods	$27,998	$20,649
Work in Process	10,628	9,942
Raw Material, Fuel and Supplies	46,577	42,036
Total Inventories	$85,203	$72,627

Recovered_Sheet4

Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details 10) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Gross Balance		$31,488	$31,488
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments)	31,488	31,488
Adjustments to Goodwill
Balance (net of impairments)	31,488	31,488
Manufacturing
Goodwill [Line Items]
Gross Balance		12,186	12,186
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments)	12,186	12,186
Adjustments to Goodwill
Balance (net of impairments)	12,186	12,186
Plastics
Goodwill [Line Items]
Gross Balance		19,302	19,302
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments)	19,302	19,302
Adjustments to Goodwill
Balance (net of impairments)	$19,302	$19,302

Recovered_Sheet5

Summary of Significant Accounting Policies - Components of Intangible Assets (Details 11) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	17,450	17,583
Amortized Intangible Assets, Accumulated Amortization	6,199	5,355
Amortized Intangible Assets, Net Carrying Amount	11,251	12,228
Customer Relationships
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	16,811	16,811
Amortized Intangible Assets, Accumulated Amortization	5,784	4,935
Amortized Intangible Assets, Net Carrying Amount	11,027	11,876
Customer Relationships | Minimum
Amortizable Intangible Assets:
Amortization Periods	60 months	72 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Amortization Periods	160 months	172 months
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Amortized Intangible Assets, Gross Carrying Amount	639	772
Amortized Intangible Assets, Accumulated Amortization	415	420
Amortized Intangible Assets, Net Carrying Amount	224	352
Amortization Periods	21 months	33 months

Recovered_Sheet6

Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details 12) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$977	$977	$981

Recovered_Sheet7

Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangible Assets (Details 13) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
2015	$977
2016	945
2017	849
2018	849
2019	$849

Recovered_Sheet8

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information of Noncash Investing Activities (Details 14) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$24,526	[1]	$22,951	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$4,594	[2]	$3,264	[2]
[1]	Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.
[2]	Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.

Recovered_Sheet9

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information Of Cash Paid During Year (Details 15) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Paid (Received) During the Year for:
Interest (net of amount capitalized)	$26,364	$26,789	$30,741
Income Taxes	$145	($453)	($353)

Recovered_Sheet10

Summary of Significant Accounting Policies (Detail Textuals) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2012	Sep. 06, 2012	Dec. 31, 2012	Mar. 31, 2012
Significant Accounting Policies [Line Items]
Asset Impairment Charge	$432,000
Big Stone Plant
Significant Accounting Policies [Line Items]
Ownership interests		53.90%
Coyote Station
Significant Accounting Policies [Line Items]
Ownership interests		35.00%
Minimum
Significant Accounting Policies [Line Items]
Product warranty period (in years)		1 year
Maximum
Significant Accounting Policies [Line Items]
Product warranty period (in years)		15 years
Electric Plant
Significant Accounting Policies [Line Items]
Interest capitalized on a plant	656,000	689,000	1,002,000
Provisions for utility depreciation	2.98%	2.89%	2.96%
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		70 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
IMD, Inc.
Significant Accounting Policies [Line Items]
Asset Impairment Charge				45,573,000
Fair value of IMD's long lived assets				20,000,000
Noncash asset impairment charges (in dollars per share)				$0.76
Noncash asset impairment charge (Net of tax benefit)				27,500,000
IMD, Inc. | Nonbinding letter of interest with Trinity Industries, Inc. (Trinity)
Significant Accounting Policies [Line Items]
Nonbinding selling price IMD fixed assets				20,000,000
Working capital net of IMD				66,000,000
IMD, Inc. | Definitive agreements with Trinity Industries, Inc. (Trinity)
Significant Accounting Policies [Line Items]
Selling price of IMD's fixed assets					20,000,000
Otter Tail Energy Services Company
Significant Accounting Policies [Line Items]
Asset Impairment Charge	400,000
Fair value of assets							0
Shrco, Inc.
Significant Accounting Policies [Line Items]
Asset Impairment Charge						7,747,000
Noncash asset impairment charges (in dollars per share)						$0.13
Noncash asset impairment charge (Net of tax benefit)						4,600,000
Otter Tail Power Company | Forward Electricity Contracts | Level 3
Significant Accounting Policies [Line Items]
Electric inputs minimum deviation below active trading hub price per megawatt-hour		2.5
Electric inputs maximum deviation below active trading hub price per megawatt-hour		7.97
Electric inputs weighted average price per megawatt-hour		34.95
Percentage of offset by regulatory liabilities and assets of fuel clause adjustment treatment of fuel costs		100.00%
Net impact of recorded fair valuation gains or losses related to derivative contract		0
Net income impact of future fair valuation adjustments of contracts		0
Otter Tail Power Company | Fargo Project
Significant Accounting Policies [Line Items]
Ownership interests		14.10%
Otter Tail Power Company | Fargo Project | Capacity Expansion 2020
Significant Accounting Policies [Line Items]
Expanded capacity of projects		345
Otter Tail Power Company | Brookings Project
Significant Accounting Policies [Line Items]
Ownership interests		4.80%
Otter Tail Power Company | Brookings Project | Capacity Expansion 2020
Significant Accounting Policies [Line Items]
Expanded capacity of projects		345
Otter Tail Power Company | Bemidji Project
Significant Accounting Policies [Line Items]
Ownership interests		14.80%
Otter Tail Power Company | Bemidji Project | Capacity Expansion 2020
Significant Accounting Policies [Line Items]
Expanded capacity of projects		230
Otter Tail Power Company | Big Stone South - Brookings MVP
Significant Accounting Policies [Line Items]
Ownership interests		50.00%
Otter Tail Power Company | Big Stone South - Brookings MVP | Capacity Expansion 2020
Significant Accounting Policies [Line Items]
Expanded capacity of projects		345
Otter Tail Power Company | Big Stone South - Ellendale MVP
Significant Accounting Policies [Line Items]
Ownership interests		50.00%
Otter Tail Power Company | Big Stone South - Ellendale MVP | Capacity Expansion 2020
Significant Accounting Policies [Line Items]
Expanded capacity of projects		345

Recovered_Sheet11

Summary of Significant Accounting Policies (Detail Textuals 1) (Coyote Creek Mining Company, L.L.C. (CCMC), Lignite Sales Agreement, Otter Tail Power Company, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company
Significant Accounting Policies [Line Items]
Amortization method	straight-line basis
Amortization period	52 months
Percentage of development period costs, development fees and capital charge incurred by CCMC	35.00%
Amount of development period costs, development fees and capital charges incurred by CCMC	$21.60

Recovered_Sheet12

Summary of Significant Accounting Policies (Detail Textuals 2) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Accounting Policies [Line Items]
Asset Impairment Charge	$432,000
Unrecognized tax benefits	4,436,000	222,000	4,239,000	4,436,000	12,138,000
Foley Company
Significant Accounting Policies [Line Items]
Estimated costs on certain projects in excess of previous period estimates, Pretax charge	14,900,000		600,000
Asset Impairment Charge		5,600,000
Goodwill impairment charges per share		$0.15
Moorhead Electric, Inc. (MEI)
Significant Accounting Policies [Line Items]
Disposal of goodwill in connection with sale of MEI				$147,000

Business_Combinations_Disposit2

Business Combinations, Dispositions and Segment Information - Percent of Sales Revenue by Country (Details) (Sales)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
United States Of America
Percentage of sales revenue	95.90%	97.20%	97.30%
Mexico
Percentage of sales revenue	3.00%	1.70%	1.30%
Canada
Percentage of sales revenue	0.90%	1.00%	1.40%
All Other Countries (none greater than 0.05%)
Percentage of sales revenue	0.20%	0.10%	0.00%

Business_Combinations_Disposit3

Business Combinations, Dispositions and Segment Information - Information on Continuing Operations for Business Segments (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating Revenue	$799,262	$743,414	$710,165
Cost of Products Sold	308,069	283,267	270,045
Other Nonelectric Expenses	45,981	40,074	40,273
Depreciation and Amortization	58,074	57,876	57,857
Operating Income (Loss)	99,531	94,237	94,301
Interest Charges	29,648	26,974	31,903
Income Tax Expense (Benefit) - Continuing Operations	16,557	12,516	7,173
Earnings (Loss) Available for Common Shares	57,723	50,352	-6,009
Capital Expenditures	163,582	159,833	114,186
Identifiable Assets	1,791,279	1,596,019	1,602,337
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	-114	-80	-82
Cost of Products Sold	-45	-10	-54
Other Nonelectric Expenses	-69	-70	-28
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	2,040	5,257	6,778
Corporate
Segment Reporting Information [Line Items]
Other Nonelectric Expenses	13,418	12,753	13,284
Depreciation and Amortization	116	207	480
Operating Income (Loss)	-13,534	-12,960	-13,764
Income Tax Expense (Benefit) - Continuing Operations	-5,890	-12,058	-15,036
Earnings (Loss) Available for Common Shares	-8,247	-15,420	-17,832
Capital Expenditures	44	47	137
Identifiable Assets	51,918	59,970	112,616
Discontinued Operations
Segment Reporting Information [Line Items]
Earnings (Loss) Available for Common Shares	840	2,270	-51,307
Identifiable Assets	48,657	49,478	69,788
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	407,743	373,540	350,765
Depreciation and Amortization	44,076	43,125	42,051
Operating Income (Loss)	76,060	62,455	61,025
Interest Charges	23,322	17,461	19,049
Income Tax Expense (Benefit) - Continuing Operations	11,029	9,278	5,862
Earnings (Loss) Available for Common Shares	43,684	38,236	38,341
Capital Expenditures	148,719	149,467	101,919
Identifiable Assets	1,472,647	1,290,416	1,226,145
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	219,583	204,997	208,965
Cost of Products Sold	169,033	154,235	157,437
Other Nonelectric Expenses	23,340	18,820	18,233
Depreciation and Amortization	10,518	11,194	12,208
Operating Income (Loss)	16,692	20,748	21,087
Interest Charges	3,243	3,255	3,557
Income Tax Expense (Benefit) - Continuing Operations	4,117	6,047	6,954
Earnings (Loss) Available for Common Shares	9,361	11,457	10,676
Capital Expenditures	11,252	7,046	9,311
Identifiable Assets	130,701	119,302	114,933
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	172,050	164,957	150,517
Cost of Products Sold	139,081	129,042	112,662
Other Nonelectric Expenses	9,292	8,571	8,784
Depreciation and Amortization	3,364	3,350	3,118
Operating Income (Loss)	20,313	23,994	25,953
Interest Charges	1,043	1,001	2,519
Income Tax Expense (Benefit) - Continuing Operations	7,301	9,249	9,393
Earnings (Loss) Available for Common Shares	12,085	13,809	14,113
Capital Expenditures	3,567	3,273	2,819
Identifiable Assets	$87,356	$76,853	$78,855

Business_Combinations_Disposit4

Business Combinations, Dispositions and Segment Information (Detail Textuals)	12 Months Ended
	Dec. 31, 2014
	Segment
Business Combinations, Dispositions and Segment Information [Abstract]
Number of segments	3

Rate_and_Regulatory_Matters_De

Rate and Regulatory Matters (Detail Textuals) (Otter Tail Power Company)	12 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2011	Jan. 31, 2012	Jan. 01, 2010
	Investor	mi	kV
	Project		mi
Capacity Expansion 2020
Regulatory Matters [Line Items]
Number of investor	11
Number of Major Transmission Line Projects	4
Capacity Expansion 2020 | Big Stone South - Brookings MVP
Regulatory Matters [Line Items]
Expanded capacity of projects	345
Capacity Expansion 2020 | Big Stone South - Ellendale MVP
Regulatory Matters [Line Items]
Expanded capacity of projects	345
Capacity Expansion 2020 | Bemidji Project
Regulatory Matters [Line Items]
Expanded capacity of projects	230
Capacity Expansion 2020 | Brookings Project
Regulatory Matters [Line Items]
Expanded capacity of projects	345
Extended distance of transmission line		250
Capacity Expansion 2020 | Twin Cities La Crosse
Regulatory Matters [Line Items]
Expanded capacity of projects	345
Capacity Expansion 2020 | Fargo Project
Regulatory Matters [Line Items]
Expanded capacity of projects	345
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%	100.00%
Federal Energy Regulatory Commission | Big Stone South - Brookings MVP
Regulatory Matters [Line Items]
Expanded capacity of projects			345
Extended distance of transmission line			70
Federal Energy Regulatory Commission | Big Stone South - Ellendale MVP
Regulatory Matters [Line Items]
Expanded capacity of projects			345
Federal Energy Regulatory Commission | Big Stone South - Ellendale MVP | Minimum
Regulatory Matters [Line Items]
Extended distance of transmission line			160
Federal Energy Regulatory Commission | Big Stone South - Ellendale MVP | Maximum
Regulatory Matters [Line Items]
Extended distance of transmission line			170

