Otter Tail (OTTR) 10-K3 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2013	Feb. 14, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'Otter Tail Corp	'	'
Entity Central Index Key	'0001466593	'	'
Trading Symbol	'ottr	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Well-Known Seasoned Issuer	'Yes	'	'
Entity Common Stock, Shares Outstanding	'	36,340,637	'
Entity Public Float	'	'	$972,636,461
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets	'	'
Cash and Cash Equivalents	$1,150	$52,362
Accounts Receivable:	'	'
Trade (less allowance for doubtful accounts of $1,177 for 2013 and $1,279 for 2012)	83,572	91,170
Other	9,790	7,684
Inventories	72,681	69,336
Deferred Income Taxes	35,452	30,964
Unbilled Revenues	18,157	15,701
Costs and Estimated Earnings in Excess of Billings	4,063	3,663
Regulatory Assets	17,940	25,499
Other	7,747	8,161
Assets of Discontinued Operations	38	19,092
Total Current Assets	250,590	323,632
Investments	9,362	9,471
Other Assets	28,834	26,222
Goodwill	38,971	38,971
Other Intangibles--Net	13,328	14,305
Deferred Debits	'	'
Unamortized Debt Expense	4,188	5,529
Regulatory Assets	83,730	134,755
Total Deferred Debits	87,918	140,284
Plant	'	'
Electric Plant in Service	1,460,884	1,423,303
Nonelectric Operations	194,872	186,094
Construction Work in Progress	187,461	77,890
Total Gross Plant	1,843,217	1,687,287
Less Accumulated Depreciation and Amortization	676,201	637,835
Net Plant	1,167,016	1,049,452
Total Assets	1,596,019	1,602,337
Current Liabilities	'	'
Short-Term Debt	51,195	'
Current Maturities of Long-Term Debt	188	176
Accounts Payable	113,457	88,406
Accrued Salaries and Wages	19,903	20,571
Billings In Excess Of Costs and Estimated Earnings	13,707	16,204
Accrued Taxes	12,491	12,047
Derivative Liabilities	11,782	18,234
Other Accrued Liabilities	6,532	6,334
Liabilities of Discontinued Operations	3,637	11,156
Total Current Liabilities	232,892	173,128
Pensions Benefit Liability	69,743	116,541
Other Postretirement Benefits Liability	45,221	58,883
Other Noncurrent Liabilities	25,209	22,244
Commitments and Contingencies (note 9)	'	'
Deferred Credits	'	'
Deferred Income Taxes	195,603	171,787
Deferred Tax Credits	28,288	31,299
Regulatory Liabilities	73,926	68,835
Other	718	466
Total Deferred Credits	298,535	272,387
Capitalization (page 74)	'	'
Long-Term Debt, Net of Current Maturities	389,589	421,680
Common Shares, Par Value $5 Per Share--Authorized, 50,000,000 Shares; Outstanding, 2013-36,271,696 Shares; 2012-36,168,368 Shares	181,358	180,842
Premium on Common Shares	255,759	253,296
Retained Earnings	99,441	92,221
Accumulated Other Comprehensive Loss	-1,728	-4,385
Total Common Equity	534,830	521,974
Total Capitalization	924,419	959,154
Total Liabilities and Equity	1,596,019	1,602,337
Cumulative Preferred Shares	'	'
Capitalization (page 74)	'	'
Cumulative Shares	'	15,500
Cumulative Preference Shares	'	'
Capitalization (page 74)	'	'
Cumulative Shares	'	'

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parentheticals) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Trade, allowance for doubtful accounts (in dollars)	$1,177	$1,279
Common Shares, Par Value (in dollars per share)	$5	$5
Common Shares, Authorized	50,000,000	50,000,000
Common Shares, Outstanding	36,271,696	36,168,368
Cumulative Preferred Shares	'	'
Cumulative Shares, Authorized	1,500,000	1,500,000
Cumulative Shares, Without Par Value	'	'
Cumulative Shares, Outstanding	'	155,000
Cumulative Preference Shares	'	'
Cumulative Shares, Authorized	1,000,000	1,000,000
Cumulative Shares, Without Par Value	'	'
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues	'	'	'
Electric	$373,459	$350,679	$342,633
Product Sales	369,952	359,474	313,020
Construction Services	149,902	149,086	184,516
Total Operating Revenues	893,313	859,239	840,169
Operating Expenses	'	'	'
Production Fuel - Electric	71,248	66,284	69,017
Purchased Power - Electric System Use	52,006	49,184	43,451
Electric Operation and Maintenance Expenses	133,395	121,069	115,863
Cost of Products Sold (depreciation included below)	283,260	270,041	248,021
Cost of Construction Revenues Earned (depreciation included below)	133,427	147,097	173,629
Other Nonelectric Expenses	51,930	52,621	49,296
Asset Impairment Charge	'	432	470
Depreciation and Amortization	59,885	59,764	58,335
Property Taxes - Electric	11,311	10,720	10,190
Total Operating Expenses	796,462	777,212	768,272
Operating Income	96,851	82,027	71,897
Interest Charges	26,978	31,905	35,629
Loss on Early Retirement of Debt	10,252	13,106	'
Other Income	4,096	4,085	2,763
Income Before Income Taxes - Continuing Operations	63,717	41,101	39,031
Income Tax Expense - Continuing Operations	13,543	2,133	4,121
Net Income from Continuing Operations	50,174	38,968	34,910
Discontinued Operations	'	'	'
Income (Loss) - net of Income Tax Expense (Benefit) of $9 in 2013, $6,231 in 2012 and ($1,811) in 2011	481	-6,603	-14,294
Impairment Loss - net of Income Tax (Benefit) of ($21,213) in 2012 and ($17,444) in 2011	'	-32,107	-42,533
Gain (Loss) on Disposition - net of Income Tax Expense of $6 in 2013, $315 in 2012 and $5,851 in 2011	210	-5,531	8,674
Net Gain (Loss) from Discontinued Operations	691	-44,241	-48,153
Total Net Income (Loss)	50,865	-5,273	-13,243
Preferred Dividend Requirement and Other Adjustments	513	736	1,058
Earnings (Loss) Available for Common Shares	$50,352	($6,009)	($14,301)
Average Number of Common Shares Outstanding--Basic (in shares)	36,151	36,048	35,922
Average Number of Common Shares Outstanding--Diluted (in shares)	36,355	36,242	36,082
Basic Earnings (Loss) Per Common Share:	'	'	'
Continuing Operations (net of preferred dividend requirement) (in dollars per share)	$1.37	$1.06	$0.95
Discontinued Operations (in dollars per share)	$0.02	($1.23)	($1.35)
Earnings Per Share, Basic, Total (in dollars per share)	$1.39	($0.17)	($0.40)
Diluted Earnings (Loss) Per Common Share:	'	'	'
Continuing Operations (net of preferred dividend requirement) (in dollars per share)	$1.37	$1.05	$0.95
Discontinued Operations (in dollars per share)	$0.02	($1.22)	($1.35)
Earnings Per Share, Diluted, Total (in dollars per share)	$1.39	($0.17)	($0.40)
Dividends Declared Per Common Share (in dollars per share)	$1.19	$1.19	$1.19

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (Parentheticals) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Income tax expense (benefit) on income from discontinued operations	$9	$6,231	($1,811)
Income tax (benefit) on impairment loss on discontinued operations	'	-21,213	-17,444
Income tax expense of (loss) gain on disposition of discontinued operations	$6	$315	$5,851

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income and Comprehensive Income [Abstract]	'	'	'
Net Income (Loss)	$50,865	($5,273)	($13,243)
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	-27	'	'
(Losses) Gains Arising During Period	-77	154	-121
Income Tax Benefit (Expense)	36	-53	48
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	-68	101	-73
Reversal of Foreign Currency Translation Adjustment Unrealized Gain:	'	'	'
Unrealized Net Change During Period	'	'	303
Reversal of Previously Recognized Gains Realized on Sale of IPH in 2011	'	'	-6,068
Income Tax Benefit	'	'	1,787
Reversal of Foreign Currency Translation Adjustment Unrealized Gain - net-of-tax	'	'	-3,978
Pension and Postretirement Benefit Plans:	'	'	'
Actuarial Gains (Losses) Net of Regulatory Allocation Adjustment	3,986	-2,133	-1,686
Amortization of Unrecognized Postretirement Benefit Costs (note 12)	555	376	239
Income Tax (Expense) Benefit	-1,816	703	579
Pension and Postretirement Benefit Plans - net-of-tax	2,725	-1,054	-868
Total Other Comprehensive Income (Loss)	2,657	-953	-4,919
Total Comprehensive Income (Loss)	$53,522	($6,226)	($18,162)

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	Common Shares	Premium On Common Shares	Retained Earnings	Accumulated Other Comprehensive Income/(Loss)		Total
Balance at Dec. 31, 2010	$180,014	$251,919	$198,443	$1,487		$631,863
Balance (in shares) at Dec. 31, 2010	36,002,739	'	'	'		'
Common Stock Issuances, Net of Expenses	771	2,671	'	'		3,442
Common Stock Issuances, Net of Expenses (in shares)	154,225	'	'	'		'
Common Stock Retirements	-276	-906	'	'		-1,182
Common Stock Retirements (in shares)	-55,269	'	'	'		'
Net Income (Loss)	'	'	-13,243	'		-13,243
Other Comprehensive Income (Loss)	'	'	'	-4,919		-4,919
Tax Benefit - Stock Compensation	'	-875	'	'		-875
Employee Stock Incentive Plan Expense	'	606	'	'		606
Premium on Purchase of Stock for Employee Purchase Plan	'	-292	'	'		-292
Premium on Purchase of Subsidiary Class B Stock and Options	'	'	-322	'		-322
Cumulative Preferred Dividends	'	'	-735	'		-735
Common Dividends ($1.19 per share)	'	'	-42,895	'		-42,895
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)	'	'	-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	'	'	'		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)	'	'	-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

[1]	Accumulated Other Comprehensive Loss on December 31 is comprised of the following:(in thousands) 2013 2012 2011 Unrealized Gain on Marketable Equity Securities: Before Tax $73 $177 $ 23 Tax Effect (26) (62) (9) Unrealized Gain on Marketable Equity Securities - Net-of-Tax 47 115 14 Unamortized Actuarial Losses, Prior Service Costs and Transition Obligation Related to Pension and Postretirement Benefits: Before Tax (2,959) (7,500) (5,743) Tax Effect 1,184 3,000 2,297 Unamortized Actuarial Losses and Transition Obligation Related to Pension and Postretirement Benefits - Net-of-Tax (1,775) (4,500) (3,446) Accumulated Other Comprehensive Loss: Before Tax (2,886) (7,323) (5,720) Tax Effect 1,158 2,938 2,288 Net Accumulated Other Comprehensive Loss $ (1,728) $ (4,385) $ (3,432)

Consolidated_Statements_of_Com2

Consolidated Statements of Common Shareholders' Equity (Parentheticals) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Accumulated Other Comprehensive Income (Loss), Before Tax	($2,886)	($7,323)	($5,720)
Accumulated Other Comprehensive Income (Loss), Tax Effect	1,158	2,938	2,288
Accumulated Other Comprehensive Income (Loss), Net of Tax	-1,728	-4,385	-3,432
Unrealized Gain On Marketable Equity Securities	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Accumulated Other Comprehensive Income (Loss), Before Tax	73	177	23
Accumulated Other Comprehensive Income (Loss), Tax Effect	-26	-62	-9
Accumulated Other Comprehensive Income (Loss), Net of Tax	47	115	14
Unamortized Actuarial Losses and Transition Obligation Related To Pension and Postretirement Benefits	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Accumulated Other Comprehensive Income (Loss), Before Tax	-2,959	-7,500	-5,743
Accumulated Other Comprehensive Income (Loss), Tax Effect	1,184	3,000	2,297
Accumulated Other Comprehensive Income (Loss), Net of Tax	($1,775)	($4,500)	($3,446)

Consolidated_Statements_of_Com3

Consolidated Statements of Common Shareholders' Equity (Parentheticals 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Stockholders' Equity [Abstract]	'	'	'
Dividends Declared Per Common Share (in dollars per share)	$1.19	$1.19	$1.19