Rate_and_Regulatory_Matters_De1

Rate and Regulatory Matters (Detail Textuals 1) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2005	Dec. 31, 2014
	Project
Otter Tail Power Company | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Number of other electric providers entered in agreement for development of project	6
Big Stone AQCS Project BART - compliant AQCS
Regulatory Matters [Line Items]
Current projected cost		$384
Big Stone AQCS Project BART - compliant AQCS | Otter Tail Power Company
Regulatory Matters [Line Items]
Current projected cost		207
Percentage of projected cost		53.90%
Construction expenditures		$153

Rate_and_Regulatory_Matters_De2

Rate and Regulatory Matters (Detail Textuals 2) (USD $)

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

0 Months Ended

Oct. 01, 2011

Dec. 31, 2014

Jan. 31, 2013

Jan. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 30, 2012

Feb. 20, 2013

24-May-12

Jul. 30, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-13

Apr. 25, 2011

Mar. 31, 2013

Apr. 02, 2010

Jan. 11, 2012

Oct. 10, 2013

Sep. 26, 2014

Apr. 01, 2014

Project

Project

Regulatory Matters [Line Items]

Regulatory asset

155,141,000

$101,670,000

Otter Tail Power Company | Minnesota Public Utilities Commission | Big Stone Project

Regulatory Matters [Line Items]

Big Stone II Investment cost incurred, recovery period

60 months

Otter Tail Power Company | Minnesota Public Utilities Commission | Renewable Resource Cost Recovery Rider | Fiscal Year 2016

Regulatory Matters [Line Items]

Percentage of qualifying renewable energy to be supplied in proportion to aggregate energy supplies in Minnesota

17.00%

Otter Tail Power Company | Minnesota Public Utilities Commission | Renewable Resource Cost Recovery Rider | Fiscal Year 2020

Regulatory Matters [Line Items]

Percentage of qualifying renewable energy to be supplied in proportion to aggregate energy supplies in Minnesota

20.00%

Percentage of total electric revenue to be supplied by solar energy as per 2013 legislature

1.50%

Otter Tail Power Company | Minnesota Public Utilities Commission | Renewable Resource Cost Recovery Rider | Fiscal Year 2025

Regulatory Matters [Line Items]

Percentage of qualifying renewable energy to be supplied in proportion to aggregate energy supplies in Minnesota

25.00%

Otter Tail Power Company | Minnesota Public Utilities Commission | Renewable Energy Standards Conservation Renewable Resource Riders Converted At Base Rate

Regulatory Matters [Line Items]

Number of wind farms

3

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

Regulatory Matters [Line Items]

Financial incentives approved

3,500,000

Percentage of conservation cost recovery adjustment

3.80%

3.00%

Financial incentives recognized during period

3,900,000

Conservation improvement programs previous surcharge

3.80%

Revised conservation improvement programs surcharge per kwh

0.00142

Decrease in percentage of customers bill

1.90%

Estimated financial incentive

2,500,000

Decrease in estimation of kilowatt-hours for financial incentives

3,000,000

Regulatory asset

8,200,000

Conservation costs recoverable and incentives earned

7,800,000

9,300,000

7,800,000

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 2012

Regulatory Matters [Line Items]

Financial incentives recognized during period

100,000

2,600,000

Financial incentive filing request

2,700,000

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

Regulatory Matters [Line Items]

Financial incentive filing request

4,000,000

Financial incentive request approved

4,000,000

Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2011

Regulatory Matters [Line Items]

Financial incentives recognized during period

400,000

Financial incentive filing request

2,600,000

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

Regulatory Matters [Line Items]

Lower Estimated Incentives

0.09

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

Regulatory Matters [Line Items]

Lower Estimated Incentives

0.07

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

Regulatory Matters [Line Items]

Regulatory asset

3,400,000

Number of additional transmission related projects

12

Number of additional projects approved

3

Amount of recognized revenue for amounts eligible for recovery

6,300,000

2,900,000

2,400,000

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

Regulatory Matters [Line Items]

Regulatory asset

200,000

Amount of recognized revenue for amounts eligible for recovery

6,900,000

Annual revenue requirement

9,800,000

6,100,000

10,200,000

Annual increase in revenue requirement

4,100,000

Otter Tail Power Company | Minnesota Public Utilities Commission | Big Stone II Project Cost Recovery

Regulatory Matters [Line Items]

Recoverable amount of generation costs

3,200,000

Present value of recoverable amount of generation costs

2,800,000

Project transmission related costs

3,200,000

Regulators jurisdictional share of Big Stone II transmission costs transferred

400,000

Recoverable amount of deferred costs

3,500,000

Discounted present value of recoverable deferred costs

300,000

700,000

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

Regulatory Matters [Line Items]

General rate revenue increase approved

$5,000,000

Percentage of increase in base rate revenue approved by rate authority

1.60%

Number of transmission lines approved for transfer of investments from rider recovery to base rate recovery

2

Big Stone II Investment cost incurred, recovery period

5 years

5 years

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

8.33%

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

8.61%

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

10.43%

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

10.74%

Rate_and_Regulatory_Matters_De3

Rate and Regulatory Matters (Detail Textuals 3) (USD $)	1 Months Ended	0 Months Ended	12 Months Ended				1 Months Ended
	Jun. 25, 2010	Mar. 12, 2014	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012	Aug. 31, 2012	Mar. 31, 2014	Jul. 30, 2013	Nov. 25, 2009
							Project
Regulatory Matters [Line Items]
Regulatory Liabilities			$78,171,000	$75,121,000
Regulatory asset			155,141,000	101,670,000
Otter Tail Power Company | North Dakota Public Service Commission | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Regulatory Liabilities			100,000
Project transmission related costs	2,600,000
Big Stone II generation costs	10,100,000
Regulators jurisdictional share of transmission costs	1,100,000
Regulators jurisdictional share of Big Stone II transmission costs transferred	300,000
Regulators jurisdictional share	4,100,000
Public utilities, allowance for funds used during construction, rate	7.65%
Big Stone II Investment cost incurred, recovery period	36 months
Recoverable amount of generation costs	4,300,000
Present value of recoverable amount of generation costs	3,900,000
Carrying charge of Big Stone II generation cost including in total recovery amount	300,000
Transmission cost plus accrued AFUDC									1,000,000
Otter Tail Power Company | North Dakota Public Service Commission | Renewable Resource Cost Recovery Rider
Regulatory Matters [Line Items]
Expected cost recovery from customers					9,900,000
Percentage of reduction in the NDRRA		13.50%
Regulatory Liabilities			1,000,000
Amount of recognized revenue for amounts eligible for recovery			7,500,000	8,600,000		9,300,000
Otter Tail Power Company | North Dakota Public Service Commission | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Amount of recognized revenue for amounts eligible for recovery			5,800,000	3,200,000		1,400,000
Number of additional transmission related projects							10
Regulatory asset			900,000
Abandoned plant costs			100,000
Otter Tail Power Company | North Dakota Public Service Commission | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Amount of recognized revenue for amounts eligible for recovery			5,900,000	2,300,000
Regulatory asset			700,000
Otter Tail Power Company | North Dakota Public Service Commission | Environmental Cost Recovery Rider | Minimum
Regulatory Matters [Line Items]
Percentage of ECR rider rate								4.32%
Otter Tail Power Company | North Dakota Public Service Commission | Environmental Cost Recovery Rider | Maximum
Regulatory Matters [Line Items]
Percentage of ECR rider rate								7.53%
Otter Tail Power Company | North Dakota Public Service Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved										$3,600,000
Percentage of increase in base rate revenue approved by MPUC										3.00%

Rate_and_Regulatory_Matters_De4

Rate and Regulatory Matters (Detail Textuals 4) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended			1 Months Ended	0 Months Ended
	31-May-13	Aug. 20, 2010	Mar. 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 21, 2011	Nov. 06, 2014	Nov. 12, 2013	Jan. 31, 2012	Jan. 01, 2010
Regulatory Matters [Line Items]
Regulatory asset				$155,141,000	$101,670,000
Regulatory Liabilities				78,171,000	75,121,000
Otter Tail Power Company | South Dakota Public Utilities Commission | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Big Stone II Investment cost incurred, recovery period			10 years
Recovery of Big Stone II generation development costs approved			1,000,000
Recovery period of Big Stone II development costs		5 years
Jurisdictional portion of unrecovered transmission costs and AFUDC transferred	200,000
Otter Tail Power Company | South Dakota Public Utilities Commission | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Regulatory Liabilities				100,000
Amount of recognized revenue for amounts eligible for recovery				1,200,000	800,000	400,000
Otter Tail Power Company | South Dakota Public Utilities Commission | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Regulatory asset				100,000
Amount of recognized revenue for amounts eligible for recovery				200,000
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved							643,000
Percentage of increase in base rate revenue approved by MPUC							2.32%
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Public utilities, allowance for funds used during construction, rate							8.50%
Otter Tail Power Company | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate										100.00%	100.00%
Proposed reduced return on equity used in transmission rates									9.15%
Current return on equity used in transmission rates									12.38%
Additional Incentive Basis Point								50-basis points