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities	'	'	'
Net Income (Loss)	$50,865	($5,273)	($13,243)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:	'	'	'
Net (Gain) Loss from Sale of Discontinued Operations	-210	5,531	-8,674
Net (Income) Loss from Discontinued Operations	-481	38,710	56,827
Depreciation and Amortization	59,885	59,764	58,335
Asset Impairment Charge	'	432	470
Premium Paid for Early Retirement of Long-Term Debt	9,889	12,500	'
Deferred Tax Credits	-1,925	-2,091	-2,386
Deferred Income Taxes	15,902	11,459	10,661
Change in Deferred Debits and Other Assets	56,720	-4,802	-25,053
Discretionary Contribution to Pension Fund	-10,000	-10,000	'
Change in Noncurrent Liabilities and Deferred Credits	-42,226	32,718	35,178
Allowance for Equity/Other Funds Used During Construction	-1,823	-1,168	-861
Change in Derivatives Net of Regulatory Deferral	8	718	72
Stock Compensation Expense - Equity Awards	1,456	1,311	2,177
Other-Net	641	4,500	6,496
Cash Provided by (Used for) Current Assets and Current Liabilities:	'	'	'
Change in Receivables	8,335	2,430	-7,952
Change in Inventories	-3,345	-687	-5,286
Change in Other Current Assets	-4,216	7,019	-1,072
Change in Payables and Other Current Liabilities	11,321	30,056	-4,775
Change in Interest Payable and Income Taxes Receivable/Payable	-513	-14,141	-7,236
Net Cash Provided by Continuing Operations	150,283	168,986	93,678
Net Cash (Used in) Provided by Discontinued Operations	-2,502	64,561	10,705
Net Cash Provided by Operating Activities	147,781	233,547	104,383
Cash Flows from Investing Activities	'	'	'
Capital Expenditures	-164,463	-115,762	-67,360
Proceeds from Disposal of Noncurrent Assets	3,764	4,889	1,923
Net Increase in Other Investments	-1,845	-1,037	-40
Net Cash Used in Investing Activities - Continuing Operations	-162,544	-111,910	-65,477
Net Proceeds from Sale of Discontinued Operations	12,842	42,229	107,310
Net Cash Provided by (Used in) Investing Activities - Discontinued Operations	505	-13,896	-36,410
Net Cash (Used in) Provided by Investing Activities	-149,197	-83,577	5,423
Cash Flows from Financing Activities	'	'	'
Change in Checks Written in Excess of Cash	'	'	-7,268
Net Short-Term Borrowings (Repayments)	51,195	'	-79,490
Proceeds from Issuance of Common Stock	1,821	'	'
Common Stock Issuance Expenses	-3	-370	'
Payments for Retirement of Capital Stock	-15,723	-111	-1,182
Proceeds from Issuance of Long-Term Debt	40,900	'	142,006
Short-Term and Long-Term Debt Issuance Expenses	-522	-897	-1,666
Payments for Retirement of Long-Term Debt	-72,981	-50,224	-100,796
Premium Paid for Early Retirement of Long-Term Debt	-9,889	-12,500	'
Dividends Paid and Other Distributions	-43,818	-43,976	-43,923
Net Cash Used in Financing Activities - Continuing Operations	-49,020	-108,078	-92,319
Net Cash Used in Financing Activities - Discontinued Operations	'	-4,278	-3,184
Net Cash Used in Financing Activities	-49,020	-112,356	-95,503
Net Change in Cash and Cash Equivalents - Discontinued Operations	-776	-1,246	2,015
Effect of Foreign Exchange Rate Fluctuations on Cash - Discontinued Operations	'	'	-324
Net Change in Cash and Cash Equivalents	-51,212	36,368	15,994
Cash and Cash Equivalents at Beginning of Period	52,362	15,994	'
Cash and Cash Equivalents at End of Period	$1,150	$52,362	$15,994

Consolidated_Statements_of_Cap

Consolidated Statements of Capitalization (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Capitalization [Line Items]	'	'
Short-Term Debt	$51,195	'
Long-Term Debt	389,778	421,860
Less: Current Maturities - Otter Tail Corporation	188	176
Unamortized Debt Discount - Otter Tail Corporation	1	4
Total Long-Term Debt	389,589	421,680
Total Common Shareholders' Equity	534,830	521,974
Total Capitalization	924,419	959,154
Cumulative Preferred Shares	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	15,500
Cumulative Preferred Shares \| Series 3.60	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	6,000
Cumulative Preferred Shares \| Series 4.40	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	2,500
Cumulative Preferred Shares \| Series 4.65	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	3,000
Cumulative Preferred Shares \| Series 6.75	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	4,000
Cumulative Preference Shares	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	'
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	100,000
North Dakota Development Note, 3.95%, due April 1, 2018	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	325	393
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	1,223	1,332
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'
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
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	'	5,065
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
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	'	20,070
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 6.47%, Series D, due August 20, 2037	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	50,000	50,000
OTTER TAIL CORPORATION	'	'
Schedule of Capitalization [Line Items]	'	'
Short-Term Debt	'	'
Long-Term Debt	53,878	101,725
Less: Current Maturities - Otter Tail Corporation	188	176
Unamortized Debt Discount - Otter Tail Corporation	1	4
Total Long-Term Debt	53,689	101,545
Total Capitalization	588,519	639,019
OTTER TAIL CORPORATION \| Cumulative Preferred Shares	'	'
Schedule of Capitalization [Line Items]	'	'
Cumulative Shares	'	15,500
OTTER TAIL CORPORATION \| 9.000% Notes, due December 15, 2016	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	52,330	100,000
OTTER TAIL CORPORATION \| North Dakota Development Note, 3.95%, due April 1, 2018	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	325	393
OTTER TAIL CORPORATION \| Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	1,223	1,332
Otter Tail Power Company	'	'
Schedule of Capitalization [Line Items]	'	'
Short-Term Debt	51,195	'
Long-Term Debt	335,900	320,135
Less: Current Maturities - Otter Tail Corporation	'	'
Unamortized Debt Discount - Otter Tail Corporation	'	'
Total Long-Term Debt	335,900	320,135
Otter Tail Power Company \| Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'
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 \| Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	'	5,065
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 \| Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	'	20,070
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 6.47%, Series D, due August 20, 2037	'	'
Schedule of Capitalization [Line Items]	'	'
Long-Term Debt	$50,000	$50,000

Consolidated_Statements_of_Cap1

Consolidated Statements of Capitalization (Parentheticals) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Apr. 06, 2011

Mar. 18, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

9.000% Notes, due December 15, 2016

North Dakota Development Note, 3.95%, due April 1, 2018

Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021

Senior Unsecured Notes 5.95%, Series A, due August 20, 2017

Senior Unsecured Notes 4.63%, due December 1, 2021

Senior Unsecured Notes 6.15%, Series B, due August 20, 2022

Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022

Senior Unsecured Notes 6.37%, Series C, due August 20, 2027

Senior Unsecured Notes 6.47%, Series D, due August 20, 2037

Cumulative Preferred Shares

Cumulative Preference Shares

Series 3.60

Series 4.40

Series 4.65

Series 6.75

OTTER TAIL CORPORATION

Otter Tail Power Company

Cumulative Preferred Shares

9.000% Notes, due December 15, 2016

North Dakota Development Note, 3.95%, due April 1, 2018

Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021

Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015

Senior Unsecured Notes 6.63%, due December 1, 2011

Senior Unsecured Notes 5.95%, Series A, due August 20, 2017

Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017

Senior Unsecured Notes 4.63%, due December 1, 2021

Senior Unsecured Notes 6.15%, Series B, due August 20, 2022

Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022

Senior Unsecured Notes 6.37%, Series C, due August 20, 2027

Senior Unsecured Notes 6.47%, Series D, due August 20, 2037

Schedule of Capitalization [Line Items]

Long-Term Debt, Interest Rate

9.00%

3.95%

2.54%

5.95%

4.63%

6.15%

4.85%

6.37%

6.47%

9.00%

3.95%

2.54%

0.88%

5.95%

4.65%

4.63%

6.15%

4.85%

6.37%

6.47%

Long-Term Debt, Due Date

15-Dec-16

1-Apr-18

18-Mar-21

20-Aug-17

1-Dec-21

20-Aug-22

1-Sep-22

20-Aug-27

20-Aug-37

15-Dec-16

1-Apr-18

18-Mar-21

15-Jan-15

20-Aug-17

1-Sep-17

1-Dec-21

20-Aug-22

1-Sep-22

20-Aug-27

20-Aug-37

Debt Instrument Retirement Date

1-Mar-13

Cumulative Shares, Without Par Value

Cumulative Shares, Stated Value per Share

$100

Cumulative Shares, Liquidating Value per Share

$100

Cumulative Shares, Authorized

1,500,000

1,000,000

Cumulative Shares, Outstanding

155,000

60,000

25,000

30,000

40,000

Cumulative Shares, Price Per Share

$3.60

$4.40

$4.65

$6.75

Cumulative Shares, Redemption Date

1-Mar-13

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2013
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, Plastics and Construction. See note 2 to the 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 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 $1,002,000 in 2013, $656,000 in 2012 and $628,000 in 2011. 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 2.96% in 2013, 2.98% in 2012 and 2.94% in 2011. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

	Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination accounted for under the purchase method of accounting, 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 2013, 2012 or 2011. 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, 2013 and 2012 consolidated balance sheets:

	(in thousands)		2013				2012
	Big Stone Plant:
	Electric Plant in Service		$	142,780			$	141,221
	Construction Work in Progress			94,913				22,335
	Accumulated Depreciation			(83,005	)			(80,588	)
	Net Plant		$	154,688			$	82,968
	Coyote Station:
	Electric Plant in Service		$	162,095			$	160,617
	Construction Work in Progress			303				578
	Accumulated Depreciation			(96,907	)			(93,564	)
	Net Plant		$	65,491			$	67,631

	OTP is a joint owner, with other regional utilities, in three Capacity Expansion 2020 (CapX2020) transmission lines with the following ownership interests: 14.8% in the Bemidji-Grand Rapids 230 kV line, 13.3% in the Fargo-Monticello 345 kV line, 4.9% 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 49.2% 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, 2013 and 2012 consolidated balance sheets:

	(in thousands)		2013				2012
	Electric Plant in Service		$	26,337			$	25,852
	Construction Work in Progress			71,205				30,171
	Accumulated Depreciation			(837	)			(483	)
	Net Plant		$	96,705			$	55,540

	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 the 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. Therefore, CCMC is not required to be consolidated in the Company’s 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, 2013 is $10.2 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, 2013 could be as high as $10.2 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 the fourth quarter of 2011, IMD, Inc. (IMD), the Company’s former wind tower manufacturer, recorded a $3.1 million asset impairment charge on its plant in Fort Erie, Ontario. IMD idled this plant in the fourth quarter of 2011, as the plant had completed all of its then current tower orders.

	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 sale of the Fort Erie fixed assets closed on September 6, 2012, the West Fargo transaction closed on October 31, 2012 and the Tulsa transaction closed on November 30, 2012.

	Otter Tail Energy Services Company (OTESCO) recorded asset impairment charges of $0.4 million in 2012 and $0.5 million in 2011 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 15 to the 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.

Revisions to Presentation
Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the years 2012 and 2011 were revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for 2013. The change in presentation of 2012 and 2011 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for 2012 or 2011.

Revenue Recognition
Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as 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.

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 for further discussion.

Manufacturing operating revenues are recorded when products are shipped.

The companies in the Construction segment 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. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

		2013				2012				2011
Percentage-of-Completion Revenues			16.70%				17.00%				21.40%

The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

		December 31,				December 31,
(in thousands)		2013				2012
Costs Incurred on Uncompleted Contracts		$	361,487			$	307,085
Less Billings to Date			(377,608	)			(321,388	)
Plus Estimated Earnings Recognized			6,477				1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	(9,644	)		$	(12,541	)

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:

		December 31,				December 31,
(in thousands)		2013				2012
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts		$	4,063			$	3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts			(13,707	)			(16,204	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	(9,644	)		$	(12,541	)

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 pretax charges of $0.6 million in 2013 compared with $14.9 million in 2012 and $7.0 million in 2011.

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, 2013 and December 31, 2012 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 17 to consolidated financial statements.

Retainage
Accounts Receivable 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)		2013				2012
Accounts Receivable Retained by Customers		$	7,125	1		$	12,227
1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

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, 2013 and 2012:

		December 31,				December 31,
(in thousands)		2013				2012
Cost Method:
Portion of IPH Sales Proceeds Held in Escrow Account1		$	--			$	1,500
Economic Development Loan Pools			219				255
Other			158				174
Equity Method:
Affordable Housing and Other Partnerships			43				117
Marketable Securities Classified as Available-for-Sale			8,942				8,925
Total Investments		$	9,362			$	10,971
Less: IPH Escrow Funds Reported under Other Current Assets1			--				(1,500	)
Investments		$	9,362			$	9,471
1$1.5 million accessible within one year is classified and reported under other current assets.

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, 2013. See further discussion below and under note 13.

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, 2013 and December 31, 2012:

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 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

December 31, 2012 (in thousands)		Level 1				Level 2				Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts		$	--			$	292			$	210
Forward Gasoline Purchase Contracts							136
Money Market Fund - Escrow Account IPH Sale			1,500
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			110
Investments:
Corporate Debt Securities – Held by Captive Insurance Company							7,620
U.S. Government Debt Securities – Held by Captive Insurance Company							1,305
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			357
Equity Securities - Nonqualified Retirement Savings Plan			125
Total Assets		$	2,092			$	9,353			$	210
Liabilities:
Derivative Liabilities - Forward Energy Contracts		$	--			$	242			$	17,992
Total Liabilities		$	--			$	242			$	17,992

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 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, 2013 and December 31, 2012, are based on prices indexed to observable prices at an active trading hub. The Level 3 forward electric price inputs ranged from $6.95 per megawatt-hour under the active trading hub price to $3.11 per megawatt-hour over the active trading hub price. The weighted average price was $34.00 per megawatt-hour.

In the table above, $117,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $11,679,000 of the fair value of the Level 3 forward energy contracts in a derivative liability position as of December 31, 2013 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, 2013 and 2012.

The remaining $221,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $103,000 of the fair value of the Level 2 forward energy contracts in a derivative liability position as of December 31, 2013 are related to financial contracts that will not be settled by physical delivery of electricity but will be settled financially by the counterparty to the contract paying or receiving the difference between the contract price and the market price at the hour of scheduled delivery. Although the related forward energy purchase and sales contracts are 100% offsetting in terms of volumes and delivery periods, the purchase contracts and offsetting sales contracts do not have the same delivery points. Therefore, the net derivative gain related to these contracts of $118,000 as of December 31, 2013 is subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in January and February of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the net fair value of the contracts.

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, 2013 and 2012:

(in thousands)		2013				2012
Forward Energy Contracts - Fair Values Beginning of Period		$	(17,782	)		$	--
Transfers into Level 3 from Level 2			--				(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods			7,943				5,135
Changes in Fair Value of Contracts Entered into in Prior Periods			(640	)			(4,001	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period			(10,479	)			(14,750	)
Net Decrease in Value of Open Contracts Entered into in Current Period			(862	)			(3,032	)
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period		$	(11,341	)		$	(17,782	)

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)		2013				2012
Finished Goods		$	20,649			$	21,893
Work in Process			9,942				8,800
Raw Material, Fuel and Supplies			42,090				38,643
Total Inventories		$	72,681			$	69,336

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.

The following tables summarize changes to goodwill by business segment during 2013 and 2012:

		Gross Balance				Accumulated				Balance (net of				Adjustments			Balance (net of
(in thousands)		December 31,				Impairments				impairments)				to Goodwill			impairments)
		2012								December 31,				in 2013			December 31,
										2012							2013
Manufacturing		$	12,186			$	--			$	12,186			$	--		$	12,186
Construction			7,483				--				7,483				--			7,483
Plastics			19,302				--				19,302				--			19,302
Total		$	38,971			$	--			$	38,971			$	--		$	38,971

		Gross Balance				Accumulated				Balance (net of				Adjustments			Balance (net of
(in thousands)		December 31,				Impairments				impairments)				to Goodwill			impairments)
		2011								December 31,				in 2012			December 31,
										2011							2012
Electric		$	240			$	(240	)		$	--			$	--		$	--
Manufacturing			24,445				(12,259	)			12,186				--			12,186
Construction			7,630				--				7,630				(147	)		7,483
Plastics			19,302				--				19,302				--			19,302
Total		$	51,617			$	(12,499	)		$	39,118			$	(147	)	$	38,971

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:

2013 (in thousands)		Gross Carrying				Accumulated Amortization				Net Carrying			Amortization
2013 (in thousands)		Amount				Accumulated Amortization				Amount			Periods
Amortizable Intangible Assets:
Customer Relationships		$	16,811			$	4,935			$	11,876		15 – 25 years
Other Intangible Assets Including Contracts			825				473				352		5 – 30 years
Total		$	17,636			$	5,408			$	12,228
Indefinite-Lived Intangible Assets:
Trade Name		$	1,100				--			$	1,100

2012 (in thousands)
Amortizable Intangible Assets:
Customer Relationships		$	16,811			$	4,085			$	12,726		15 – 25 years
Other Intangible Assets Including Contracts			1,092				613				479		5 – 30 years
Total		$	17,903			$	4,698			$	13,205
Indefinite-Lived Intangible Assets:
Trade Name		$	1,100				--			$	1,100

The amortization expense for these intangible assets was:

(in thousands)		2013				2012				2011
Amortization Expense – Intangible Assets		$	977			$	981			$	956

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)		2014				2015				2016				2017			2018
Estimated Amortization Expense – Intangible Assets		$	977			$	977			$	945			$	849		$	849

Supplemental Disclosures of Cash Flow Information

		As of December 31,
(in thousands)		2013				2012
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1		$	22,951			$	9,967
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2		$	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)		2013				2012				2011
Cash Paid (Received) During the Year for:
Interest (net of amount capitalized)		$	26,789			$	30,741			$	34,434
Income Tax Refunds		$	(453	)		$	(353	)		$	(257	)

New Accounting Standards

Accounting Standards Update (ASU) 2011-11 and 2013-01
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), to clarify which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The amendments in ASU 2013-01 apply to derivatives accounted for in accordance with ASC 815 and clarify that only derivatives accounted for in accordance with ASC 815 are within the scope of the disclosure requirements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.

The Company implemented the disclosure guidance January 1, 2013. While certain of the Company’s offsetting derivative asset and liability positions related to forward energy contracts with the same counterparty are subject to legally enforceable netting arrangements, the Company does not present its derivative assets and liabilities subject to legally enforceable netting arrangements, or any related payables or receivables, on a net basis on the face of its consolidated balance sheet. The Company has added disclosures and a table in note 5 to the consolidated financial statements indicating the amounts of its derivative forward energy contracts presented at fair value in accordance with ASC 815 that are subject to legally enforceable netting arrangements.

ASU 2013-02
In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, which requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under accounting principles generally accepted in the United States of America (U.S. GAAP) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail on these amounts. This ASU is effective for reporting periods beginning after December 15, 2012. Additional information required by this update is included on the face of the Company’s consolidated statement of comprehensive income for the period ending December 31, 2013. The amounts of accumulated other comprehensive losses associated with the Company’s pension and other post-retirement benefit programs that are being amortized and recognized as operating expenses and the income statement line item affected by the expense are disclosed in note 12 to the consolidated financial statements.

Business_Combinations_Disposit

Business Combinations, Dispositions and Segment Information	12 Months Ended
Business Combinations, Dispositions and Segment Information	Dec. 31, 2013
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 2013, 2012 or 2011.

	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, 2012 and 2011. 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. In 2011, the Company sold Idaho Pacific Holdings, Inc. (IPH), its food ingredient processing business, eliminating its Food Ingredient Processing segment, and E.W. Wylie (Wylie), its trucking company, which was included in its Wind Energy segment.

	The results of operations of Shrco including Aviva, IMD, DMS, Wylie and IPH are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years ended December 31, 2013, 2012 and 2011, and are summarized in note 17 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 four segments: Electric, Manufacturing, Plastics and Construction. 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. Additionally, the electric segment includes OTESCO, which provided technical and engineering services through December 31, 2012. OTESCO ceased operations and did not record any operating revenues, expenses or net income in 2013.

	Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping and fabrication, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Illinois and Minnesota and sell products primarily in the United States.

	Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

	Construction consists of businesses involved in commercial and industrial electric contracting and construction of fiber optic, electric distribution, water, wastewater and HVAC systems primarily in the central 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 2013, 2012 or 2011. 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:		2013				2012				2011
	United States of America			97.6	%			97.7	%			98.1	%
	Mexico			1.4	%			1	%			0.4	%
	Canada			0.9	%			1.1	%			1.4	%
	All Other Countries (none greater than 0.04%)			0.1	%			0.2	%			0.1	%

	The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information on continuing operations for the business segments for 2013, 2012 and 2011 is presented in the following table:

	(in thousands)		2013				2012				2011
	Operating Revenue
	Electric		$	373,540			$	350,765			$	342,727
	Manufacturing			204,997				208,965				189,459
	Plastics			164,957				150,517				123,669
	Construction			149,910				149,092				184,657
	Intersegment Eliminations			(91	)			(100	)			(343	)
	Total		$	893,313			$	859,239			$	840,169
	Cost of Products Sold and Cost of Construction Revenues Earned
	Manufacturing		$	154,235			$	157,437			$	144,987
	Plastics			129,042				112,662				103,131
	Construction			133,430				147,107				173,654
	Intersegment Eliminations			(20	)			(68	)			(122	)
	Total		$	416,687			$	417,138			$	421,650
	Other Nonelectric Expenses
	Manufacturing		$	18,820			$	18,233			$	16,524
	Plastics			8,571				8,784				6,210
	Construction			11,855				12,353				11,886
	Corporate			12,755				13,283				14,897
	Intersegment Eliminations			(71	)			(32	)			(221	)
	Total		$	51,930			$	52,621			$	49,296
	Depreciation and Amortization
	Electric		$	43,125			$	42,051			$	40,283
	Manufacturing			11,194				12,208				12,116
	Plastics			3,350				3,118				3,377
	Construction			2,009				1,906				2,009
	Corporate			207				481				550
	Total		$	59,885			$	59,764			$	58,335
	Operating Income (Loss)
Electric		$	62,455			$	61,025			$	63,453
Manufacturing			20,748				21,087				15,832
Plastics			23,994				25,953				10,951
Construction			2,616				(12,274	)			(2,892	)
Corporate			(12,962	)			(13,764	)			(15,447	)
Total		$	96,851			$	82,027			$	71,897
Interest Charges
Electric		$	17,461			$	19,049			$	19,643
Manufacturing			3,255				3,557				3,727
Plastics			1,001				2,519				1,525
Construction			456				1,039				947
Corporate and Intersegment Eliminations			4,805				5,741				9,787
Total		$	26,978			$	31,905			$	35,629


(in thousands)		2013				2012				2011
Income Tax Expense (Benefit) – Continuing Operations
Electric		$	9,278			$	5,862			$	6,683
Manufacturing			6,047				6,954				3,962
Plastics			9,249				9,393				3,653
Construction			850				(5,456	)			(1,484	)
Corporate			(11,881	)			(14,620	)			(8,693	)
Total		$	13,543			$	2,133			$	4,121
Earnings (Loss) Available for Common Shares
Electric		$	38,236			$	38,341			$	38,886
Manufacturing			11,457				10,676				8,229
Plastics			13,809				14,113				5,811
Construction			1,310				(7,689	)			(2,204	)
Corporate			(15,151	)			(17,209	)			(16,548	)
Discontinued Operations			691				(44,241	)			(48,475	)
Total		$	50,352			$	(6,009	)		$	(14,301	)
Capital Expenditures
Electric		$	149,467			$	101,919			$	49,707
Manufacturing			7,046				9,311				10,546
Plastics			3,273				2,819				2,414
Construction			4,630				1,576				2,645
Corporate			47				137				2,048
Total		$	164,463			$	115,762			$	67,360
Identifiable Assets
Electric		$	1,290,416			$	1,226,145			$	1,170,449
Manufacturing			119,302				114,933				124,872
Plastics			76,853				78,855				72,200
Construction			49,440				50,696				69,453
Corporate			59,970				112,616				53,619
Assets of Discontinued Operations			38				19,092				209,929
Total		$	1,596,019			$	1,602,337			$	1,700,522

Rate_and_Regulatory_Matters

Rate and Regulatory Matters	12 Months Ended
Rate and Regulatory Matters	Dec. 31, 2013
Rate and Regulatory Matters [Abstract]	'
Rate and Regulatory Matters	'
	3. Rate and Regulatory Matters

	Minnesota

	2010 General Rate Case—OTP filed a general rate case on April 2, 2010 requesting an 8.01% base rate increase as well as a 3.8% interim rate increase. On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates, and approving the interim rate increase, as requested, to be effective with customer usage on and after June 1, 2010. The MPUC held a hearing to decide on the issues in the rate case on March 25, 2011 and issued a written order on April 25, 2011. The MPUC authorized a revenue increase of approximately $5.0 million, or 3.76% in base rate revenues, excluding the effect of moving recovery of wind investments to base rates. 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. Final rates went into effect October 1, 2011. The overall increase to customers was approximately 1.6% compared to the authorized interim rate increase of 3.8%, which resulted in an interim rate refund to Minnesota retail electric customers of approximately $3.9 million in the fourth quarter of 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%. OTP’s authorized rates of return are based on a capital structure of 48.28% long term debt and 51.72% common equity.

	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, a new standard established by the 2013 legislature requires 1.5% of total electric sales to be supplied by solar energy by the year 2020. OTP is currently evaluating the new legislation and 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 renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. 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. A request for an updated rate to be effective October 1, 2012 was initially filed on June 28, 2012, followed by a revised filing on July 25, 2012. Because the request to extend the period of the new rate for 18 months was still under review, a supplemental filing was submitted on February 15, 2013, requesting that the current rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the February 15, 2013 request on April 4, 2013 and authorized that any 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.