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	$25,273		$17,940
Regulatory Liabilities - Current	1,158		1,195
Net Regulatory Assets - Current	24,115		16,745
Regulatory Assets - Long-Term	129,868		83,730
Regulatory Liabilities - Long-Term	77,013		73,926
Net Regulatory Assets - Long-Term	52,855		9,804
Regulatory Assets - Total	155,141		101,670
Regulatory Liabilities - Total	78,171		75,121
Net Regulatory Asset Position	76,970		26,549
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	7,464	[1]	4,095	[1]
Regulatory Assets - Long-Term	101,526	[1]	55,012	[1]
Regulatory Assets - Total	108,990	[1]	59,107	[1]
Regulatory Assets - Long term - Remaining Recovery/Refund Period	see note	[1]	see note	[1]
Deferred Marked-to-Market Losses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	4,492	[1]	3,008	[1]
Regulatory Assets - Long-Term	9,396	[1]	8,674	[1]
Regulatory Assets - Total	13,888	[1]	11,682	[1]
Regulatory Assets - Remaining Recovery/Refund Period	72 months	[1]	60 months	[1]
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	5,843	[2]	4,945	[2]
Regulatory Assets - Long-Term	2,500	[2]	3,959	[2]
Regulatory Assets - Total	8,343	[2]	8,904	[2]
Regulatory Assets - Remaining Recovery/Refund Period	18 months	[2]	18 months	[2]
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current		[1]		[1]
Regulatory Assets - Long-Term	5,190	[1]	4,646	[1]
Regulatory Assets - Total	5,190	[1]	4,646	[1]
Regulatory Assets - Long term - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	592	[1]	558	[1]
Regulatory Assets - Long-Term	3,207	[1]	3,967	[1]
Regulatory Assets - Total	3,799	[1]	4,525	[1]
Regulatory Assets - Remaining Recovery/Refund Period	96 months	[1]	81 months	[1]
Minnesota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	943	[2]
Regulatory Assets - Long-Term	2,455	[2]
Regulatory Assets - Total	3,398	[2]
Regulatory Assets - Remaining Recovery/Refund Period	24 months	[2]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	2,585	[1]	1,351	[1]
Regulatory Assets - Long-Term	807	[1]	1,753	[1]
Regulatory Assets - Total	3,392	[1]	3,104	[1]
Regulatory Assets - Remaining Recovery/Refund Period	24 months	[1]	24 months	[1]
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	351	[1]	351	[1]
Regulatory Assets - Long-Term	1,890	[1]	2,241	[1]
Regulatory Assets - Total	2,241	[1]	2,592	[1]
Regulatory Assets - Remaining Recovery/Refund Period	213 months	[1]	225 months	[1]
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	706	[2]	2,331	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	706	[2]	2,331	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	12 months	[2]
Minnesota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	186	[2]
Regulatory Assets - Long-Term		[2]
Regulatory Assets - Total	186	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current		[1]		[1]
Regulatory Liabilities - Current		[1]
Regulatory Assets - Long-Term	2,086	[1]	1,805	[1]
Regulatory Liabilities - Long-Term	1,550	[1]	1,960
Regulatory Assets - Total	2,086	[1]	1,805	[1]
Regulatory Liabilities - Total	1,550	[1]	1,960
Regulatory Assets - Long term - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Regulatory Liabilities - Long-Term - Remaining Recovery/Refund Period	asset lives	[1]	asset lives
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	100	[2]	101	[2]
Regulatory Assets - Long-Term	743	[2]	843	[2]
Regulatory Assets - Total	843	[2]	944	[2]
Regulatory Assets - Remaining Recovery/Refund Period	101 months	[2]	113 months	[2]
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current				[2]
Regulatory Assets - Long-Term			762	[2]
Regulatory Assets - Total			762	[2]
Regulatory Assets - Remaining Recovery/Refund Period			15 months	[2]
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	1,114	[1]	760	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	1,114	[1]	760	[1]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[1]	12 months	[1]
Big Stone II Unrecovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current			375	[1]
Regulatory Liabilities - Current	147
Regulatory Assets - Long-Term				[1]
Regulatory Liabilities - Long-Term
Regulatory Assets - Total			375	[1]
Regulatory Liabilities - Total	147
Regulatory Assets - Remaining Recovery/Refund Period			3 months	[1]
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]		[2]
Regulatory Assets - Long-Term	68	[2]	68	[2]
Regulatory Assets - Total	68	[2]	68	[2]
Regulatory Assets - Long term - Remaining Recovery/Refund Period	see note	[2]	see note	[2]
South Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	38	[2]
Regulatory Assets - Long-Term		[2]
Regulatory Assets - Total	38	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
South Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current			32	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			32	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
Deferred Holding Company Formation Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current			27	[1]
Regulatory Assets - Long-Term				[1]
Regulatory Assets - Total			27	[1]
Regulatory Assets - Remaining Recovery/Refund Period			6 months	[1]
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current
Regulatory Liabilities - Long-Term	74,237		71,454
Regulatory Liabilities - Total	74,237		71,454
Regulatory Liabilities - Long-Term - Remaining Recovery/Refund Period	asset lives		asset lives
Minnesota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			670
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			670
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Revenue for Rate Case Expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current
Regulatory Liabilities - Long-Term	784		289
Regulatory Liabilities - Total	784		289
Regulatory Liabilities - Long-Term - Remaining Recovery/Refund Period	see note		see note
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	933		261
Regulatory Liabilities - Long-Term	85
Regulatory Liabilities - Total	1,018		261
Regulatory Liabilities - Remaining Recovery/Refund Period	15 months		12 months
North Dakota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			215
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			215
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Deferred Marked-to-Market Gains
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			6
Regulatory Liabilities - Long-Term	257		117
Regulatory Liabilities - Total	257		123
Regulatory Liabilities - Remaining Recovery/Refund Period	67 months		56 months
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	6		5
Regulatory Liabilities - Long-Term	100		106
Regulatory Liabilities - Total	106		111
Regulatory Liabilities - Remaining Recovery/Refund Period	228 months		240 months
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	24		38
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	24		38
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
General Rate Case Recoverable Expenses - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current			6	[1]
Regulatory Assets - Long-Term				[1]
Regulatory Assets - Total			6	[1]
Regulatory Assets - Remaining Recovery/Refund Period			1 month	[1]
North Dakota Transmission Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	859	[2]
Regulatory Assets - Long-Term		[2]
Regulatory Assets - Total	859	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
South Dakota Transmission Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current	48
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	$48
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
[1]	Costs subject to recovery without a rate of return.
[2]	Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities (Detail Textuals)	12 Months Ended
	Dec. 31, 2014
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets long term, remaining recovery/refund period	213 months
Otter Tail Power Company | South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Share of actual profit margins on nonasset-based wholesale sales of electricity	25.00%

Forward_Contracts_Classified_a2

Forward Contracts Classified as Derivatives - Electric Operating Revenue (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Wholesale Sales - Company-Owned Generation	$11,160	$14,846	$12,951
Revenue from Settled Contracts at Market Prices	131,952	133,238	160,987
Market Cost of Settled Contracts	-130,908	-132,055	-159,500
Net Margins on Settled Contracts at Market	1,044	1,183	1,487
Marked-to-Market Gains on Settled Contracts	263	3,039	7,864
Marked-to-Market Losses on Settled Contracts	-276	-2,722	-7,974
Net Marked-to-Market Gains (Losses) on Settled Contracts	-13	317	-110
Unrealized Marked-to-Market Gains on Open Contracts		215	284
Unrealized Marked-to-Market Losses on Open Contracts		-100	-235
Net Unrealized Marked-to-Market Gains on Open Contracts		115	49
Wholesale Electric Revenue	$12,191	$16,461	$14,377

Forward_Contracts_Classified_a3

Forward Contracts Classified as Derivatives - Effect of Marking to Market Forward Contracts for Purchase and Sale of Electricity and Location and Fair Value Amounts of Related Derivatives (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current Deferred Marked-to-Market Loss	$25,273	$17,940
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	129,868	83,730
Current Liability - Marked-to-Market Loss	-14,230	-11,782
Regulatory Liability - Current Deferred Marked-to-Market Gain	-1,158	-1,195
Regulatory Liability - Long-Term Deferred Marked-to-Market Gain	-77,013	-73,926
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Other Current Asset - Marked-to-Market Gain	257	338
Total Assets	14,145	12,020
Current Liability - Marked-to-Market Loss	-13,888	-11,782
Total Liabilities	-14,145	-11,905
Net Fair Value of Marked-to-Market Energy Contracts		115	49
Forward Electricity Contracts | Deferred Marked-to-Market Loss
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current Deferred Marked-to-Market Loss	4,492	3,008
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	9,396	8,674
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current Deferred Marked-to-Market Gain		-6
Regulatory Liability - Long-Term Deferred Marked-to-Market Gain	($257)	($117)

Forward_Contracts_Classified_a4

Forward Contracts Classified as Derivatives - Change in Consolidated Balance Sheet Location and Fair Values of Forward Contracts for Purchase and Sale of Electricity (Details 2) (Forward Electricity Contracts, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Forward Electricity Contracts
Derivatives Fair Value [Roll Forward]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period	$115	$49
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods	-72	-49
Changes in Fair Value of Contracts Entered into in Prior Periods	-43
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period
Changes in Fair Value of Contracts Entered into in Current Period		115
Cumulative Fair Value Adjustments Included in Earnings - End of Period		$115

Forward_Contracts_Classified_a5

Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 3) (Legally enforceable netting arrangements, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Legally enforceable netting arrangements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative Assets Subject to Legally Enforceable Netting Arrangements	$257	$400
Derivative Liabilities Subject to Legally Enforceable Netting Arrangements	-14,230	-11,782
Net Balance Subject to Legally Enforceable Netting Arrangements	($13,973)	($11,382)

Forward_Contracts_Classified_a6

Forward Contracts Classified as Derivatives - Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions (Details 4) (Otter Tail Power Company, USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit	$45
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	13,888	[1]	11,679	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements	297		103
Total Current Liability - Marked-to-Market Loss	$14,230		$11,782
[1]	Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $13,888 $11,679 Offsetting Gains with Counterparties under Master Netting Agreements (257) (117) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $13,631 $11,562

Forward_Contracts_Classified_a7

Forward Contracts Classified as Derivatives - Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions (Parentheticals) (Details 4) (Otter Tail Power Company, USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$13,888	[1]	$11,679	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	-257		-117
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$13,631		$11,562
[1]	Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $13,888 $11,679 Offsetting Gains with Counterparties under Master Netting Agreements (257) (117) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $13,631 $11,562

Common_Shares_and_Earnings_Per2

Common Shares and Earnings Per Share - Reconciliation of Common Shares Outstanding (Details)	12 Months Ended
	Dec. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Balance (in shares)	36,271,696
Issuances:
At-the-Market Offering	519,636
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	180,818
Cash Invested	81,533
Employee Stock Purchase Plan:
Cash Invested	39,222
Dividends Reinvested	25,694
Restricted Stock Issued to Employees	26,700
Employee Stock Ownership Plan	22,650
Executive Stock Performance Awards (2011-2013 shares earned)	22,630
Stock Options Exercised	20,800
Restricted Stock Issued to Directors	16,800
Vesting of Restricted Stock Units	14,305
Directors Deferred Compensation	498
Retirements:
Shares Withheld for Individual Income Tax Requirements	-20,554
Forfeiture of Unvested Restricted Stock	-4,375
Balance (in shares)	37,218,053

Common_Shares_and_Earnings_Per3

Common Shares and Earnings Per Share - Outstanding Stock Options with Exercise Prices Greater than Average Market Price Excluded from Calculation of Diluted Earnings per Share (Details 1) (Stock options, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options Outstanding			92,497
Range of Exercise Prices, Lower Range			$24.93
Range of Exercise Prices, Upper Range			$27.25

Common_Shares_and_Earnings_Per4

Common Shares and Earnings Per Share (Detail Textuals) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	11-May-12	14-May-12
Stockholders Equity Note [Line Items]
Common shares issued for cash	39,222
Adjustments to denominator diluted earnings per share	238,162	203,583	194,240
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
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	460,264
Common shares issued for cash	39,222
Purchase of shares in open market		43,837	60,439
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	661,751
Common shares issued for cash	288,045
Purchase of shares in open market	7,480	284,632	258,092
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	1,685,653
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS)
Stockholders Equity Note [Line Items]
Agreement with distribution agent for offer and sale of shares, aggregate sales price					$75
Percentage of commission on gross sales price					2.00%

ShareBased_Payments_Informatio

Share-Based Payments - Information about Stock Options Outstanding (Details) (Stock options, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$24.93	$25.69	$26.59	$28.53
Exercise price $24.93
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$24.93
Outstanding and Exercisable	12,750
Remaining Contractual Life	Expire on April 10, 2015

ShareBased_Payments_Summary_of

Share-Based Payments - Summary of Stock Options Activity (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding [Roll Forward]
Exercised	20,800
Stock options
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, Beginning of Year	34,700	92,497	156,397
Granted
Exercised	20,800	56,109
Forfeited or Expired	1,150	1,688	63,900
Outstanding, End of Year	12,750	34,700	92,497
Exercisable, End of Year	12,750	34,700	92,497
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding, Beginning of Year	$25.69	$26.59	$28.53
Granted
Exercised	$26.11	$27.12
Forfeited or Expired	$26.50	$27.25	$31.34
Outstanding, End of Year	$24.93	$25.69	$26.59
Exercisable, End of Year	$24.93	$25.69	$26.59
Cash Received for Options Exercised	$543,000	$1,522,000
Intrinsic Value of Options Exercised	$89,000	$152,000
Fair Value of Options Granted During Year	none granted	none granted	none granted

ShareBased_Payments_Summary_of1

Share-Based Payments - Summary of Status of Directors' Restricted Stock Awards (Details 2) (Director, Restricted Stock, USD $)	0 Months Ended	12 Months Ended
	Apr. 14, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Director | Restricted Stock
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Nonvested, Number Of Shares [Roll Forward]
Nonvested, Beginning of Year		42,483	56,900	54,250
Shares/Units Granted	16,800	16,800	17,333	24,000
Vested		21,233	29,750	21,350
Forfeited			2,000
Nonvested, End of Year		38,050	42,483	56,900
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested, Beginning of Year		$25.03	$21.84	$23.26
Weighted Average Grant-Date Fair Value per Award	$29.41	$29.41	$30.77	$21.32
Vested		$24.11	$21.87	$24.86
Forfeited			$31.03
Nonvested, End of Year		$27.47	$25.03	$21.84
Compensation Expense Recognized		$416,000	$611,000	$552,000
Fair Value of Shares Vested in Year		$512,000	$651,000	$531,000