	Transmission Cost Recovery (TCR) Rider—In addition to the MNRRA rider, the Minnesota Public Utilities 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 2013 legislature passed legislation that 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.

	OTP requested recovery of its transmission investments being recovered through its Minnesota TCR rider rate as part of its general rate case filed on April 2, 2010. In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs then being recovered through OTP’s Minnesota TCR rider to recovery in base rates. Final rates went into effect on October 1, 2011. OTP continues to utilize the TCR rider cost recovery mechanism to recover the remaining balance of current transmission projects and to recover costs associated with new transmission projects determined eligible for TCR rider recovery by the MPUC.

	OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. In this TCR rider update, the MPUC addressed how to handle utility investments in transmission facilities that qualify for regional cost allocation under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from the other MISO utilities. On March 26, 2012 the MPUC approved the 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 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. On January 30, 2014 the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal labor costs and costs in excess of CON estimates in the TCR rider. These costs will be removed from OTP’s Minnesota TCR rider effective as of the date of the MPUC order. OTP will be allowed to seek recovery of these costs in a future rate case. OTP had a regulatory liability of $0.7 million as of December 31, 2013 for amounts billed to Minnesota customers that are subject to refund through the Minnesota TCR rider.

	Environmental Cost Recovery (ECR) Rider—On January 14, 2011 OTP filed a petition asking the MPUC for Advance Determination of Prudence (ADP) for costs associated with the design, construction and operation of the Best-Available Retrofit Technology (BART) compliant air quality control system at Big Stone Plant attributable to serving OTP’s Minnesota customers, and on December 20, 2011 the MPUC granted OTP’s petition for ADP for the Big Stone Plant air quality control system (AQCS). The MPUC written order was issued on January 23, 2012. 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 July 31, 2013 OTP filed for a Minnesota ECR rider with the MPUC for recovery of its Minnesota jurisdictional share of the revenue requirements of its investment in the AQCS under construction at Big Stone Plant. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance. The MPUC granted approval of OTP’s Minnesota ECR rider on December 18, 2013 with an effective date of January 1, 2014. The rate will be updated in an annual filing with the MPUC until the costs are rolled into base rates at an undetermined future date.

	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 Next Generation Energy Act of 2007, passed by the Minnesota legislature in May 2007, transitions from a conservation spending goal to a conservation energy savings goal.

	The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.

	On January 11, 2012 the MPUC approved 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 kilowatt-hour (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.

	OTP had a regulatory asset of $8.9 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, 2013. OTP’s Minnesota conservation recoverable costs and incentives totaled $9.3 million in 2013, $7.8 million in 2012 and $8.0 million in 2011.

	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. OTP’s 2010 NDRRA was in place from September 1, 2010 through March 31, 2012 with a recovery of $15.6 million. 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 and, on July 10, 2013, the NDPSC approved the rate implemented on April 1, 2013. OTP submitted its annual update to the NDRRA on December 31, 2013 with a proposed April 1, 2014 effective date. OTP has a regulatory asset of $0.5 million for amounts eligible for recovery through the NDRRA rider that had not been billed to North Dakota customers as of December 31, 2013.

	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. OTP has a regulatory liability of $0.2 million as of December 31, 2013 for amounts billed to North Dakota customers that are subject to refund through the North Dakota TCR rider.

	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 carrying costs 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. OTP had a regulatory asset of $2.3 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, 2013. The ECR rider rate will be updated at least annually in a filing with the NDPSC until the project costs are rolled into base rates at an undetermined future date.

	South Dakota

	2010 General Rate Case—On April 21, 2011 the SDPUC issued a written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50% for the interim rates and final rates for OTP in South Dakota. 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. On September 4, 2012 OTP filed its annual update to the South Dakota TCR rider. Updated rates, approved on April 23, 2013, went into effect on May 1, 2013. OTP filed its annual update to the South Dakota TCR rider on August 30, 2013 with a supplemental filing made in February 2014 with a proposed implementation date of March 1, 2014.

	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. Instead of receiving rider recovery on the portion of AQCS construction costs assignable to OTP’s South Dakota customers while the project is under construction, OTP will accrue an Allowance for Funds Used During Construction (AFUDC) on these costs and request recovery of, and a return on, the accumulated costs, including AFUDC, in a future rate filing in South Dakota.

	Federal

	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 invested.

	On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in MISO called Multi-Value Projects (MVP). 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 October 7, 2013 certain parties submitted a petition for writ of certiorari to the U.S. Supreme Court seeking review of the Seventh Circuit decision. The U.S. Supreme Court had not acted on the request as of February 14, 2014.

	On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint at 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%. MISO and a group of MISO transmission owners have filed responses to the complaint seeking its dismissal and defending the current return on equity. The complaint is pending at the FERC.

	Effective January 1, 2012 the FERC authorized OTP to recover 100% 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.

	The Big Stone South – Brookings Project—This planned 345 kiloVolt (kV) transmission line will extend 70 miles between a proposed substation near Big Stone City, South Dakota and the new Brookings County Substation near Brookings, South Dakota. OTP is jointly developing this project with Xcel Energy. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. A portion of this line is anticipated to use previously obtained Big Stone II transmission route permits and easements and is expected to be in service in the fourth quarter of 2017. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP. In December 2012, a request was filed with the SDPUC for recertification of a portion of the line route that was approved as part of the Big Stone II transmission development. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. OTP and Xcel Energy jointly submitted an application to the SDPUC for a route permit for the southern portion of the Big Stone South to Brookings line on June 3, 2013. A decision on the permit application for the southern half of this route is expected in the first quarter of 2014.

	The Big Stone South – Ellendale Project—This transmission line is a proposed 345 kV 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 the ten miles of the proposed line to be built in North Dakota. A joint route permit application was filed by OTP and MDU on August 23, 2013 with the SDPUC. OTP and MDU jointly filed an Application for a Certificate of Corridor Compatibility along with an application for a route permit with the NDPSC on October 18, 2013. If the proposed project receives all the necessary approvals, OTP anticipates the line will be placed in service in the fourth quarter of 2019.

CapX2020

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 kiloVolt 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 will be through the MISO Tariff (the Brookings Project as an MVP) and Minnesota, North Dakota and South Dakota TCR Riders.

The Fargo Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Fargo Project. The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. Construction is underway for the remaining portions of the project, with completion scheduled for second quarter 2015.

The Brookings Project—All major permits have been received from state regulatory bodies and project agreements have been signed for the construction of the Brookings Project. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. This project is anticipated to be completed in the first quarter of 2015.

The Bemidji Project—The Bemidji-Grand Rapids transmission line was fully energized and put into service on September 17, 2012.

Big Stone Plant AQCS

The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant is subject to BART requirements of the Clean Air Act (CAA), based on air dispersion modeling indicating that Big Stone’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan. Under the U.S. Environmental Protection Agency’s (EPA) regional haze regulations, South Dakota developed and submitted its implementation plan and associated implementation rules to the EPA on January 21, 2011. The DENR and the EPA have agreed on non-substantive rule revisions, which were adopted by the Board of Minerals and Environment and became effective on September 19, 2011.

South Dakota developed and submitted its revised implementation plan and associated implementation rules to the EPA on September 19, 2011. Under the South Dakota implementation plan, and its implementing rules, the Big Stone Plant must install and operate a new BART compliant AQCS to reduce emissions as expeditiously as practicable, but no later than five years after the EPA’s approval of South Dakota’s implementation plan. On March 29, 2012 the EPA took final action to approve South Dakota’s Regional Haze State Implementation Plan (SIP), finding that South Dakota’s SIP submittal met all applicable regional haze regulations. The EPA’s final approval of the SIP was effective on May 29, 2012.

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.

Minnesota—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 (which excluded $3.2 million of transmission-related project costs). Because OTP will not 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 980 accounting requirements.

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 in the first quarter of 2013. The remaining costs, along with accumulated AFUDC, were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota regulatory asset account in May 2013, based on recovery granted in the April 25, 2011 order. Because OTP will not 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 of $2.8 million 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. The amount of the discount is expected to be recovered, along with the remaining balance of the Big Stone II Unrecovered Project Costs – Minnesota regulatory asset, over an anticipated 89-month recovery period which began in May 2013.

North Dakota—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 is including 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 begins based on OTP’s average 2009 AFUDC rate of 7.65%. Because OTP will 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 is being 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.

South Dakota—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 long-term regulatory asset account.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
Regulatory Assets and Liabilities	Dec. 31, 2013
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:

												Remaining
			31-Dec-13									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.

												Remaining
			31-Dec-12									Recovery/
	(in thousands)		Current			Long-Term			Total			Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1		$	8,411		$	109,538		$	117,949		see note
	Deferred Marked-to-Market Losses1			7,949			10,050			17,999		72 months
	Conservation Improvement Program Costs and Incentives2			3,707			2,560			6,267		18 months
	Accumulated ARO Accretion/Depreciation Adjustment1			--			4,137			4,137		asset lives
	Debt Reacquisition Premiums1			268			1,978			2,246		237 months
	Big Stone II Unrecovered Project Costs – Minnesota1			526			1,618			2,144		45 months
	Recoverable Fuel and Purchased Power Costs1			1,737			--			1,737		12 months
	Deferred Income Taxes1			--			1,691			1,691		asset lives
	North Dakota Renewable Resource Rider Accrued Revenues2			532			1,087			1,619		15 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1			--			1,352			1,352		see note
	Minnesota Renewable Resource Rider Accrued Revenues2			915			--			915		5 months
	Big Stone II Unrecovered Project Costs – North Dakota1			908			--			908		7 months
	Big Stone II Unrecovered Project Costs – South Dakota2			100			711			811		97 months
	General Rate Case Recoverable Expenses1			279			6			285		13 months
	North Dakota Transmission Rider Accrued Revenues2			110			--			110		12 months
	Deferred Holding Company Formation Costs1			55			27			82		18 months
	South Dakota Transmission Rider Accrued Revenue2			2			--			2		12 months
	Total Regulatory Assets		$	25,499		$	134,755		$	160,254
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		$	--		$	65,960		$	65,960		asset lives
Deferred Income Taxes			--			2,553			2,553		asset lives
Minnesota Transmission Rider Accrued Refund			489			--			489		12 months
Deferred Marked-to-Market Gains			8			210			218		68 months
Deferred Gain on Sale of Utility Property – Minnesota Portion			6			112			118		252 months
South Dakota – Nonasset-Based Margin Sharing Excess			56			--			56		12 months
Total Regulatory Liabilities		$	559		$	68,835		$	69,394
Net Regulatory Asset Position		$	24,940		$	65,920		$	90,860
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, 2013 are related to forward purchases of energy scheduled for delivery through December 2018.

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

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. The December 31, 2013 balance will be amortized on a straight-line basis over two consecutive 12-month periods beginning in January 2014.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 225 months.

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. The rider, approved in December 2013, is retroactive to January 2013. The balance in the regulatory asset account is subject to recovery over a twelve month period ending on December 31, 2014.

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC 740, Income Taxes.

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of December 31, 2013.

Big Stone II Unrecovered Project Costs – North Dakota are 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.

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 as of December 31, 2013. A supplemental filing was submitted to the MPUC on February 15, 2013, requesting that the then current MNRRA rate be retained until a majority of the remaining costs were recovered and that the MNRRA rate be set to zero effective May 1, 2013. The MPUC approved the request on April 4, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

The South Dakota Transmission Rider Accrued Revenues relate to revenues billed for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers net of transmission revenues that have not been billed to South Dakota customers as of December 31, 2013.

General Rate Case Recoverable Expenses – South Dakota relate to expenses incurred during rate case proceedings that are eligible for recovery.

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

The Minnesota Transmission Rider Accrued Refund relates to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers net of transmission revenues that are refundable to Minnesota customers as of December 31, 2013.

Revenue for Rate Case Expenses Subject to Refund - Minnesota relate to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.

The 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, 2013.

The North Dakota Transmission Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers net of transmission revenues that are refundable to North Dakota customers as of December 31, 2013.

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
Forward Contracts Classified as Derivatives	Dec. 31, 2013
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 optimize the use of its generating and transmission facilities and leverage its knowledge of wholesale energy markets in the region to maximize financial returns for the benefit of both its customers and shareholders. 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. OTP also enters into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales.

	As of December 31, 2013 OTP had recognized, on a pretax basis, $115,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Market prices used to value OTP’s forward contracts for the purchases and sales of electricity and electricity generating capacity 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)		2013				2012			2011
	Wholesale Sales - Company-Owned Generation		$	14,846			$	12,951		$	14,518
	Revenue from Settled Contracts at Market Prices			133,238				160,987			168,313
	Market Cost of Settled Contracts			(132,055	)			(159,500	)		(166,920	)
	Net Margins on Settled Contracts at Market			1,183				1,487			1,393
	Marked-to-Market Gains on Settled Contracts			3,039				7,864			10,208
	Marked-to-Market Losses on Settled Contracts			(2,722	)			(7,974	)		(10,176	)
	Net Marked-to-Market Gains (Losses) on Settled Contracts			317				(110	)		32
	Unrealized Marked-to-Market Gains on Open Contracts			215				284			3,707
	Unrealized Marked-to-Market Losses on Open Contracts			(100	)			(235	)		(2,813	)
	Net Unrealized Marked-to-Market Gains on Open Contracts			115				49			894
	Wholesale Electric Revenue		$	16,461			$	14,377		$	16,837

	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, 2013 and December 31, 2012, and the change in the Company’s consolidated balance sheet position from December 31, 2012 to December 31, 2013 and December 31, 2011 to December 31, 2012:

	(in thousands)		31-Dec-13				31-Dec-12
	Other Current Asset – Marked-to-Market Gain		$	338			$	502
	Regulatory Asset – Current Deferred Marked-to-Market Loss			3,008				7,949
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss			8,674				10,050
	Total Assets			12,020				18,501
	Current Liability – Marked-to-Market Loss			(11,782	)			(18,234	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain			(6	)			(8	)
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain			(117	)			(210	)
	Total Liabilities			(11,905	)			(18,452	)
	Net Fair Value of Marked-to-Market Energy Contracts		$	115			$	49


	(in thousands)		Year ended				Year ended
	(in thousands)		31-Dec-13				31-Dec-12
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period		$	49			$	894
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods			(49	)			(861	)
	Changes in Fair Value of Contracts Entered into in Prior Periods			--				(33	)
	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				49
	Cumulative Fair Value Adjustments Included in Earnings - End of Period		$	115			$	49

	The $115,000 in recognized but unrealized net gains on the forward energy and capacity purchases and sales marked to market on December 31, 2013 is expected to be realized on settlement in the first quarter of 2014.

	OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. The Company 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.

	The following table provides information on OTP’s credit risk exposure on delivered and marked-to-market forward contracts as of December 31, 2013 and December 31, 2012:

			31-Dec-13							31-Dec-12
	(in thousands)		Exposure				Counterparties			Exposure			Counterparties
	Net Credit Risk on Forward Energy Contracts		$	856				3		$	580			6
	Net Credit Risk to Single Largest Counterparty		$	530						$	285

	OTP had a net credit risk exposure to three counterparties with investment grade credit ratings. OTP had no exposure at December 31, 2013 or December 31, 2012 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The credit risk exposures include net amounts due to OTP on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains on forward contracts for the purchase of gasoline scheduled for settlement subsequent to December 31, 2013. Individual counterparty exposures are 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, 2013 and December 31, 2012 are indicated in the following table:

	(in thousands)		31-Dec-13				31-Dec-12
	Derivative Assets Subject to Legally Enforceable Netting Arrangements		$	400			$	638
	Derivative Liabilities Subject to Legally Enforceable Netting Arrangements			(11,782	)			(18,234	)
	Net Balance Subject to Legally Enforceable Netting Arrangements		$	(11,382	)		$	(17,596	)

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, 2013 and December 31, 2012:

Current Liability – Marked-to-Market Loss (in thousands)	December 31,				December 31,
Current Liability – Marked-to-Market Loss (in thousands)	2013				2012
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--			$	2,176
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,679				16,058
Loss Contracts with No Ratings Triggers or Deposit Requirements		103				--
Total Current Liability – Marked-to-Market Loss	$	11,782			$	18,234
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	11,679			$	16,058
Offsetting Gains with Counterparties under Master Netting Agreements		(117	)			(416	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	11,562			$	15,642

Common_Shares_and_Earnings_Per

Common Shares and Earnings Per Share	12 Months Ended
Common Shares and Earnings Per Share	Dec. 31, 2013
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 $75,000,000.

	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. No shares were sold pursuant to the Agreement in 2013.

	2013 Common Stock Activity
	Following is a reconciliation of the Company’s common shares outstanding from December 31, 2012 through December 31, 2013:

	Common Shares Outstanding, December 31, 2012			36,168,368
	Issuances:
	Stock Options Exercised			56,109
	Vesting of Restricted Stock Units			17,535
	Restricted Stock Issued to Employees			17,000
	Restricted Stock Issued to Directors			17,333
	Director’s Compensation			4,535
	Retirements:
	Shares Withheld for Individual Income Tax Requirements			(7,184	)
	Forfeiture of Unvested Restricted Stock			(2,000	)
	Common Shares Outstanding, December 31, 2013			36,271,696

	Stock Incentive Plan
	The 1999 Stock Incentive Plan, as amended (Incentive Plan), 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 3,600,000 common shares were authorized for granting stock awards under the Incentive Plan, which terminated on December 13, 2013.

	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, 482,782 were available for purchase as of December 31, 2013. 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 the Purchase Plan, 43,837 common shares were purchased in the open market in 2013, 60,439 common shares were purchased in the open market in 2012 and 78,537 common shares were purchased in the open market in 2011. 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 or customers who participate in the Plan to be either new issue common shares or common shares purchased in the open market. In 2013 and 2012 common shares were purchased in the open market to provide shares for the Plan. In 2011 common shares were purchased in the open market to provide shares for the Plan under a prior shelf registration statement that expired on December 1, 2011.

	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 2013, 2012 or 2011. 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 203,583 shares, 194,240 shares and 160,228 shares in 2013, 2012 and 2011, 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, 2013, 2012 and 2011.

	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, 2013, 2012 and 2011:

	Year	Options Outstanding	Range of Exercise Prices
	2013	--	--
	2012	92,497	$24.93 – $27.245
	2011	156,397	$24.93 – $31.34

ShareBased_Payments

Share-Based Payments	12 Months Ended
Share-Based Payments	Dec. 31, 2013
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 $143,000 in 2013, $179,000 in 2012 and $257,000 in 2011. 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 Incentive Plan
	Since the inception of the Incentive Plan in 1999, the Company has granted 2,041,500 options for the purchase of the Company’s common stock. 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 Incentive Plan was based on the Black-Scholes option pricing model.

	The following table provides information about options outstanding as of December 31, 2013:

	Exercise Price	Outstanding and	Remaining Contractual Life
		Exercisable as of
		12/31/13
	$24.93	17,900	Expire on April 10, 2015
	$26.50	16,800	Expire on April 11, 2014

	Presented below is a summary of the stock options activity:

	Stock Option Activity		2013						2012						2011
			Options			Average			Options			Average			Options			Average
						Exercise						Exercise						Exercise
						Price						Price						Price
	Outstanding, Beginning of Year			92,497		$	26.59			156,397		$	28.53			383,460		$	27.28
	Granted			--			--			--			--			--			--
	Exercised			56,109			27.12			--			--			--			--
	Forfeited or Expired			1,688			27.245			63,900			31.34			227,063			26.43
	Outstanding, End of Year			34,700			25.69			92,497			26.59			156,397			28.53
	Exercisable, End of Year			34,700			25.69			92,497			26.59			156,397			28.53
	Cash Received for Options Exercised					$	1,522,000						--						--
	Intrinsic Value of Options Exercised					$	152,000						--						--
	Fair Value of Options Granted During Year					none granted						none granted						none granted

	Restricted Stock Granted to Directors
	Under the 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 8, 2013 the Company’s Board of Directors granted 16,000 shares of restricted stock to the Company’s nonemployee directors. The grant date fair value of each share of restricted stock granted on April 8, 2013 was $31.03 per share, the average of the high and low market price on the date of grant. On September 23, 2013 the Compensation Committee of the Company’s Board of Directors granted Steven L. Fritze, a new Director, 1,333 shares of restricted stock effective October 1, 2013. The grant date fair value of each share of restricted stock granted on October 1, 2013 was $27.67 per share, the average of the high and low market price on the date of grant. The restricted shares granted in 2013 vest 25% per year on April 8 of each year in the period 2014 through 2017 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		2013						2012						2011
			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			56,900		$	21.84			54,250		$	23.26			59,725		$	24.95
	Granted			17,333			30.77			24,000			21.32			24,000			22.51
	Vested			29,750			21.87			21,350			24.86			29,475			26.07
	Forfeited			2,000			31.03			--						--
	Nonvested, End of Year			42,483			25.03			56,900			21.84			54,250			23.26
	Compensation Expense Recognized					$	611,000					$	552,000					$	740,000
	Fair Value of Shares Vested in Year						651,000						531,000						768,000

	Restricted Stock Granted to Employees
	Under the 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 8, 2013 the Company’s Board of Directors granted 17,000 shares of restricted stock to the Company’s executive officers under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2014 through 2017 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 2013 was $31.03 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		2013						2012						2011
			Shares			Weighted Average			Shares			Weighted			Shares			Weighted
						Grant-Date						Average						Average
						Fair Value						Grant-Date						Grant-Date
												Fair Value						Fair Value
	Nonvested, Beginning of Year			47,645		$	21.82			34,868		$	22.86			66,161		$	24.79
	Granted			17,000			31.03			26,120			21.48			24,600			22.51
	Awards Vested			16,330			21.89			11,518			24.14			55,893			25
Forfeited			--						1,825			22.2			--
Nonvested, End of Year			48,315			25.04			47,645			21.82			34,868			22.86
Compensation Expense Recognized					$	427,000					$	325,000					$	832,000
Fair Value of Awards Vested						358,000						278,000						1,397,000

Restricted Stock Units Granted to Employees
On April 8, 2013 the Company’s Board of Directors granted 15,150 restricted stock units to key employees under the Incentive Plan payable in common shares on April 8, 2017, the date the units vest. The grant date fair value of each restricted stock unit was $25.30 per share based on the market value of the Company’s common stock on April 8, 2013, 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		2013						2012						2011
		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			60,665		$	18.11			73,815		$	20.95			79,315		$	23.55
Granted			15,150			25.3			15,800			17.66			19,800			18.03
Vested			17,535			18.73			20,750			27.13			20,025			27.94
Forfeited			2,100			19.88			8,200			19.97			5,275			22.56
Nonvested, End of Year			56,180			19.79			60,665			18.11			73,815			20.95
Compensation Expense Recognized					$	275,000					$	256,000					$	349,000
Fair Value of Units Converted in Year						328,000						563,000						559,000

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 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 8, 2013 the Company’s Board of Directors granted performance share awards to the Company’s executive officers under the Incentive Plan for the 2013-2015 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 Subject			Shares Used			Grant			Expense Recognized									Shares Awarded
Period		To Award			To Estimate Expense			Date Fair			in the Year Ended December 31,
								Value
											2013			2012			2011
2013-2015			100,400			50,200		$	37.51		$	580,000		$	--		$	--			--
2012-2014			161,600			80,800		$	21.75			1,686,000			1,001,000			--			--
2011-2013			97,200			48,600		$	23.61			412,000			254,000			553,000			48,730
2010-2012			146,800			73,400		$	20.97			--			--			572,000			49,500
2009-2011			181,200			90,600		$	27.98			--			--			746,000			64,500
Total											$	2,678,000		$	1,255,000		$	1,871,000			162,730

The Company’s former Chief Executive Officer resigned his employment with the Company effective December 15, 2011, and his resignation was treated as a termination without cause for the purposes of his employment agreement. Under the terms of his employment agreement, he received the targeted number of the Company’s common shares for the performance awards granted him in 2009, 2010 and 2011, or 88,300 shares, valued at the average of the high and low price of the Company’s common shares on December 14, 2011 of $21.191 per share, for a total value of $1,871,165.

The shares awarded shown in the table above for the 2009-2011 and 2010-2012 performance periods reflect only shares received under executive employment agreements. The Company’s 2009-2011 and 2010-2012 total shareholder return rankings resulted in no incentive share awards for the Company’s active plan participants for the 2009-2011 and 2010-2012 performance measurement periods.

As of December 31, 2013 the total remaining unrecognized amount of compensation expense related to stock-based compensation for all of the Company’s stock-based payment programs was approximately $4.6 million (before income taxes), which will be amortized over a weighted-average period of 2.0 years.

Retained_Earnings_and_Dividend

Retained Earnings and Dividend Restriction	12 Months Ended
Retained Earnings and Dividend Restriction	Dec. 31, 2013
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’s 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, 2013 the Company was in compliance with the debt covenants. See note 10 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 44.8% and 54.8%. OTP’s equity to total capitalization ratio including short-term debt was 50.2% as of December 31, 2013. Total capitalization for OTP cannot currently exceed $874 million.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	9. Commitments and Contingencies

	Construction and Other Purchase Commitments
	At December 31, 2013 OTP had commitments under contracts in connection with construction programs aggregating approximately $108,227,000.