ShareBased_Payments_Summary_of2

Share-Based Payments - Summary of Status of Employees' Restricted Stock Awards (Details 3) (Employee, Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee | Restricted Stock
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Nonvested, Number Of Shares [Roll Forward]
Nonvested, Beginning of Year	48,315	47,645	34,868
Shares/Units Granted	26,700	17,000	26,120
Awards Vested	25,360	16,330	11,518
Forfeited	4,375		1,825
Nonvested, End of Year	45,280	48,315	47,645
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested, Beginning of Year	$25.04	$21.82	$22.86
Weighted Average Grant-Date Fair Value per Award	$29.41	$31.03	$21.48
Awards Vested	$24.80	$21.89	$24.14
Forfeited	$28.03		$22.20
Nonvested, End of Year	$27.46	$25.04	$21.82
Compensation Expense Recognized	$998,000	$427,000	$325,000
Fair Value Of Awards Vested	$629,000	$358,000	$278,000

ShareBased_Payments_Summary_of3

Share-Based Payments - Summary of Status of Employees' Restricted Stock Unit Awards (Details 4) (Restricted Stock Units (RSU), Employee, USD $)	0 Months Ended	12 Months Ended
	Apr. 14, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock Units (RSU) | Employee
Share-Based Compensation Arrangement By Share-Based Payment Award, Equity Instruments Other Than Options, Nonvested, Number Of Shares [Roll Forward]
Nonvested, Beginning of Year		56,180	60,665	73,815
Granted	11,800	11,800	15,150	15,800
Reinstated		75
Vested		14,305	17,535	20,750
Forfeited		7,850	2,100	8,200
Nonvested, End of Year		45,900	56,180	60,665
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested, Beginning of Year		$19.79	$18.11	$20.95
Granted	$24.95	$24.95	$25.30	$17.66
Reinstated		$30.81
Vested		$18.05	$18.73	$27.13
Forfeited		$18.90	$19.88	$19.97
Nonvested, End of Year		$21.82	$19.79	$18.11
Compensation Expense Recognized		$194,000	$275,000	$256,000
Fair Value of Units Converted in Year		$258,000	$328,000	$563,000

ShareBased_Payments_Summary_of4

Share-Based Payments - Summary of Stock Performance Awards Granted and Amounts Expensed (Details 5) (USD $)	12 Months Ended			60 Months Ended	36 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Awarded	22,630
Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense Recognized	2,022,000	$2,678,000	$1,255,000
Shares Awarded				188,221
Executive Officers | Performance Period 2014 To 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum Shares Subject To Award	159,450			159,450	159,450
Shares Used To Estimate Expense	106,300			106,300	106,300
Average Grant Date Fair Value	22.94			22.94	$22.94
Expense Recognized	1,422,000
Executive Officers | Performance Period 2014 To 2016 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2014
Executive Officers | Performance Period 2014 To 2016 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2016
Executive Officers | Performance Period 2013 To 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum Shares Subject To Award	90,600			90,600	90,600
Shares Used To Estimate Expense	45,300			45,300	45,300
Average Grant Date Fair Value	37.51			37.51	$37.51
Expense Recognized	458,000	580,000
Executive Officers | Performance Period 2013 To 2015 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2013
Executive Officers | Performance Period 2013 To 2015 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2015
Executive Officers | Performance Period 2012 To 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum Shares Subject To Award	148,400			148,400	148,400
Shares Used To Estimate Expense	74,200			74,200	74,200
Average Grant Date Fair Value	21.75			21.75	$21.75
Expense Recognized	142,000	1,686,000	1,001,000
Shares Awarded					89,991
Executive Officers | Performance Period 2012 To 2014 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2012
Executive Officers | Performance Period 2012 To 2014 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2014
Executive Officers | Performance Period 2011 To 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum Shares Subject To Award	90,600			90,600	90,600
Shares Used To Estimate Expense	45,300			45,300	45,300
Average Grant Date Fair Value	23.61			23.61	$23.61
Expense Recognized		412,000	254,000
Shares Awarded						48,730
Executive Officers | Performance Period 2011 To 2013 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2011
Executive Officers | Performance Period 2011 To 2013 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2013
Executive Officers | Performance Period 2010 To 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum Shares Subject To Award	138,800			138,800	138,800
Shares Used To Estimate Expense	69,400			69,400	69,400
Average Grant Date Fair Value	20.97			20.97	$20.97
Expense Recognized
Shares Awarded							49,500
Executive Officers | Performance Period 2010 To 2012 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2010
Executive Officers | Performance Period 2010 To 2012 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Period	2012

ShareBased_Payments_Detail_Tex

Share-Based Payments (Detail Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$175,000	$143,000	$179,000
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

ShareBased_Payments_Detail_Tex1

Share-Based Payments (Detail Textuals 1) (USD $)	0 Months Ended	12 Months Ended
	Apr. 14, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	16,800	16,800	17,333	24,000
Forfeited			2,000
Vesting percentage	25.00%
Grant date fair value of each share of stock awards	$29.41	$29.41	$30.77	$21.32
Restricted Stock | Director | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date	8-Apr-15
Restricted Stock | Director | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date	8-Apr-18
Restricted Stock | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted		26,700	17,000	26,120
Forfeited		4,375		1,825
Grant date fair value of each share of stock awards		$29.41	$31.03	$21.48
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	26,700
Vesting percentage	25.00%
Grant date fair value of each share of stock awards	$29.41
Restricted Stock | Executive Officers | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date	8-Apr-15
Restricted Stock | Executive Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date	8-Apr-18
Restricted Stock Units (RSU) | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	11,800	11,800	15,150	15,800
Forfeited		7,850	2,100	8,200
Vesting date	8-Apr-18
Grant date fair value of each share of stock awards	$24.95	$24.95	$25.30	$17.66
Unvested stock performance awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited		8,900
Unvested stock performance awards | Executive Officers | Granted in 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited		4,900
Unvested stock performance awards | Executive Officers | Granted in 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited		6,600
Unvested stock performance awards | Executive Officers | Granted in 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited				3,300
Unvested stock performance awards | Executive Officers | Granted in 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited				4,000

ShareBased_Payments_Detail_Tex2

Share-Based Payments (Detail Textuals 2) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized amount of compensation expense related to stock-based compensation	$3
Weighted-average period of amortization	1 year 10 months 24 days
Chief Executive Officer | Performance Period 2012 To 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout target percentage	121.28%
Chief Executive Officer | Performance Period 2011 To 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Awarded		26,100
Payout target percentage		117.86%

Retained_Earnings_and_Dividend1

Retained Earnings and Dividend Restriction (Detail Textuals) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Retained Earnings Restriction [Line Items]
Total Capitalization	1,071,255	$924,419
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	49.80%
OTP | Minimum
Retained Earnings Restriction [Line Items]
Required equity to total capitalization ratio to limit dividend payment	45.00%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Required equity to total capitalization ratio to limit dividend payment	55.00%
Total Capitalization	987,000

Commitments_and_Contingencies_2

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) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Operating Leases
2015	$7,072
2016	5,427
2017	4,311
2018	3,734
2019	2,225
Beyond 2019	14,590
Total	37,359
OTP
Operating Leases
2015	1,958
2016	1,371
2017	978
2018	990
2019	1,002
Beyond 2019	10,824
Total	17,123
OTP | Capacity and Energy Requirements
Purchase Commitments
2015	34,383
2016	22,812
2017	22,123
2018	22,729
2019	24,532
Beyond 2019	217,359
Total	343,938
OTP | Coal and Freight Purchase Commitments
Purchase Commitments
2015	49,739
2016	22,943
2017	28,146
2018	23,135
2019	23,072
Beyond 2019	598,742
Total	745,777
OTP | Construction Program Commitments
Purchase Commitments
2015	48,708
2016	40,653
2017	17,163
2018	100
2019
Beyond 2019
Total	106,624
Nonelectric
Operating Leases
2015	5,114
2016	4,056
2017	3,333
2018	2,744
2019	1,223
Beyond 2019	3,766
Total	$20,236

Commitments_and_Contingencies_3

Commitments and Contingencies of Continuing Operations (Detail Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Line Items]
Rent expense from continuing operations	$10,165,000	$8,560,000	$7,951,000
Loss Contingency, range of possible loss, maximum	2,000,000
OTP | Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$106,600,000
OTP | Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year	2039
OTP | Coal and Freight Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Contracts expiration year	2015, 2016, 2017 and 2040

ShortTerm_and_LongTerm_Borrowi2

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Status of Lines of Credit (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Line of Credit Facility [Line Items]
Line Limit	$320,000
In Use	10,854
Restricted due to Outstanding Letters of Credit	834
Available	308,312	266,316
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	10,854
Restricted due to Outstanding Letters of Credit	274
Available	138,872	149,341
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use
Restricted due to Outstanding Letters of Credit	560
Available	$169,440	$116,975

ShortTerm_and_LongTerm_Borrowi3

Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Aggregate Amounts of Maturities on Bonds Outstanding and Other Long-Term Obligations (Details 1) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
Aggregate amounts of debt maturities in 2015	$201
Aggregate amounts of debt maturities in 2016	52,544
Aggregate amounts of debt maturities in 2017	33,228
Aggregate amounts of debt maturities in 2018	187
Aggregate amounts of debt maturities in 2019	$172

ShortTerm_and_LongTerm_Borrowi4

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 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Short-Term Debt	$10,854	$51,195
Long-Term Debt	498,691	389,778
Less: Current Maturities - Otter Tail Corporation	201	188
Unamortized Debt Discount	1	1
Total Long-Term Debt	498,489	389,589
Total Short-Term and Long-Term Debt (with current maturities)	509,544	440,972
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Debt Instrument [Line Items]
Long-Term Debt		40,900
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	256	325
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	1,105	1,223
OTP
Debt Instrument [Line Items]
Short-Term Debt		51,195
Long-Term Debt	445,000	335,900
Less: Current Maturities - Otter Tail Corporation
Unamortized Debt Discount
Total Long-Term Debt	445,000	335,900
Total Short-Term and Long-Term Debt (with current maturities)	445,000	387,095
OTP | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Debt Instrument [Line Items]
Long-Term Debt		40,900
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000
OTP | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt
OTP | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	10,854
Long-Term Debt	53,691	53,878
Less: Current Maturities - Otter Tail Corporation	201	188
Unamortized Debt Discount	1	1
Total Long-Term Debt	53,489	53,689
Total Short-Term and Long-Term Debt (with current maturities)	64,544	53,877
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	256	325
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$1,105	$1,223

ShortTerm_and_LongTerm_Borrowi5

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 2)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Nov. 25, 2013	Nov. 06, 2013
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Debt Instrument [Line Items]
Long-Term Debt, Due Date		15-Jan-15
Description of variable rate basis		LIBOR
Basis spread on variable rate		0.88%
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%	9.00%	9.00%
Long-Term Debt, Due Date	15-Dec-16	15-Dec-16
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	20-Aug-17	20-Aug-17
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	1-Dec-21	1-Dec-21
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	20-Aug-22	20-Aug-22
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	20-Aug-27	20-Aug-27
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%
Long-Term Debt, Due Date	27-Feb-29
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	20-Aug-37	20-Aug-37
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%
Long-Term Debt, Due Date	27-Feb-44
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	1-Apr-18	1-Apr-18
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	18-Mar-21	18-Mar-21
OTP | Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015 (early retired on February 27, 2014)
Debt Instrument [Line Items]
Long-Term Debt, Due Date		15-Jan-15
Description of variable rate basis		LIBOR
Basis spread on variable rate		0.88%
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	20-Aug-17	20-Aug-17
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	1-Dec-21	1-Dec-21
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	20-Aug-22	20-Aug-22
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	20-Aug-27	20-Aug-27
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%
Long-Term Debt, Due Date	27-Feb-29
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	20-Aug-27	20-Aug-37
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%
Long-Term Debt, Due Date	27-Feb-44
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	15-Dec-16	15-Dec-16
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	1-Apr-18	1-Apr-18
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	18-Mar-21	18-Mar-21

ShortTerm_and_LongTerm_Borrowi6

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Oct. 29, 2012
Line of Credit Facility [Line Items]
Weighted average interest rate paid on short-term debt	1.90%
Line Limit	$320,000,000
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Maximum amount of debt outstanding	41,348,000
Average daily balance of debt outstanding	17,868,000
Weighted average interest rate paid on short-term debt	1.90%	1.90%
Line Limit	150,000,000
Reduced line of credit facility, borrowing capacity			40,000,000
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
OTP Credit Agreement
Line of Credit Facility [Line Items]
Maximum amount of debt outstanding	97,000,000
Average daily balance of debt outstanding	12,815,000
Weighted average interest rate paid on short-term debt	1.40%	1.40%
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 | Unsecured 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

ShortTerm_and_LongTerm_Borrowi7

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 1) (USD $)	12 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Mar. 01, 2013	Mar. 01, 2013
Cumulative Preferred Shares
Debt Instrument [Line Items]
Redemption amount of preferred stock equal to proceeds from term loan			$15.70
Preferred stock redemption, call premiums	0.2
Otter Tail Power Company | J P Morgan Chase Bank | Unsecured Term Loan
Debt Instrument [Line Items]
Term loan borrowed for funding		40.9
Variable interest rate		LIBOR
Basis spread on variable rate		0.88%
Otter Tail Power Company | J P Morgan Chase Bank | Unsecured Term Loan | 4.65 % Grant County, South Dakota and 4.85 % Mercer County, North Dakota Pollution Control Refunding Revenue Bonds
Debt Instrument [Line Items]
Term loan borrowed for funding		25.1
Otter Tail Power Company | J P Morgan Chase Bank | Unsecured Term Loan | Intercompany Note
Debt Instrument [Line Items]
Term loan borrowed for funding		$15.70

ShortTerm_and_LongTerm_Borrowi8

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 2) (USD $)	12 Months Ended					0 Months Ended
	Dec. 31, 2014			Dec. 31, 2013	Dec. 31, 2012	Jul. 13, 2012	Nov. 06, 2013	Nov. 25, 2013	Dec. 31, 2011
							Transaction
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	$498,691,000			$389,778,000
Financial covenants of debt	The Company’s and OTP’s borrowing agreements are subject to certain financial covenants. Specifically:
		●	Under the Otter Tail Corporation Credit 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 Otter Tail Corporation Credit Agreement.
		●	Under the OTP Credit Agreement and the Loan Agreement (when in effect), 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.
Income (loss) from continuing operations per diluted share	$1.55			$1.33	$1.25
Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	445,000,000			335,900,000
Cascade Investment, L.L.C. (Cascade)
Debt Instrument [Line Items]
Income (loss) from continuing operations per diluted share						$0.22
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	1,105,000			1,223,000
Interest rate of original debt repurchased	2.54%			2.54%
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	256,000			325,000
Interest rate of original debt repurchased	3.95%			3.95%
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	140,000,000			140,000,000
Interest rate of original debt repurchased	4.63%			4.63%
Senior Unsecured Notes 4.63%, due December 1, 2021 | Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	140,000,000			140,000,000
Interest rate of original debt repurchased	4.63%			4.63%
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	33,000,000			33,000,000
Interest rate of original debt repurchased	5.95%			5.95%
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	33,000,000			33,000,000
Interest rate of original debt repurchased	5.95%			5.95%
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	30,000,000			30,000,000
Interest rate of original debt repurchased	6.15%			6.15%
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	30,000,000			30,000,000
Interest rate of original debt repurchased	6.15%			6.15%
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	42,000,000			42,000,000
Interest rate of original debt repurchased	6.37%			6.37%
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	42,000,000			42,000,000
Interest rate of original debt repurchased	6.37%			6.37%
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	50,000,000			50,000,000
Interest rate of original debt repurchased	6.47%			6.47%
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | Otter Tail Power Company
Debt Instrument [Line Items]
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	50,000,000			50,000,000
Interest rate of original debt repurchased	6.47%			6.47%
2016 Notes
Debt Instrument [Line Items]
Original debt issued, principal amount							100,000,000
Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid	52,330,000			52,330,000
Interest rate of original debt repurchased	9.00%			9.00%			9.00%	9.00%
Negotiated prepayment premium pursuant to the Note Purchase Agreement							9,889,000
Unamortized debt expense recognized pursuant to the Note Purchase Agreement							363,000
Income (loss) from continuing operations per diluted share							$0.17
Amount of the original debt repurchased							12,933,000	34,737,000
Price paid for repurchase of debt							59,404,000
Principal and accrued interest of purchased notes							1,845,000
Negotiated premium of repurchase notes							9,889,000
Number of repurchase transaction							2
Divesture Period							2 years
2007 and 2011 Note Purchase Agreement
Debt Instrument [Line Items]
Percentage of required payment for whole prepayment	100.00%
2007 and 2011 Note Purchase Agreement | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio	1
Interest and dividend coverage ratio	1.5
Priority debt to total capitalization	20.00%
2007 and 2011 Note Purchase Agreement | Minimum
Debt Instrument [Line Items]
Percentage of required payment for partial prepayment	10.00%
Debt to total capitalization ratio	0.6
Interest and dividend coverage ratio	1
2007 and 2011 Note Purchase Agreement | Senior Unsecured Notes 6.63%, due December 1, 2011 | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount									140,000,000
Interest rate of original debt repurchased									4.63%
2007 Note Purchase Agreement
Debt Instrument [Line Items]
Percentage of required payment in the event of change in control	100.00%
2007 Note Purchase Agreement | Unsecured Senior Notes | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount	155,000,000
2007 Note Purchase Agreement | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount	33,000,000
Interest rate of original debt repurchased	5.95%
2007 Note Purchase Agreement | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount	30,000,000
Interest rate of original debt repurchased	6.15%
2007 Note Purchase Agreement | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount	42,000,000
Interest rate of original debt repurchased	6.37%
2007 Note Purchase Agreement | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | Otter Tail Power Company
Debt Instrument [Line Items]
Original debt issued, principal amount	50,000,000
Interest rate of original debt repurchased	6.47%
Cascade Note Purchase Agreement | 8.89% Senior Unsecured Note due November 30, 2017
Debt Instrument [Line Items]
Prepayment of cascade note pursuant to the Note Purchase Agreement						50,000,000
Effective interest rate during the period						8.89%
Price paid for early repayment of debt						63,031,000
Accrued interest pursuant to the Note Purchase Agreement						531,000
Negotiated prepayment premium pursuant to the Note Purchase Agreement						12,500,000
Unamortized debt expense recognized pursuant to the Note Purchase Agreement						$606,000
Otter Tail Corporation Credit Agreement | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio	1
Interest and dividend coverage ratio	1.5
Otter Tail Corporation Credit Agreement | Minimum
Debt Instrument [Line Items]
Debt to total capitalization ratio	0.6
Interest and dividend coverage ratio	1
OTP Credit Agreement | Maximum
Debt Instrument [Line Items]
Debt to total capitalization ratio	1
OTP Credit Agreement | Minimum
Debt Instrument [Line Items]
Debt to total capitalization ratio	0.6

ShortTerm_and_LongTerm_Borrowi9

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 3) (Otter Tail Power Company, Note Purchase Agreement 2013, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Aug. 14, 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.
Interest bearing debt, maximum percentage of total capitalization	60.00%
Priority indebtedness, maximum percentage of total capitalization	20.00%
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%
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%

Pension_Plan_and_Other_Postret2

Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost--Benefit Earned During the Period	$4,666		$5,594		$5,084
Interest Cost on Projected Benefit Obligation	13,111		12,123		12,465
Expected Return on Assets	-16,743		-14,521		-14,430
Amortization of Prior-Service Cost:
From Regulatory Asset	257		333		398
From Other Comprehensive Income	7	[1]	9	[1]	11	[1]
Amortization of Net Actuarial Loss (Net of Medicare Part D Subsidy):
From Regulatory Asset	3,400		6,600		4,910
From Other Comprehensive Income	83	[1]	176	[1]	131	[1]
Net Periodic Cost	4,781		10,314		8,569
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Service Cost--Benefit Earned During the Period	51		51		45
Interest Cost on Projected Benefit Obligation	1,520		1,408		1,479
Amortization of Prior-Service Cost:
From Regulatory Asset	22		22		22
From Other Comprehensive Income	51	[2]	51	[2]	51	[2]
Amortization of Net Actuarial Loss (Net of Medicare Part D Subsidy):
From Regulatory Asset	142		208		175
From Other Comprehensive Income	46	[3]	313	[3]	152	[3]
Net Periodic Cost	1,832		2,053		1,924
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost (Net of Medicare Part D Subsidy)	1,055		1,421		1,544
Interest Cost (Net of Medicare Part D Subsidy)	2,200		2,050		2,574
Amortization of Transition Obligation
From Regulatory Asset					729
From Other Comprehensive Income		[1]		[1]	19	[1]
Amortization of Prior-Service Cost:
From Regulatory Asset	205		205		206
From Other Comprehensive Income	5	[1]	5	[1]	5	[1]
Amortization of Net Actuarial Loss (Net of Medicare Part D Subsidy):
From Regulatory Asset			24		642
From Other Comprehensive Income		[1]	1	[1]	17	[1]
Net Periodic Cost	3,465		3,706		5,736
Effect of Medicare Part D Subsidy	($948)		($1,806)		($2,039)
[1]	Corporate cost included in Other Nonelectric Expenses.
[2]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 20 $ 20 $ 20 Other Nonelectric Expenses 31 31 31
[3]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 132 $ 193 $ 162 Other Nonelectric Expenses (86) 120 (10)

Pension_Plan_and_Other_Postret3

Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan (ESSRP), USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income	$51	[1]	$51	[1]	$51	[1]
Amortization of Net Actuarial Loss from Other Comprehensive Income	46	[2]	313	[2]	152	[2]
Electric Operation and Maintenance Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income	20		20		20
Amortization of Net Actuarial Loss from Other Comprehensive Income	132		193		162
Other Nonelectric Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income	31		31		31
Amortization of Net Actuarial Loss from Other Comprehensive Income	($86)		$120		($10)
[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 20 $ 20 $ 20 Other Nonelectric Expenses 31 31 31
[2]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 132 $ 193 $ 162 Other Nonelectric Expenses (86) 120 (10)

Pension_Plan_and_Other_Postret4

Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost (Details 1)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.30%	4.50%	5.15%
Long-Term Rate of Return on Plan Assets	7.75%	7.75%	8.00%
Rate of Increase in Future Compensation Level	3.13%	3.13%	3.38%
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.30%	4.50%	5.15%
Rate of Increase in Future Compensation Level	3.18%	3.19%	4.59%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	5.10%	4.25%	5.05%

Pension_Plan_and_Other_Postret5

Pension Plan and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Pension Plan
Regulatory Assets:
Unrecognized Prior Service Cost	$518	$776
Unrecognized Net Actuarial Loss (Gain)	97,722	56,051
Total Regulatory Assets	98,240	56,827
Projected Benefit Obligation	-311,650	-254,039	-275,634
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	21	28
Unrecognized Actuarial Loss (Gain)	899	448
Total Accumulated Other Comprehensive Loss	920	476
Noncurrent Liability	67,061	40,422
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Regulatory Assets:
Unrecognized Prior Service Cost	91	113
Unrecognized Net Actuarial Loss (Gain)	3,238	1,971
Total Regulatory Assets	3,329	2,084
Projected Benefit Obligation	-35,650	-29,321	-31,925
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	210	261
Unrecognized Actuarial Loss (Gain)	6,881	2,465
Total Accumulated Other Comprehensive Loss	7,091	2,726
Other Postretirement Benefits
Regulatory Assets:
Unrecognized Prior Service Cost	335	540
Unrecognized Net Actuarial Loss (Gain)	7,086	-344
Total Regulatory Assets	7,421	196
Projected Benefit Obligation	-53,638	-45,221	-58,883
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost	13	18
Unrecognized Actuarial Loss (Gain)	-209	-261
Total Accumulated Other Comprehensive Loss	($196)	($243)