	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 through 2038. 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 2014, 2015, 2016 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, construction equipment and vehicles. Rent expense from continuing operations was $11,114,000, $11,858,000, and $10,061,000 for 2013, 2012 and 2011, respectively.

	The amounts of the Company’s commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases as of December 31, 2013, are as follows:

		Capacity and		Coal and Freight		Operating Leases
		Energy		Purchase		Operating Leases
	(in thousands)	Requirements		Commitments		OTP		Nonelectric		Total
	2014	$	22,565	$	50,149	$	2,519	$	5,695	$	8,214
	2015		30,468		20,790		1,649		4,533		6,182
	2016		22,812		21,041		1,309		3,756		5,065
	2017		22,123		23,599		978		2,419		3,397
	2018		25,808		23,135		989		1,554		2,543
	Beyond 2018		223,561		621,814		11,812		325		12,137
	Total	$	347,337	$	760,528	$	19,256	$	18,282	$	37,538

	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, litigation matters and the resolution of matters related to open tax years. Should all of these known items result in liabilities being incurred, the loss could be as high as $2.0 million. Additionally, the Company may become subject to significant claims of which its management is unaware, or the claims of which its management is aware, such as possible warranty claims on products that are beyond their warranty period but where a customer may claim to have provided notice of a defect while the product was under warranty. If these claims were to occur, it could result in the Company incurring a significantly greater liability than it anticipates.

	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, 2013 will not be material.

ShortTerm_and_LongTerm_Borrowi

Short-Term and Long-Term Borrowings and Preferred Stock Redemption	12 Months Ended
	Dec. 31, 2013
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, 2013 and December 31, 2012:

	(in thousands)		Line Limit			In Use on			Restricted due to		Available on		Available on
						December 31,			Outstanding		December 31,		December 31,
						2013			Letters of Credit		2013		2012
	Otter Tail Corporation Credit Agreement		$	150,000		$	--		$	659	$	149,341	$	149,267
	OTP Credit Agreement			170,000			51,195			1,830		116,975		166,811
	Total		$	320,000		$	51,195		$	2,489	$	266,316	$	316,078

	Under the Otter Tail Corporation Credit Agreement referenced below, the maximum amount of debt outstanding in 2013 was $4,754,000 on December 2, 2013 and the average daily balance of debt outstanding during 2013 was $49,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2013 was 1.9% compared with 3.8% in 2012. Under the OTP Credit Agreement, the maximum amount of debt outstanding in 2013 was $53,003,000 on December 13, 2013 and the average daily balance of debt outstanding during 2013 was $17,446,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2013 was 1.4% compared with 1.7% in 2012. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2013 was 1.4%.

	On October 29, 2012 the Company entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement) with the Banks named therein, which is an unsecured $150 million revolving credit facility with an accordion feature whereby the line can be increased to $250 million on the terms and subject to the conditions described in the Credit Agreement. On October 29, 2013 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2017 to October 29, 2018. 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 interest rate being charged under the Second Amended and Restated Credit Agreement prior to the renewal was LIBOR plus 3.25%. Under the Otter Tail Corporation Credit Agreement, 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 material 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 certain financial covenants described below under the heading “Financial Covenants.” It 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 material 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) with the Banks named therein, providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 29, 2013 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2017 to October 29, 2018. 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 the OTP Credit Agreement bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. The interest rate being charged under the OTP Credit Agreement prior to the renewal was LIBOR plus 1.5%. Under the OTP Credit Agreement, 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 certain financial covenants as described below under the heading “Financial Covenants,” as well as a financial covenant under which OTP may not permit the ratio of its “Interest-bearing Debt” to “Total Capitalization” (as defined in the OTP Credit Agreement) to be greater than 0.60 to 1.00. The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

	Long-Term Debt Issuances, Retirements and Preferred Stock Redemption

	Debt Retirements
	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 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. Cascade owned approximately 9.5% of the Company’s outstanding common stock as of December 31, 2013.

	In addition, on February 27, 2014 the Company repaid in full its Term Loan as described below.

	Unsecured Term Loan due January 15, 2015
	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. On February 27, 2014, OTP used a portion of the proceeds of the New OTP Notes described below to retire early the Term Loan.

	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 pays 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 our preferred dividend requirement for the nine-month period ending September 30, 2013.

	2016 Notes
	On December 4, 2009 the Company issued $100 million of its 2016 notes under the indenture (for unsecured debt securities) dated as of November 1, 1997, as amended by the First Supplemental Indenture dated as of July 1, 2009, between the Company and U.S. Bank National Association (formerly First Trust National Association), as trustee. The 2016 Notes are senior unsecured indebtedness and bear interest at 9.000% per year, payable semi-annually in arrears on June 15 and December 15 of each year. As discussed above, in November 2013 the Company purchased and retired, in two separate transactions, $12,933,000 and $34,737,000, respectively, of the outstanding 2016 Notes. The remaining $52,300,000 principal amount of the 2016 Notes outstanding, unless previously redeemed or otherwise repaid, will mature and become due and payable on December 15, 2016.

	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 2029 Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the 2044 Notes and, together with the 2029 Notes, the New OTP Notes). The New OTP Notes were issued on February 27, 2014. OTP used a portion of the proceeds of the New OTP 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 New OTP Notes will be used to pay fees and expenses related to the issuance of the New OTP Notes and for other general purposes, including planned construction program expenditures.

	The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the New OTP Notes (in an amount not less than 10% of the aggregate principal amount of the New OTP 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 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 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 New OTP 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 New OTP 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 (the 2021 Notes) pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP used a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of its 6.63% Senior Notes due December 1, 2011 at maturity and to retire early $10.4 million aggregate principal amount of outstanding pollution control refunding revenue bonds due December 1, 2012. No penalty was paid for the early retirement.

	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.”

	PACE Loan
	On March 18, 2011 the Company borrowed $1.5 million under a Partnership in Assisting Community Expansion loan to finance capital investments at Northern Pipe Products, Inc. (Northern Pipe), the Company’s PVC pipe manufacturing subsidiary located in Fargo, North Dakota. The ten-year unsecured note bears interest at 2.54% with monthly principal and interest payments through March 2021. On April 6, 2011, Otter Tail Corporation borrowed $0.5 million under a North Dakota Development Fund loan to finance additional capital investments at Northern Pipe. The seven-year unsecured note bears interest at 3.95% with monthly principal and interest payments through April 1, 2018.

	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, 2013 for each of the next five years are:

	(in thousands)		2014			2015			2016		2017		2018
	Aggregate amounts of Debt Maturities		$	188		$	41,101		$	52,544	$	33,228	$	187

	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, 2013 and December 31, 2012:

December 31, 2013 (in thousands)		OTP			Otter Tail Corporation			Otter Tail 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
Other Obligations - Various up to 3.95% at December 31, 2013			--			1,548			1,548
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


December 31, 2012 (in thousands)		OTP			Otter Tail			Otter Tail
					Corporation			Corporation
								Consolidated
Short-Term Debt		$	--		$	--		$	--
Long-Term Debt:
9.000% Notes, due December 15, 2016					$	100,000		$	100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		$	33,000						33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017			5,065						5,065
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
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022			20,070						20,070
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
Other Obligations - Various up to 3.95% at December 31, 2012						1,725			1,725
Total		$	320,135		$	101,725		$	421,860
Less: Current Maturities			--			176			176
Unamortized Debt Discount			--			4			4
Total Long-Term Debt		$	320,135		$	101,545		$	421,680
Total Short-Term and Long-Term Debt (with current maturities)		$	320,135		$	101,721		$	421,856

Financial Covenants

The Company and OTP were in compliance with the financial covenants in their debt agreements as of December 31, 2013.

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.

Class_B_Stock_Options_of_Subsi

Class B Stock Options of Subsidiary	12 Months Ended
Class B Stock Options of Subsidiary	Dec. 31, 2013
Common Stock Options Of Subsidiary [Abstract]	'
Class B Stock Options of Subsidiary	'
	11. Class B Stock Options of Subsidiary

	In conjunction with the sale of IPH on May 6, 2011, all 363 outstanding IPH Class B common share options were cancelled by mutual agreement between the issuer and the holders of the options and a liability to the holders of the options was established based on the fair value of the options on May 6, 2011. The liability was assumed by the new owner of IPH. The options were adjusted to their fair value based on the fair value of an underlying share of Class B Common Stock of $2,973.90 per share on May 6, 2011. The book value of IPH Class B common share options prior to their cancellation on May 6, 2011 was based on an IPH Class B common share value of $2,085.88 per share. The $322,000 difference between the fair value and book value of the options was charged to retained earnings and earnings available for common shares were reduced by $322,000 in the second quarter of 2011.

Pension_Plan_and_Other_Postret

Pension Plan and Other Postretirement Benefits	12 Months Ended
Pension Plan and Other Postretirement Benefits	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Pension Plan and Other Postretirement Benefits	'
	12. Pension Plan and Other Postretirement Benefits

	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)		2013				2012				2011
	Service Cost–Benefit Earned During the Period		$	5,594			$	5,084			$	4,415
	Interest Cost on Projected Benefit Obligation			12,123				12,465				12,666
	Expected Return on Assets			(14,521	)			(14,430	)			(14,140	)
	Amortization of Prior-Service Cost:
	From Regulatory Asset			333				398				423
	From Other Comprehensive Income1			9				11				11
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			6,600				4,910				2,549
	From Other Comprehensive Income1			176				131				68
	Net Periodic Pension Cost		$	10,314			$	8,569			$	5,992
	1Corporate cost included in Other Nonelectric Expenses.

	Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:

			2013				2012				2011
	Discount Rate			4.5	%			5.15	%			6	%
	Long-Term Rate of Return on Plan Assets			7.75	%			8	%			8	%
	Rate of Increase in Future Compensation Level			3.13	%			3.38	%			3.75	%

	The following table presents amounts recognized in the consolidated balance sheets as of December 31:

	(in thousands)		2013				2012
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	776			$	1,109
	Unrecognized Actuarial Loss			56,051				98,808
	Total Regulatory Assets		$	56,827			$	99,917

	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	28			$	37
	Unrecognized Actuarial Loss			448				1,857
	Total Accumulated Other Comprehensive Loss		$	476			$	1,894
	Noncurrent Liability		$	40,422			$	84,616

	Funded status as of December 31:

	(in thousands)		2013				2012
	Accumulated Benefit Obligation		$	(224,365	)		$	(238,706	)

	Projected Benefit Obligation		$	(254,039	)		$	(275,634	)
	Fair Value of Plan Assets			213,617				191,018
	Funded Status		$	(40,422	)		$	(84,616	)

	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, 2013:

	(in thousands)		2013				2012
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	191,018			$	168,603
	Actual Return on Plan Assets			23,044				22,656
	Discretionary Company Contributions			10,000				10,000
	Benefit Payments			(10,445	)			(10,241	)
	Fair Value of Plan Assets at December 31		$	213,617			$	191,018
Estimated Asset Return			11.8	%			13.4	%
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1		$	275,634			$	246,098
Service Cost			5,594				5,084
Interest Cost			12,123				12,465
Benefit Payments			(10,445	)			(10,241	)
Actuarial (Gain) Loss			(28,867	)			22,228
Projected Benefit Obligation at December 31		$	254,039			$	275,634

Weighted-average assumptions used to determine benefit obligations at December 31:

		2013				2012
Discount Rate			5.3	%			4.5	%
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 2014 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. We review our rate of return on plan asset assumptions annually. The assumptions are largely based on the asset category rate-of-return assumptions developed annually with our 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:	2013	2012
Net Periodic Pension Cost	1-Jan-13	1-Jan-12

End of Year Benefit Obligations	January 1, 2013 projected to	January 1, 2012 projected to
End of Year Benefit Obligations	31-Dec-13	31-Dec-12

Market Value of Assets	31-Dec-13	31-Dec-12

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 2014 are:

(in thousands)		2014
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	257
Amortization of Unrecognized Actuarial Loss			3,477
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			7
Amortization of Unrecognized Actuarial Loss			93
Total Estimated Amortization		$	3,834

Cash flows—The Company had no minimum funding requirement as of December 31, 2013, but made discretionary plan contributions totaling $20,000,000 in January 2014.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:

(in thousands)		2014				2015				2016				2017			2018		Years
(in thousands)		2014				2015				2016				2017			2018		2019-2023
		$	11,304			$	11,772			$	12,363			$	13,014		$	13,801	$	80,569

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, 2013 and 2012, by asset category are as follows:

Asset Allocation		2013				2012
Large Capitalization Equity Securities			21	%			24.7	%
International Equity Securities			21.7	%			17.8	%
Small and Mid-Capitalization Equity Securities			8.5	%			7.1	%
SEI Dynamic Asset Allocation Fund			5.2	%			4.8	%
Equity Securities			56.4	%			54.4	%
Fixed-Income Securities and Cash			39.3	%			41.1	%
Other - SEI Special Situation Collective Investment Trust			4.3	%			4.5	%
			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, 2013 and 2012:

2013 (in thousands)		Level 1				Level 2				Level 3

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			$	--

2012 (in thousands)
Large Capitalization Equity Securities Mutual Fund		$	47,083
International Equity Securities Mutual Funds			34,088
Small and Mid-Capitalization Equity Securities Mutual Fund			13,613
SEI Dynamic Asset Allocation Mutual Fund			9,177
Fixed Income Securities Mutual Funds			78,480
Cash Management – Working Capital Account			11
SEI Special Situation Collective Investment Trust Fund										$	8,566
Total Assets		$	182,452			$	--			$	8,566

The investments held by the SEI Special Situation Collective Investment Trust on December 31, 2013 and 2012 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 management team. These assets were classified as Level 3 in 2012 because there were restrictions on trading shares in the fund that made the shares illiquid. In 2013, the restriction on the shares held by OTP’s pension fund was lifted and shares in the fund could be redeemed at net asset value, so the investment in the fund was reclassified to Level 2. There were no other transfers between Levels of the fair value hierarchy during the year ended December 31, 2013.