Pension_Plan_and_Other_Postret6

Pension Plan and Other Postretirement Benefits - Funded Status (Details 3) (Pension Plan, USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	($273,903)	($224,365)
Projected Benefit Obligation	-311,650	-254,039	-275,634
Fair Value of Plan Assets	244,589	213,617	191,018
Funded Status	($67,061)	($40,422)

Pension_Plan_and_Other_Postret7

Pension Plan and Other Postretirement Benefits - Reconciliation of Changes in Fair Value of Plan Assets and Plan's Benefit Obligations (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1	$213,617,000	$191,018,000
Actual Return on Plan Assets	21,874,000	23,044,000
Employer Contributions	20,000,000	10,000,000
Benefit Payments	-10,902,000	-10,445,000
Fair Value of Plan Assets at December 31	244,589,000	213,617,000	191,018,000
Estimated Asset Return	9.60%	11.80%
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	254,039,000	275,634,000
Service Cost	4,666,000	5,594,000	5,084,000
Interest Cost	13,111,000	12,123,000	12,465,000
Benefit Payments	-10,902,000	-10,445,000
Actuarial (Gain) Loss	50,736,000	-28,867,000
Projected Benefit Obligation at December 31	311,650,000	254,039,000	275,634,000
Reconciliation of Funded Status:
Funded Status	-67,061,000	-40,422,000
Expense	-4,781,000	-10,314,000	-8,569,000
Employer Contributions	20,000,000	10,000,000
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	1,113,000	1,137,000
Benefit Payments (Net of Medicare Part D Subsidy)	-1,113,000	-1,137,000
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	29,321,000	31,925,000
Service Cost	51,000	51,000	45,000
Interest Cost	1,520,000	1,408,000	1,479,000
Benefit Payments (Net of Medicare Part D Subsidy)	-1,113,000	-1,137,000
Plan Amendments
Actuarial (Gain) Loss	5,871,000	-2,926,000
Projected Benefit Obligation at December 31	35,650,000	29,321,000	31,925,000
Reconciliation of Funded Status:
Funded Status	-35,650,000	-29,321,000
Expense	-1,832,000	-2,053,000	-1,924,000
Unrecognized Net Actuarial Loss	10,119,000	4,436,000
Employer Contributions	1,113,000	1,137,000
Unrecognized Prior Service Cost	301,000	374,000
Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost	-25,230,000	-24,511,000
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	2,320,000	2,012,000
Benefit Payments (Net of Medicare Part D Subsidy)	-5,017,000	-4,626,000
Participant Premium Payments	2,697,000	2,614,000
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1	45,221,000	58,883,000
Service Cost (Net of Medicare Part D Subsidy)	1,055,000	1,421,000	1,544,000
Interest Cost (Net of Medicare Part D Subsidy)	2,200,000	2,050,000	2,574,000
Benefit Payments (Net of Medicare Part D Subsidy)	-5,017,000	-4,626,000
Participant Premium Payments	2,697,000	2,614,000
Actuarial (Gain) Loss	7,482,000	-15,121,000
Projected Benefit Obligation at December 31	53,638,000	45,221,000	58,883,000
Reconciliation of Funded Status:
Accrued Postretirement Cost at January 1	-45,268,000	-43,574,000
Expense	-3,465,000	-3,706,000	-5,736,000
Employer Contributions	2,320,000	2,012,000
Accrued Postretirement Cost at December 31	($46,413,000)	($45,268,000)	($43,574,000)

Pension_Plan_and_Other_Postret8

Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Benefit Obligations (Details 5)	Dec. 31, 2014	Dec. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.35%	5.30%
Rate of Increase in Future Compensation Level	3.13%	3.13%
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.35%	5.30%
Rate of Increase in Future Compensation Level	3.15%	3.18%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.20%	5.10%

Pension_Plan_and_Other_Postret9

Pension Plan and Other Postretirement Benefits - Measurement Dates (Details 6)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Pension Cost	1-Jan-14	1-Jan-13
Market Value of Assets	31-Dec-14	31-Dec-13
Pension Plan | Minimum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	1-Jan-14	1-Jan-13
Pension Plan | Maximum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	31-Dec-14	31-Dec-13
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Pension Cost	1-Jan-14	1-Jan-13
Other Postretirement Benefits | Minimum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	1-Jan-14	1-Jan-13
Other Postretirement Benefits | Maximum
Defined Benefit Plan Disclosure [Line Items]
End of Year Benefit Obligations	31-Dec-14	31-Dec-13

Recovered_Sheet13

Pension Plan and Other Postretirement Benefits - Estimated Amounts of Unrecognized Net Actuarial Losses and Prior Service Costs to be Amortized (Details 7) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Pension Plan
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost	$189
Amortization of Unrecognized Actuarial Loss	6,529
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost	5
Amortization of Unrecognized Actuarial Loss	161
Total Estimated Amortization	6,884
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost	16
Amortization of Unrecognized Actuarial Loss	334
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost	38
Amortization of Unrecognized Actuarial Loss	602
Total Estimated Amortization	990
Other Postretirement Benefits
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost	205
Amortization of Unrecognized Actuarial Loss	191
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost	5
Amortization of Unrecognized Actuarial Loss	5
Total Estimated Amortization	$406

Recovered_Sheet14

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) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2015	$11,858
2016	12,462
2017	13,116
2018	13,941
2019	14,665
Years 2020-2024	85,322
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
2015	1,178
2016	1,399
2017	1,376
2018	1,423
2019	1,516
Years 2020-2024	10,904
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2015	2,638
2016	2,762
2017	2,925
2018	3,086
2019	3,247
Years 2020-2024	$17,281

Recovered_Sheet15

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, 2014
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 | >0% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	15.00%
Equity | >0% 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 | >0% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	50.00%
Investment Grade Fixed Income | >0% 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 | >0% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[1]
Below Investment Grade Fixed Income | >0% 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 | >0% PBO | Minimum
Defined Benefit Plan Disclosure [Line Items]
Asset Allocation	0.00%	[2]
Other | >0% 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.

Recovered_Sheet16

Pension Plan and Other Postretirement Benefits - Pension Plan Asset Allocations by Asset Category (Details 10) (Pension Plan)	Dec. 31, 2014	Dec. 31, 2013
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	53.30%	56.40%
Large Capitalization Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	21.00%	21.00%
International Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	18.90%	21.70%
Small and Mid-Capitalization Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	7.90%	8.50%
SEI Dynamic Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	5.50%	5.20%
Fixed-Income Securities and Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	42.70%	39.30%
Other - SEI Special Situation Collective Investment Trust
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations	4.00%	4.30%

Recovered_Sheet17

Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value (Details 11) (Pension Plan, USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Defined Benefit Plan Disclosure [Line Items]
Total Assets	$244,589	$213,617	$191,018
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total Assets	234,788	204,447
Level 1 | Large Capitalization Equity Securities Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	51,404	44,882
Level 1 | International Equity Securities Mutual Funds
Defined Benefit Plan Disclosure [Line Items]
Total Assets	46,287	46,412
Level 1 | Small and Mid-Capitalization Equity Securities Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	19,189	18,151
Level 1 | SEI Dynamic Asset Allocation Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	13,543	11,159
Level 1 | Fixed Income Securities Mutual Funds
Defined Benefit Plan Disclosure [Line Items]
Total Assets	104,360	83,843
Level 1 | Cash Management - Money Market Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	5
Level 2
Defined Benefit Plan Disclosure [Line Items]
Total Assets	9,801	9,170
Level 2 | SEI Special Situation Collective Investment Trust Fund
Defined Benefit Plan Disclosure [Line Items]
Total Assets	9,801	9,170
Level 3
Defined Benefit Plan Disclosure [Line Items]
Total Assets

Recovered_Sheet18

Pension Plan and Other Postretirement Benefits - Healthcare Cost-Trend Rates (Details 12) (Other Postretirement Benefits)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Rate at Which the Cost-Trend Rate is Assumed to Decline	5.00%	5.00%
Year the Rate Reaches the Ultimate Trend Rate	2025	2025
Pre-65
Defined Benefit Plan Disclosure [Line Items]
Healthcare Cost-Trend Rate Assumed for Next Year	6.32%	6.47%
Post-65
Defined Benefit Plan Disclosure [Line Items]
Healthcare Cost-Trend Rate Assumed for Next Year	6.63%	6.82%

Recovered_Sheet19

Pension Plan and Other Postretirement Benefits - Effects of One Percentage Change in Assumed healthcare Cost-Trend Rates (Details 13) (Other Postretirement Benefits, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Effect of 1 point increase on the Postretirement Benefit Obligation	$7,442
Effect of 1 point increase on Total of Service and Interest Cost	516
Effect of 1 point increase on Expense	516
Effect of 1 point decrease on the Postretirement Benefit Obligation	-6,088
Effect of 1 point decrease on Total of Service and Interest Cost	-414
Effect of 1 point decrease on Expense	($606)

Recovered_Sheet20

Pension Plan and Other Postretirement Benefits (Detail Textuals) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015	Jan. 31, 1993
Defined Benefit Plan Disclosure [Line Items]
Contributions made to 401K plan by the companies	$3,171,000	$2,748,000	$2,283,000
Contributions made by the company to employee stock ownership plan	696,000	705,000	735,000
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 2015 net periodic pension cost	7.75%
Plan contribution	20,000,000	10,000,000
Pension Plan | Subsequent Event
Defined Benefit Plan Disclosure [Line Items]
Plan contribution				10,000,000
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Defined Benefit Plan Disclosure [Line Items]
Plan contribution	1,113,000	1,137,000
Period of benefit payments to the beneficiaries on their deaths	15 years
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Plan contribution	2,320,000	2,012,000
Health insurance benefits, requisite age	55 years
Health insurance benefits, requisite service period	10 years
Estimated future employer contributions in the next fiscal year	2,600,000
Medicare part D subsidy expected to received in 2015	456,000
Other Postretirement Benefits Transition Obligation
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation liability recognized					$14,964,000
Benefits earned recognition period					20 years

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments - Long-term debt including current maturities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents		$2,007
Short-Term Debt	-10,854	-51,195
Long-Term Debt including Current Maturities	-498,690	-389,777
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents		2,007
Short-Term Debt	-10,854	-51,195
Long-Term Debt including Current Maturities	($600,828)	($427,796)

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Detail Textuals)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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_Equipment_D

Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Total Gross Plant	$1,968,948	$1,819,271
Less Accumulated Depreciation and Amortization	700,418	663,581
Net Plant	1,268,530	1,155,690
Electric Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	1,785,282	1,645,664
Less Accumulated Depreciation and Amortization	584,956	554,818
Net Plant	1,200,326	1,090,846
Electric Plant | Production Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	690,024	679,067
Electric Plant | Transmission Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	323,496	270,606
Electric Plant | Distribution Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	438,489	421,803
Electric Plant | General Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	93,103	89,408
Electric Plant | Electric Plant In Service
Property, Plant and Equipment [Line Items]
Total Gross Plant	1,545,112	1,460,884
Electric Plant | Construction In Progress
Property, Plant and Equipment [Line Items]
Total Gross Plant	240,170	184,780
Nonelectric Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	183,666	173,607
Less Accumulated Depreciation and Amortization	115,462	108,763
Net Plant	68,204	64,844
Nonelectric Plant | Equipment
Property, Plant and Equipment [Line Items]
Total Gross Plant	135,007	131,075
Nonelectric Plant | Buildings And Leasehold Improvements
Property, Plant and Equipment [Line Items]
Total Gross Plant	36,558	36,420
Nonelectric Plant | Land
Property, Plant and Equipment [Line Items]
Total Gross Plant	3,594	3,430
Nonelectric Plant | Nonelectric Operations Plant
Property, Plant and Equipment [Line Items]
Total Gross Plant	175,159	170,925
Nonelectric Plant | Construction In Progress
Property, Plant and Equipment [Line Items]
Total Gross Plant	$8,507	$2,682

Property_Plant_and_Equipment_E

Property, Plant and Equipment - Estimated Service Lives for Properties (Details 1)	12 Months Ended
	Dec. 31, 2014
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	34 years
Electric Plant | Minimum | Transmission Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Electric Plant | Minimum | Distribution Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	15 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	70 years
Electric Plant | Maximum | Production Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	62 years
Electric Plant | Maximum | Transmission Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	55 years
Electric Plant | Maximum | Distribution Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	55 years
Electric Plant | Maximum | General Plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	70 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_Equipment_D1

Property, Plant and Equipment (Detail Textuals)	12 Months Ended
	Dec. 31, 2014
Electric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	70 years
Electric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years
Nonelectric Plant | Maximum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Nonelectric Plant | Minimum
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years

Income_Taxes_Income_Tax_Expens

Income Taxes - Income Tax Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Tax Computed at Federal Statutory Rate - Continuing Operations	$25,704	$21,389	$18,622
Increases (Decreases) in Tax from:
Federal PTCs	-7,517	-6,612	-6,695
State Income Taxes Net of Federal Income Tax Expense (Benefit)	1,993	1,561	-249
Section 199 Domestic Production Activities Deduction	-1,026
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	-849	-863	-891
Dividend Received/Paid Deduction	-622	-632	-656
Investment Tax Credit Amortization	-597	-597	-720
Allowance for Funds Used During Construction - Equity	-505	-638	-409
Corporate Owned Life Insurance	-354	-856	-585
Tax Depreciation - Treasury Grant for Wind Farms	-152	-304	-304
Differences Reversing in Excess of Federal Rates	-106	-100	-143
Impact of Medicare Part D Change			-584
Permanent and Other Differences	588	168	-213
Total Income Tax Expense - Continuing Operations	16,557	12,516	7,173
Income Tax Expense (Benefit) - Discontinued Operations - U.S.	3,952	1,042	-19,707
Income Tax Expense (Benefit) - Continuing and Discontinued Operations	20,509	13,558	-12,534
Overall Effective Federal, State and Foreign Income Tax Rate	26.20%	21.00%	70.40%
Income Tax Expense From Continuing Operations Includes the Following:
Current Federal Income Taxes	124	146	-3,198
Current State Income Taxes	5	37	-361
Deferred Federal Income Taxes	21,044	17,488	15,877
Deferred State Income Taxes	4,347	2,917	3,161
Federal PTCs	-7,517	-6,612	-6,695
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	-849	-863	-891
Investment Tax Credit Amortization	-597	-597	-720
Total	16,557	12,516	7,173
Income (Loss) Before Income Taxes - U.S.	78,232	63,924	-13,426
Income (Loss) Before Income Taxes - Foreign (Discontinued Operations)		499	-4,381
Total Income (Loss) Before Income Taxes - Continuing and Discontinued Operations	$78,232	$64,423	($17,807)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred Tax Assets
Retirement Benefits Liabilities	$42,706	$39,524
Benefit Liabilities	42,479	39,480
North Dakota Wind Tax Credits	41,783	42,241
Federal PTCs	30,189	33,620
Cost of Removal	29,089	27,926
Differences Related to Property	10,505	9,462
Net Operating Loss Carryforward	7,842	15,151
Vacation Accrual	2,154	1,843
Investment Tax Credits	1,549	1,960
Other	1,915	4,045
Total Deferred Tax Assets	210,211	215,252
Deferred Tax Liabilities
Differences Related to Property	-313,959	-302,852
Retirement Benefits Regulatory Asset	-42,706	-39,524
Excess Tax over Book Pension	-12,928	-6,977
North Dakota Wind Tax Credits	-11,543	-11,543
Impact of State Net Operating Losses on Federal Taxes	-2,745	-3,088
Regulatory Asset	-2,087	-1,805
Other	-5,571	-6,360
Total Deferred Tax Liabilities	-391,539	-372,149
Deferred Income Taxes	($181,328)	($156,897)

Income_Taxes_Expiration_of_Tax

Income Taxes - Expiration of Tax Net Operating Losses and Tax Credits Available (Details 2) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Federal Tax Credits
Tax Credit Carryforward [Abstract]
Tax Credits, Amount	$31,913
Tax Credits, Year of Expiration 2015
Tax Credits, Year of Expiration 2016
Tax Credits, Year of Expiration 2017
Tax Credits, Year of Expiration 2024-33	31,913
State Tax Credits
Tax Credit Carryforward [Abstract]
Tax Credits, Amount	38,654
Tax Credits, Year of Expiration 2015	2,339
Tax Credits, Year of Expiration 2016	2,339
Tax Credits, Year of Expiration 2017	389
Tax Credits, Year of Expiration 2024-33	33,587
State Net Operating Losses
Net Operating Loss Carryforward [Abstract]
Net Operating Losses, Amount	5,829
Net Operating Losses, Year of Expiration 2015
Net Operating Losses, Year of Expiration 2016
Net Operating Losses, Year of Expiration 2017
Net Operating Losses, Year of Expiration 2024-33	$5,829

Income_Taxes_Summary_of_Activi

Income Taxes - Summary of Activity Related to Unrecognized Tax benefit (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance on January 1	$4,239	$4,436	$12,138
Increases Related to Tax Positions for Prior Years	120	98
Decreases Related to Tax Positions for Prior Years	-4,142	-295	-6,802
Increases Related to Tax Positions for Current Year	5
Uncertain Positions Resolved During Year			-900
Balance on December 31	$222	$4,239	$4,436

Income_Taxes_Detail_Textuals

Income Taxes (Detail Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal income tax rate	35.00%	35.00%	35.00%
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	$5.10
Period for unrecognized tax benefits not expected change	12 months
Increase in percentage of production tax credits	13.80%
Wind tax credits amortization period	25 years

Asset_Retirement_Obligations_R

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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
Beginning Balance	$5,661	$5,207
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates	1,582
Accrued Accretion	478	454
Settlements
Ending Balance	7,721	5,661
Asset Retirement Costs Capitalized
Beginning Balance	1,477	1,477
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates	1,582
Settlements
Ending Balance	3,059	1,477
Accumulated Depreciation - Asset Retirement Costs Capitalized
Beginning Balance	462	407
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense	65	55
Settlements
Ending Balance	527	462
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) (North Dakota)	Dec. 31, 2014
	Turbine
North Dakota
Asset Retirement Obligations [Line Items]
Number of wind turbines	92

Discontinued_Operations_Result

Discontinued Operations - Results of Discontinued Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues	$149,860	$151,915	$382,136
Operating Expenses	140,002	149,287	394,879
Asset Impairment Charge	5,605		53,320
Interest Expense		4	177
Other (Deductions) Income	539	473	441
Income Tax (Benefit) Expense	3,952	1,037	-20,023
Net Gain (Loss)	840	2,060	-45,776
(Loss) Gain on Disposition Before Taxes		216	-5,216
Income Tax Expense (Benefit) on Disposition		6	315
Net Gain (Loss) on Disposition		210	-5,531
Net Gain (Loss) from Discontinued Operations	840	2,270	-51,307
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	105,333	110,097	93,598
Operating Expenses	100,826	109,036	109,493
Asset Impairment Charge	5,605
Interest Expense	510	249	689
Other (Deductions) Income	-38	4
Income Tax (Benefit) Expense	1,388	331	-6,630
Net Gain (Loss)	-3,034	485	-9,954
(Loss) Gain on Disposition Before Taxes
Income Tax Expense (Benefit) on Disposition
Net Gain (Loss) on Disposition
Net Gain (Loss) from Discontinued Operations		485	-9,954
Aevenia | 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	44,527	39,813	55,494
Operating Expenses	40,297	38,257	51,873
Asset Impairment Charge
Interest Expense	184	207	351
Other (Deductions) Income	304	-5	169
Income Tax (Benefit) Expense	1,729	518	1,174
Net Gain (Loss)	2,621	826	2,265
(Loss) Gain on Disposition Before Taxes
Income Tax Expense (Benefit) on Disposition
Net Gain (Loss) on Disposition
Net Gain (Loss) from Discontinued Operations		826	2,265
IMD | 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			186,151
Operating Expenses	19	-988	184,462
Asset Impairment Charge			45,573
Interest Expense			5,787
Other (Deductions) Income		412	135
Income Tax (Benefit) Expense	-8	370	-15,792
Net Gain (Loss)	-11	1,030	-33,744
(Loss) Gain on Disposition Before Taxes
Income Tax Expense (Benefit) on Disposition
Net Gain (Loss) on Disposition
Net Gain (Loss) from Discontinued Operations		1,030	-33,744
Wylie | 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		640	179
Asset Impairment Charge
Interest Expense
Other (Deductions) Income
Income Tax (Benefit) Expense		-256	13
Net Gain (Loss)		-384	-192
(Loss) Gain on Disposition Before Taxes			-62
Income Tax Expense (Benefit) on Disposition			460
Net Gain (Loss) on Disposition			-522
Net Gain (Loss) from Discontinued Operations		-384	-714
Shrco | 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		2,016	32,563
Operating Expenses	-180	2,622	36,163
Asset Impairment Charge			7,747
Interest Expense			1,553
Other (Deductions) Income	277	67	15
Income Tax (Benefit) Expense	183	-213	-4,021
Net Gain (Loss)	274	-326	-8,864
(Loss) Gain on Disposition Before Taxes		16
Income Tax Expense (Benefit) on Disposition		6
Net Gain (Loss) on Disposition		10
Net Gain (Loss) from Discontinued Operations		-316	-8,864
DMS | 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			16,362
Operating Expenses		-269	14,741
Asset Impairment Charge
Interest Expense			279
Other (Deductions) Income			122
Income Tax (Benefit) Expense		108	1,734
Net Gain (Loss)		161	-270
(Loss) Gain on Disposition Before Taxes		200	-5,154
Income Tax Expense (Benefit) on Disposition			-145
Net Gain (Loss) on Disposition		200	-5,009
Net Gain (Loss) from Discontinued Operations		361	-5,279
IPH | 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
Asset Impairment Charge
Interest Expense
Other (Deductions) Income
Income Tax (Benefit) Expense			106
Net Gain (Loss)			-106
(Loss) Gain on Disposition Before Taxes
Income Tax Expense (Benefit) on Disposition
Net Gain (Loss) on Disposition
Net Gain (Loss) from Discontinued Operations			-106
Intercompany Transactions Adjustment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues		-11	-2,032
Operating Expenses	-960	-11	-2,032
Asset Impairment Charge
Interest Expense	-694	-452	-8,482
Other (Deductions) Income	-4	-5
Income Tax (Benefit) Expense	660	179	3,393
Net Gain (Loss)	990	268	5,089
(Loss) Gain on Disposition Before Taxes
Income Tax Expense (Benefit) on Disposition
Net Gain (Loss) on Disposition
Net Gain (Loss) from Discontinued Operations		$268	$5,089

Discontinued_Operations_Major_

Discontinued Operations - Major Components of Assets and Liabilities of Discontinued Operations (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets	$35,174	$29,569
Goodwill and Intangibles	2,814	8,583
Net Plant	10,669	11,326
Assets of Discontinued Operations	48,657	49,478
Current Liabilities	22,864	35,902
Deferred Income Taxes	4,695	3,381
Liabilities of Discontinued Operations	27,559	39,283
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 Assets	29,897	21,408
Goodwill and Intangibles	2,814	8,420
Net Plant	4,445	5,225
Assets of Discontinued Operations	37,156	35,053
Current Liabilities	17,114	29,766
Deferred Income Taxes	2,065	1,892
Liabilities of Discontinued Operations	19,179	31,658
Aevenia | 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 Assets	5,277	8,123
Goodwill and Intangibles		163
Net Plant	6,224	6,101
Assets of Discontinued Operations	11,501	14,387
Current Liabilities	2,916	2,499
Deferred Income Taxes	2,630	1,489
Liabilities of Discontinued Operations	5,546	3,988
IMD | 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 Assets
Goodwill and Intangibles
Net Plant
Assets of Discontinued Operations
Current Liabilities	1,840	2,196
Deferred Income Taxes
Liabilities of Discontinued Operations	1,840	2,196
Shrco | 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 Assets		38
Goodwill and Intangibles
Net Plant
Assets of Discontinued Operations		38
Current Liabilities	994	1,441
Deferred Income Taxes
Liabilities of Discontinued Operations	$994	$1,441

Discontinued_Operations_Warran

Discontinued Operations - Warranty Reserves (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]
Warranty Reserve Balance, Beginning of Year	$3,087	$5,027
Provision for Warranties Issued During the Year		188
Less Settlements Made During the Year	-372	-715
Decrease in Warranty Estimates for Prior Years	-188	-1,413
Warranty Reserve Balance, End of Year	$2,527	$3,087

Discontinued_Operations_Detail

Discontinued Operations (Detail Textuals) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Feb. 08, 2013

Jun. 30, 2013

Nov. 30, 2012

6-May-11

Dec. 29, 2011

Jan. 18, 2012

Feb. 28, 2013

Feb. 29, 2012

Mar. 31, 2013

Dec. 31, 2014

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

$12,842,000

$42,229,000

Disposal Group, Held-for-sale or Disposed of by Sale | Shrco

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

13,000,000

Amount of working capital true up received

2,400,000

Disposal Group, Held-for-sale or Disposed of by Sale | IMD

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

18,100,000

Disposal Group, Held-for-sale or Disposed of by Sale | IPH

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

86,000,000

Disposal Group, Held-for-sale or Disposed of by Sale | Wylie

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

25,000,000

Disposal Group, Held-for-sale or Disposed of by Sale | Aviva

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

300,000

Disposal Group, Held-for-sale or Disposed of by Sale | DMS

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of business

24,000,000

Amount of working capital settlement paid

1,700,000

Value of working capital settlement paid

1,900,000

Gain on working capital settlement

200,000

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]

Commitments under operating lease obligations

$1,900,000

Subsequent_Events_Summary_of_s

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, USD $)	12 Months Ended
	Feb. 06, 2015
Restricted Stock Units (RSU) | 25% per year through February 6, 2019
Subsequent Event [Line Items]
Shares/Units Granted	20,900
Weighted Average Grant-Date Fair Value per Award	$31.68
Vesting percentage	25.00%
Vesting date	6-Feb-19
Restricted Stock Units (RSU) | 100% on February 6, 2020
Subsequent Event [Line Items]
Shares/Units Granted	6,400
Weighted Average Grant-Date Fair Value per Award	$31.68
Vesting percentage	100.00%
Vesting date	6-Feb-20
Stock Performance Awards | December 31, 2017
Subsequent Event [Line Items]
Shares/Units Granted	77,500
Weighted Average Grant-Date Fair Value per Award	$26.99
Vesting date	31-Dec-17

Subsequent_Events_Detail_Textu

Subsequent Events (Detail Textuals) (2014 Stock Incentive Plan)	12 Months Ended
	Feb. 06, 2015	Dec. 31, 2014
Subsequent Event [Line Items]
Target number of shares awarded		1,900,000
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	77,500
Maximum number of common shares authorized for payment	116,250
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	51,667
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 Edison Electric Institute Index over the performance measurement period of January 1, 2015 through December 31, 2017, 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, 2015 and the average closing price for the 20 trading days immediately preceding January 1, 2018.
Subsequent Event | Executive Officers | Stock Performance Awards | Performance Target Two
Subsequent Event [Line Items]
Target number of shares awarded	25,833
Basis for achieving performance target, description	Achieving the target set for the Company's 3-year average adjusted return on equity

Subsequent_Events_Detail_Textu1

Subsequent Events (Detail Textuals 1) (Subsequent Event, Aevenia, USD $)	1 Months Ended
In Millions, unless otherwise specified	Feb. 24, 2015
Subsequent Event | Aevenia
Subsequent Event [Line Items]
Proceeds from sale of Aevenia before working capital and other adjustments	$25
Consideration for sale of business, description	agreement to sell Aevenia for $25 million in cash plus adjustments for working capital and final assets to be determined within 90 days of closing

SCHEDULE_1_Condensed_Balance_S

SCHEDULE 1 Condensed Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents		$2,007	$54,749	$18,168
Deferred Income Taxes	49,482	35,325
Other	7,187	7,581
Total Current Assets	307,149	270,499
Investments in Subsidiaries	8,582	9,362
Other Assets	30,111	28,834
Total Assets	1,791,279	1,596,019	1,602,337
Current Liabilities
Other	8,793	6,532
Total Current Liabilities	201,699	236,273
Other Noncurrent Liabilities	26,794	25,209
Commitments and Contingencies
Capitalization
Long-Term Debt, Net of Current Maturities	498,489	389,589
Common Shareholder Equity	186,090	181,358
Total Capitalization	1,071,255	924,419
Total Liabilities and Equity	1,791,279	1,596,019
OTTER TAIL CORPORATION (PARENT COMPANY)
Current Assets
Cash and Cash Equivalents		7,907	44,802	7,062
Accounts Receivable from Subsidiaries	4,651	1,736
Interest Receivable from Subsidiaries	191	192
Notes Receivable from Subsidiaries	13,553	5,703
Deferred Income Taxes	13,895	28,853
Other	1,105	947
Total Current Assets	33,395	45,338
Investments in Subsidiaries	605,242	541,291
Notes Receivable from Subsidiaries	52,060	52,249
Deferred Income Taxes	36,632	25,861
Other Assets	27,365	25,456
Total Assets	754,694	690,195
Current Liabilities
Accounts Payable to Subsidiaries	5,990	5,961
Notes Payable to Subsidiaries	67,218	62,562
Other	18,371	5,122
Total Current Liabilities	91,579	73,645
Other Noncurrent Liabilities	36,860	28,031
Commitments and Contingencies
Capitalization
Long-Term Debt, Net of Current Maturities	53,489	53,689
Common Shareholder Equity	572,766	534,830
Total Capitalization	626,255	588,519
Total Liabilities and Equity	$754,694	$690,195

SCHEDULE_1_Condensed_Statement

SCHEDULE 1 Condensed Statements of Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss
Revenue	$799,262	$743,414	$710,165
Operating Expenses	699,731	649,177	615,864
Operating Loss	99,531	94,237	94,301
Other Income (Expense)
Loss on Early Retirement of Debt		-10,252	-13,106
Interest Charges	-29,648	-26,974	-31,903
Other Income	3,557	4,100	3,915
Income Before Income Taxes - Continuing Operations	73,440	61,111	53,207
Income Tax Benefit	16,557	12,516	7,173
Net Income (Loss) from Continuing Operations	56,883	48,595	46,034
Net Income (Loss) from Discontinued Operations	840	2,270	-51,307
Total Net Income (Loss)	57,723	50,865	-5,273
Income (Loss) Available for Common Shares	57,723	50,352	-6,009
OTTER TAIL CORPORATION (PARENT COMPANY)
Operating Loss
Revenue
Operating Expenses	12,593	14,150	15,197
Operating Loss	-12,593	-14,150	-15,197
Other Income (Expense)
Equity Income in Earnings of Subsidiaries	64,926	66,468	8,430
Loss on Early Retirement of Debt		-10,252	-13,106
Interest Charges	-6,326	-9,940	-13,994
Interest Charges to Subsidiaries	-117	-494	-512
Interest Income from Subsidiaries	4,980	5,318	15,700
Other Income	1,379	1,413	1,426
Total Other Income (Expense)	64,842	52,513	-2,056
Income Before Income Taxes - Continuing Operations	52,249	38,363	-17,253
Income Tax Benefit	-5,474	-12,502	-11,980
Net Income (Loss) from Continuing Operations	57,723	50,865	-5,273
Net Income (Loss) from Discontinued Operations
Total Net Income (Loss)	57,723	50,865	-5,273
Preferred Dividend Requirement and Other Adjustments		513	736
Income (Loss) Available for Common Shares	$57,723	$50,352	($6,009)

SCHEDULE_1_Condensed_Statement1

SCHEDULE 1 Condensed Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	$112,474	$147,781	$233,547
Cash Flows from Investing Activities
(Investment in Subsidiaries) Return of Capital	2,785	1,845	1,184
Net Cash (Used in) Provided by Investing Activities	-164,496	-149,197	-83,577
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	1,236
Net Short-Term Borrowings	-40,341	51,195
Proceeds from Issuance of Common Stock	26,259	1,821
Common Stock Issuance Expenses	-673	-3	-370
Payments for Retirement of Capital Stock	-590	-15,723	-111
Short-Term and Long-Term Debt Issuance Expenses	-856	-522	-897
Payments for Retirement of Long-Term Debt	-41,088	-72,981	-50,224
Premium Paid for Early Retirement of Long-Term Debt		-9,889	-12,500
Dividends Paid and Other Distributions	-44,261	-43,818	-43,976
Net Cash Used in Financing Activities	50,864	-49,020	-112,356
Net Change in Cash and Cash Equivalents	-2,007	-52,742	36,581
Cash and Cash Equivalents at Beginning of Period	2,007	54,749	18,168
Cash and Cash Equivalents at End of Period		2,007	54,749
OTTER TAIL CORPORATION (PARENT COMPANY)
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	47,697	70,376	43,904
Cash Flows from Investing Activities
(Investment in Subsidiaries) Return of Capital	-44,000	150,381	-137,726
Debt (Issued to) Repaid by Subsidiaries	-7,662	-141,919	239,452
Cash Used in Investing Activities	-44	-37	-69
Net Cash (Used in) Provided by Investing Activities	-51,706	8,425	101,657
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	215
Net Short-Term Borrowings	10,854
Borrowings from Subsidiaries	4,656
Proceeds from Issuance of Common Stock	26,259	1,821
Common Stock Issuance Expenses	-673	-3	-370
Payments for Retirement of Capital Stock	-590	-15,723	-111
Short-Term and Long-Term Debt Issuance Expenses	-170	-238	-700
Payments for Retirement of Long-Term Debt	-188	-47,846	-50,164
Premium Paid for Early Retirement of Long-Term Debt		-9,889	-12,500
Dividends Paid and Other Distributions	-44,261	-43,818	-43,976
Net Cash Used in Financing Activities	-3,898	-115,696	-107,821
Net Change in Cash and Cash Equivalents	-7,907	-36,895	37,740
Cash and Cash Equivalents at Beginning of Period	7,907	44,802	7,062
Cash and Cash Equivalents at End of Period		$7,907	$44,802

SCHEDULE_1_Related_Party_Trans

SCHEDULE 1 Related Party Transactions (Details) (OTTER TAIL CORPORATION (PARENT COMPANY), USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	$4,651	$1,736
Interest Receivable	191	192
Current Notes Receivable	13,553	5,703
Long-Term Notes Receivable	52,060	52,249
Accounts Payable	5,990	5,961
Current Notes Payable	67,218	62,562
Otter Tail Power Company
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	3,599	1,346
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable	42	11
Current Notes Payable
Vinyltech Corporation
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	2
Interest Receivable	32	32
Current Notes Receivable
Long-Term Notes Receivable	8,500	8,500
Accounts Payable
Current Notes Payable	13,995	17,285
Northern Pipe Products, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable	8	9
Current Notes Receivable
Long-Term Notes Receivable	3,360	3,549
Accounts Payable
Current Notes Payable	9,233	11,948
BTD Manufacturing, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	33	7
Interest Receivable	107	107
Current Notes Receivable
Long-Term Notes Receivable	28,500	28,500
Accounts Payable
Current Notes Payable	55	3,985
IMD, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable
Current Notes Receivable	1,602	1,266
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
Shrco, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable		2
Interest Receivable
Current Notes Receivable		3,889
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable	378
T.O. Plastics, Inc.
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable
Interest Receivable	28	28
Current Notes Receivable
Long-Term Notes Receivable	7,400	7,400
Accounts Payable		1
Current Notes Payable	6,477	4,705
Aevenia, Inc
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	86
Interest Receivable	7	7
Current Notes Receivable		548
Long-Term Notes Receivable	1,800	1,800
Accounts Payable		1
Current Notes Payable
Foley Company
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	35	44
Interest Receivable	9	9
Current Notes Receivable	11,951
Long-Term Notes Receivable	2,500	2,500
Accounts Payable
Current Notes Payable	6,004	5,343
Varistar Corporation
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	816
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable	5,948	5,948
Current Notes Payable	31,076	19,296
Otter Tail Assurance Limited
Condensed Financial Statements, Captions [Line Items]
Accounts Receivable	80	337
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable

SCHEDULE_1_Dividends_Details

SCHEDULE 1 Dividends (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Cash Dividends Paid to Parent by Subsidiaries	$44,261	$91,693	$43,018