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)		2013				2012				2011
Service Cost–Benefit Earned During the Period		$	51			$	45			$	81
Interest Cost on Projected Benefit Obligation			1,408				1,479				1,632
Amortization of Prior Service Cost:
From Regulatory Asset			22				22				42
From Other Comprehensive Income1			51				51				31
Amortization of Net Actuarial Loss:
From Regulatory Asset			208				175				142
From Other Comprehensive Income2			313				152				103
Net Periodic Pension Cost		$	2,053			$	1,924			$	2,031
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses		$	20			$	20			$	--
Other Nonelectric Expenses			31				31				31
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses		$	193			$	162			$	--
Other Nonelectric Expenses			120				(10	)			103

Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31:

		2013				2012				2011
Discount Rate			4.5	%			5.15	%			6	%
Rate of Increase in Future Compensation Level			3.19	%			4.59	%			4.65	%

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

(in thousands)		2013				2012
Regulatory Assets:
Unrecognized Prior Service Cost		$	113			$	135
Unrecognized Actuarial Loss			1,971				2,788
Total Regulatory Assets		$	2,084			$	2,923
Projected Benefit Obligation Liability – Net Amount Recognized		$	(29,321	)		$	(31,925	)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost		$	261			$	312
Unrecognized Actuarial Loss			2,465				5,095
Total Accumulated Other Comprehensive Loss		$	2,726			$	5,407

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, 2013 and a statement of the funded status as of December 31 of both years:

(in thousands)		2013				2012
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1		$	--			$	--
Actual Return on Plan Assets			--				--
Employer Contributions			1,137				1,259
Benefit Payments			(1,137	)			(1,259	)
Fair Value of Plan Assets at December 31		$	--			$	--
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1		$	31,925			$	29,323
Service Cost			51				45
Interest Cost			1,408				1,479
Benefit Payments			(1,137	)			(1,259	)
Plan Amendments			--				--
Actuarial (Gain) Loss			(2,926	)			2,337
Projected Benefit Obligation at December 31		$	29,321			$	31,925
Reconciliation of Funded Status:
Funded Status at December 31		$	(29,321	)		$	(31,925	)
Unrecognized Net Actuarial Loss			4,436				7,882
Unrecognized Prior Service Cost			374				448
Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost		$	(24,511	)		$	(23,595	)

Weighted-average assumptions used to determine benefit obligations at December 31:

		2013				2012
Discount Rate			5.30%				4.50%
Rate of Increase in Future Compensation Level			3.18%				3.19%

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 2014 are:

(in thousands)		2014
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	22
Amortization of Unrecognized Actuarial Loss			142
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			51
Amortization of Unrecognized Actuarial Loss			46
Total Estimated Amortization		$	261

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)		2014				2015				2016				2017			2018		2019-2023
		$	1,178			$	1,392			$	1,381			$	1,359		$	1,402	$	8,939

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. There are no plan assets.

Components of net periodic postretirement benefit cost:

(in thousands)		2013				2012				2011
Service Cost–Benefit Earned During the Period		$	1,421			$	1,544			$	1,275
Interest Cost on Projected Benefit Obligation			2,050				2,574				2,384
Amortization of Transition Obligation
From Regulatory Asset			--				729				729
From Other Comprehensive Income1			--				19				19
Amortization of Prior Service Cost
From Regulatory Asset			205				206				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		$	3,706			$	5,736			$	4,618
Effect of Medicare Part D Subsidy		$	(1,806	)		$	(2,039	)		$	(2,118	)
1Corporate cost included in Other Nonelectric Expenses.

Weighted-average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:

		2013				2012				2011
Discount Rate			4.25	%			5.05	%			5.75	%

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

(in thousands)		2013				2012
Regulatory Asset:
Unrecognized Prior Service Cost		$	540			$	745
Unrecognized Net Actuarial (Gain) Loss			(344	)			14,364
Net Regulatory Asset		$	196			$	15,109
Projected Benefit Obligation Liability – Net Amount Recognized		$	(45,221	)		$	(58,883	)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost		$	18			$	23
Unrecognized Net Actuarial (Gain) Loss			(261	)			177
Accumulated Other Comprehensive (Gain) Loss		$	(243	)		$	200

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, 2013:

(in thousands)		2013				2012
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1		$	--			$	--
Actual Return on Plan Assets			--				--
Company Contributions			2,012				1,956
Benefit Payments (Net of Medicare Part D Subsidy)			(4,626	)			(4,296	)
Participant Premium Payments			2,614				2,340
Fair Value of Plan Assets at December 31		$	--			$	--
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1		$	58,883			$	48,263
Service Cost (Net of Medicare Part D Subsidy)			1,421				1,544
Interest Cost (Net of Medicare Part D Subsidy)			2,050				2,575
Benefit Payments (Net of Medicare Part D Subsidy)			(4,626	)			(4,296	)
Participant Premium Payments			2,614				2,340
Actuarial (Gain) Loss			(15,121	)			8,457
Projected Benefit Obligation at December 31		$	45,221			$	58,883
Reconciliation of Accrued Postretirement Cost:
Accrued Postretirement Cost at January 1		$	(43,574	)		$	(39,794	)
Expense			(3,706	)			(5,736	)
Net Company Contribution			2,012				1,956
Accrued Postretirement Cost at December 31		$	(45,268	)		$	(43,574	)

Weighted-average assumptions used to determine benefit obligations at December 31:

		2013				2012
Discount Rate			5.10%				4.25%

Assumed healthcare cost-trend rates as of December 31:
		2013				2012
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65			6.47%				6.62%
Healthcare Cost-Trend Rate Assumed for Next Year Post-65			6.82%				7.01%
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

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 2013 would have the following effects:

(in thousands)		1 Point				1 Point
(in thousands)		Increase				Decrease
Effect on the Postretirement Benefit Obligation		$	5,306			$	(4,449	)
Effect on Total of Service and Interest Cost		$	634			$	(500	)
Effect on Expense		$	1,266			$	(525	)

Measurement Dates:	2013	2012
Net Periodic Postretirement Benefit Cost	1-Jan-13	1-Jan-12

End of Year Benefit Obligations	January 1, 2013 projected to	January 1, 2012 projected to
End of Year Benefit Obligations	31-Dec-13	31-Dec-12

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 2014 are:

(in thousands)		2014
Decrease in Regulatory Assets:
Amortization of Unrecognized Prior Service Cost		$	205
Decrease in Accumulated Other Comprehensive Loss:
Amortization of Unrecognized Prior Service Cost			5
Total Estimated Amortization		$	210

Cash flows—The Company expects to contribute $2.7 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2014. The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $448,000 in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

																			Years
(in thousands)		2014				2015				2016				2017			2018		2019-2023
		$	2,653			$	2,785			$	2,899			$	3,061		$	3,206	$	17,207

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 $3,042,000 for 2013, $2,547,000 for 2012 and $2,598,000 for 2011.

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 $705,000 for 2013, $735,000 for 2012 and $760,000 for 2011.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Instruments	'
	13. 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 obligation is short-term and the balance outstanding related to the OTP Credit Agreement is subject to a variable interest rate of LIBOR plus 1.25%, which approximates current market rates.

	Long-Term Debt including Current Maturities—The fair value of the Company’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-13						31-Dec-12
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
		Amount						Amount
	Cash and Cash Equivalents	$	1,150		$	1,150		$	52,362		$	52,362
	Short-Term Debt		(51,195	)		(51,195	)		--			--
	Long-Term Debt including Current Maturities		(389,777	)		(427,796	)		(421,856	)		(491,244	)

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
Property, Plant and Equipment	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	14. Property, Plant and Equipment

	(in thousands)	December 31,		December 31,
	(in thousands)	2013		2012
	Electric Plant in Service
	Production	$	679,067	$	672,120
	Transmission		270,606		261,447
	Distribution		421,803		405,461
	General		89,408		84,275
	Electric Plant in Service		1,460,884		1,423,303
	Construction Work in Progress		184,780		75,758
	Total Gross Electric Plant		1,645,664		1,499,061
	Less Accumulated Depreciation and Amortization		554,818		526,467
	Net Electric Plant	$	1,090,846	$	972,594
	Nonelectric Operations Plant
	Equipment	$	153,098	$	144,901
	Buildings and Leasehold Improvements		38,074		37,209
	Land		3,700		3,984
	Nonelectric Operations Plant		194,872		186,094
	Construction Work in Progress		2,681		2,132
	Total Gross Nonelectric Plant		197,553		188,226
	Less Accumulated Depreciation and Amortization		121,383		111,368
	Net Nonelectric Operations Plant	$	76,170	$	76,858
	Net Plant	$	1,167,016	$	1,049,452

	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
Income Taxes	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	15. Income Taxes

	The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2013, 2012 and 2011) to net income before total income tax expense for the following reasons:

	(in thousands)		2013				2012				2011
	Tax Computed at Federal Statutory Rate		$	22,301			$	14,385			$	13,661
	Increases (Decreases) in Tax from:
	Federal Production Tax Credit			(6,612	)			(6,695	)			(7,281	)
	State Income Taxes Net of Federal Income Tax Expense (Benefit)			1,667				(849	)			798
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes			(863	)			(891	)			(996	)
	Corporate Owned Life Insurance			(856	)			(585	)			(388	)
	Allowance for Funds Used During Construction - Equity			(638	)			(409	)			(301	)
	Dividend Received/Paid Deduction			(632	)			(656	)			(677	)
	Investment Tax Credit Amortization			(597	)			(720	)			(855	)
	Tax Depreciation - Treasury Grant for Wind Farms			(304	)			(304	)			(507	)
	Differences Reversing in Excess of Federal Rates			(100	)			(143	)			680
	Impact of Medicare Part D Change			--				(584	)			(599	)
	Permanent and Other Differences			177				(416	)			586
	Total Income Tax Expense – Continuing Operations		$	13,543			$	2,133			$	4,121
	Income Tax Expense (Benefit) – Discontinued Operations – U.S.			15				(14,667	)			(13,325	)
	Income Tax (Benefit) – Discontinued Operations – Foreign			--				--				(79	)
	Income Tax Expense (Benefit) – Continuing and Discontinued Operations		$	13,558			$	(12,534	)		$	(9,283	)
	Overall Effective Federal, State and Foreign Income Tax Rate			21	%			70.4	%			41.2	%

	Income Tax Expense From Continuing Operations Includes the Following:
	Current Federal Income Taxes		$	146			$	(7,198	)		$	(4,303	)
	Current State Income Taxes			37				(1,402	)			(754	)
	Deferred Federal Income Taxes			18,310				15,878				14,308
	Deferred State Income Taxes			3,122				3,161				4,002
	Federal Production Tax Credit			(6,612	)			(6,695	)			(7,281	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes			(863	)			(891	)			(996	)
	Investment Tax Credit Amortization			(597	)			(720	)			(855	)
	Total		$	13,543			$	2,133			$	4,121
	Income (Loss) Before Income Taxes – U.S.		$	63,924			$	(13,426	)		$	(7,547	)
	Income (Loss) Before Income Taxes – Foreign (Discontinued Operations)			499				(4,381	)			(14,979	)
	Total Income (Loss) Before Income Taxes – Continuing and Discontinued Operations		$	64,423			$	(17,807	)		$	(22,526	)

	The Company’s deferred tax assets and liabilities were composed of the following on December 31:

	(in thousands)		2013				2012
	Deferred Tax Assets
	North Dakota Wind Tax Credits		$	42,241			$	44,172
	Retirement Benefits Liabilities			39,524				34,618
	Benefit Liabilities			39,290				35,459
	Federal Production Tax Credits			33,620				27,048
	Cost of Removal			27,926				25,869
	Net Operating Loss Carryforward			15,360				27,682
	Differences Related to Property			9,462				12,983
	Vacation Accrual			1,985				2,017
	Investment Tax Credits			1,960				2,554
	Other			4,045				10,853
	Total Deferred Tax Assets		$	215,413			$	223,255
	Deferred Tax Liabilities
	Differences Related to Property		$	(306,232	)		$	(301,991	)
	Retirement Benefits Regulatory Asset			(39,524	)			(34,618	)
	North Dakota Wind Tax Credits			(11,543	)			(11,923	)
	Excess Tax over Book Pension			(6,977	)			(6,995	)
	Impact of State Net Operating Losses on Federal Taxes			(3,088	)			(3,484	)
	Regulatory Asset			(1,805	)			(1,691	)
	Renewable Resource Rider Accrued Revenue			(329	)			(934	)
	Other			(6,066	)			(2,442	)
	Total Deferred Tax Liabilities		$	(375,564	)		$	(364,078	)
	Deferred Income Taxes		$	(160,151	)		$	(140,823	)

Schedule of expiration of tax net operating losses and tax credits available as of December 31, 2013:

(in thousands)		Amount				2014				2015				2016		2017			2024-33
United States
Federal Net Operating Losses		$	6,350			$	--			$	--			$	--	$	--	$	6,350
Federal Tax Credits			35,350				--				--				--		--		35,350
State Net Operating Losses			8,823				--				--				--		--		8,823
State Tax Credits			40,750				2,339				2,339				2,339		389		33,344

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 $10.3 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)		2013				2012				2011
Balance on January 1		$	4,436			$	12,138			$	900
Increases Related to Tax Positions for Prior Years			98				--				11,238
Decreases Related to Tax Positions for Prior Years			(295	)			(6,802	)			--
Uncertain Positions Resolved During Year			--				(900	)			--
Balance on December 31		$	4,239			$	4,436			$	12,138

The balance of unrecognized tax benefits as of December 31, 2013 would not reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2013 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, 2013.

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, 2013, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2010. 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, 2013 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 likely 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
Asset Retirement Obligations (AROs)	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations (AROs)	'
	16. 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 2013.

	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, 2013 and 2012 are presented in the following table:

	(in thousands)	2013		2012
	Asset Retirement Obligations
	Beginning Balance	$	5,207	$	4,808
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		(20	)
	Accrued Accretion		454		419
	Settlements		--		--
	Ending Balance	$	5,661	$	5,207
	Asset Retirement Costs Capitalized
	Beginning Balance	$	1,477	$	1,497
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		(20	)
	Settlements		--		--
	Ending Balance	$	1,477	$	1,477
	Accumulated Depreciation - Asset Retirement Costs Capitalized
	Beginning Balance	$	407	$	351
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		--
	Depreciation Expense		55		56
	Settlements		--		--
	Ending Balance	$	462	$	407
	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
Discontinued Operations	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	17. Discontinued Operations

	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 and Food Ingredient Processing segments were eliminated as a result of the sales of IMD, DMS and IPH. Following are summary presentations of the results of discontinued operations for the years ended December 31, 2013, 2012 and 2011, along with the major components of assets and liabilities of discontinued operations as of December 31, 2013 and 2012:

			For the Year Ended December 31, 2013
	(in thousands)		IMD				Wylie				Shrco				DMS				IPH				Intercompany Transactions Adjustment			Total
	Operating Revenues		$	--			$	--			$	2,016			$	--			$	--			$	--		$	2,016
	Operating Expenses			(988	)			640				2,622				(269	)			--				--			2,005
	Other Income			412				--				67				--				--				--			479
	Income Tax Expense (Benefit)			370				(256	)			(213	)			108				--				--			9
	Net Income (Loss) from Operations			1,030				(384	)			(326	)			161				--				--			481
	Gain on Disposition Before Taxes			--				--				16				200				--				--			216
	Income Tax Expense on Disposition			--				--				6				--				--				--			6
	Net Gain on Disposition			--				--				10				200				--				--			210
	Net Gain (Loss)		$	1,030			$	(384	)		$	(316	)		$	361			$	--			$	--		$	691

			For the Year Ended December 31, 2012
	(in thousands)		IMD				Wylie				Shrco				DMS				IPH				Intercompany Transactions Adjustment			Total
	Operating Revenues		$	186,151			$	--			$	32,563			$	16,362			$	--			$	(2,017	)	$	233,059
	Operating Expenses			184,462				179				36,163				14,741				--				(2,017	)		233,528
	Asset Impairment Charge			45,573				--				7,747				--				--				--			53,320
	Operating (Loss) Income			(43,884	)			(179	)			(11,347	)			1,621				--				--			(53,789	)
	Other Income			135				--				15				122				--				--			272
	Interest Expense			5,787				--				1,553				279				--				(7,444	)		175
	Income Tax (Benefit) Expense			(15,792	)			13				(4,021	)			1,734				106				2,978			(14,982	)
	Net Loss from Operations			(33,744	)			(192	)			(8,864	)			(270	)			(106	)			4,466			(38,710	)
	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		$	(33,744	)		$	(714	)		$	(8,864	)		$	(5,279	)		$	(106	)		$	4,466		$	(44,241	)

			For the Year Ended December 31, 2011
	(in thousands)		IMD				Wylie				Shrco				DMS				IPH				Intercompany Transactions Adjustment			Total
	Operating Revenues		$	201,921			$	49,884			$	39,863			$	89,558			$	28,125			$	(6,016	)	$	403,335
	Operating Expenses			218,542				55,927				41,478				85,244				24,046				(6,016	)		419,221
	Asset Impairment Charge			3,142				--				456				56,379				--				--			59,977
	Operating (Loss) Income			(19,763	)			(6,043	)			(2,071	)			(52,065	)			4,079				--			(75,863	)
	Other (Deductions) Income			(46	)			18				1				281				(228	)			(3	)		23
	Interest Expense			6,852				709				1,580				1,726				11				(10,636	)		242
	Income Tax (Benefit) Expense			(4,768	)			(2,683	)			(1,462	)			(16,058	)			1,462				4,254			(19,255	)
	Net (Loss) Income from Operations			(21,893	)			(4,051	)			(2,188	)			(37,452	)			2,378				6,379			(56,827	)
	(Loss) Gain on Disposition Before Taxes			--				(946	)			--				--				15,471				--			14,525
	Income Tax Expense on Disposition			--				2,854				--				--				2,997				--			5,851
	Net (Loss) Gain on Disposition			--				(3,800	)			--				--				12,474				--			8,674
	Net (Loss) Income		$	(21,893	)		$	(7,851	)		$	(2,188	)		$	(37,452	)		$	14,852			$	6,379		$	(48,153	)

			31-Dec-13												31-Dec-12
	(in thousands)		IMD				Shrco				Total				IMD				Shrco				Total
	Current Assets		$	--			$	38			$	38			$	1,367			$	17,120			$	18,487
	Investments			--				--				--				--				85				85
	Net Plant			--				--				--				--				520				520
	Assets of Discontinued Operations		$	--			$	38			$	38			$	1,367			$	17,725			$	19,092
	Current Liabilities		$	2,196			$	1,441			$	3,637			$	4,587			$	6,569			$	11,156
Liabilities of Discontinued Operations		$	2,196			$	1,441			$	3,637			$	4,587			$	6,569			$	11,156

Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:

(in thousands)		2013				2012
Warranty Reserve Balance, Beginning of Year		$	5,027			$	3,170
Provision for Warranties Issued During the Year			188				3,240
Less Settlements Made During the Year			(715	)			(1,342	)
Decrease in Warranty Estimates for Prior Years			(1,413	)			(41	)
Warranty Reserve Balance, End of Year		$	3,087			$	5,027

The warranty reserve balances as of December 31, 2013 and 2012 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.

SCHEDULE_1_CONDENSED_FINANCIAL

SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	Dec. 31, 2013
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)		2013				2012

	ASSETS

	Current Assets
	Cash and Cash Equivalents		$	7,907			$	44,802
	Accounts Receivable from Subsidiaries			1,736				3,587
	Interest Receivable from Subsidiaries			192				317
	Notes Receivable from Subsidiaries			5,703				17,157
	Deferred Income Taxes			28,853				14,790
	Other			947				1,594
	Total Current Assets			45,338				82,247

	Investments in Subsidiaries			541,291				716,453
	Notes Receivable from Subsidiaries			52,249				67,925
	Deferred Income Taxes			25,861				18,042
	Other Assets			25,456				24,584

	Total Assets		$	690,195			$	909,251

	LIABILITIES AND EQUITY

	Current Liabilities
	Accounts Payable to Subsidiaries		$	5,961			$	5,035
	Notes Payable to Subsidiaries			62,562				231,611
	Other			5,122				6,223
	Total Current Liabilities			73,645				242,869

	Other Noncurrent Liabilities			28,031				27,363

	Commitments and Contingencies

	Capitalization
	Long-Term Debt, Net of Current Maturities			53,689				101,545
	Cumulative Preferred Shares			--				15,500
	Common Shareholder Equity			534,830				521,974

	Total Capitalization			588,519				639,019

	Total Liabilities and Equity		$	690,195			$	909,251
	See accompanying notes to condensed financial statements.

	OTTER TAIL CORPORATION (PARENT COMPANY)
	Condensed Statements of Income--For the Years Ended December 31
	(in thousands)		2013				2012				2011

	Operating Loss
	Revenue		$	--			$	--			$	--
	Operating Expenses			14,150				15,197				15,798
	Operating Loss			(14,150	)			(15,197	)			(15,798	)

	Other Income (Expense)
	Equity Income (Loss) in Earnings of Subsidiaries			66,468				8,430				(4,205	)
	Loss on Early Retirement of Debt			(10,252	)			(13,106	)			--
	Interest Charges			(9,940	)			(13,994	)			(17,157	)
	Interest Charges to Subsidiaries			(494	)			(512	)			(290	)
	Interest Income from Subsidiaries			5,318				15,700				18,006
	Other Income			1,413				1,426				548
	Total Other Income (Expense)			52,513				(2,056	)			(3,098	)

Income Before Income Taxes – Continuing Operations			38,363				(17,253	)			(18,896	)
Income Tax Benefit			(12,502	)			(11,980	)			(5,653	)
Net Income (Loss) from Continuing Operations			50,865				(5,273	)			(13,243	)
Net Income (Loss) from Discontinued Operations			--				--				--
Total Net Income (Loss)			50,865				(5,273	)			(13,243	)
Preferred Dividend Requirement and Other Adjustments			513				736				1,058
Income (Loss) Available for Common Shares		$	50,352			$	(6,009	)		$	(14,301	)
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)		2013				2012				2011
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities		$	70,376			$	43,904			$	30,833

Cash Flows from Investing Activities
Return of Capital (Investment in Subsidiaries)			150,381				(137,726	)			(24,534	)
Debt (Issued to) Repaid by Subsidiaries			(141,919	)			239,452				98,521
Cash Used in Investing Activities			(37	)			(69	)			(99	)
Net Cash Provided by Investing Activities			8,425				101,657				73,888

Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash			-				-				(253	)
Net Short-Term (Repayments) Borrowings			-				-				(54,176	)
Proceeds from Issuance of Common Stock			1,821				-				-
Common Stock Issuance Expenses			(3	)			(370	)			-
Payments for Retirement of Capital Stock			(15,723	)			(111	)			(1,182	)
Proceeds from Issuance of Long-Term Debt			-				-				2,006
Short-Term and Long-Term Debt Issuance Expenses			(238	)			(700	)			(14	)
Payments for Retirement of Long-Term Debt			(47,846	)			(50,164	)			(117	)
Premium Paid for Early Retirement of Long-Term Debt			(9,889	)			(12,500	)			-
Dividends Paid and Other Distributions			(43,818	)			(43,976	)			(43,923	)
Net Cash Used in Financing Activities			(115,696	)			(107,821	)			(97,659	)
Net Change in Cash and Cash Equivalents			(36,895	)			37,740				7,062
Cash and Cash Equivalents at Beginning of Period			44,802				7,062				-
Cash and Cash Equivalents at End of Period		$	7,907			$	44,802			$	7,062


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, 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

As of December 31, 2012:

(in thousands)		Accounts				Interest				Current				Long-Term		Accounts		Current
		Receivable				Receivable				Notes				Notes		Payable		Notes
										Receivable				Receivable				Payable
Otter Tail Power Company		$	1,201			$	--			$	--			$	15,500	$	160	$	--
Vinyltech Corporation			2				32				--				8,500		--		8,251
Northern Pipe Products, Inc.			--				9				--				3,725		--		10,537
BTD Manufacturing, Inc.			41				107				--				28,500		--		1,773
IMD, Inc.			20				113				1,461				--		--		--
Shrco, Inc.			40				12				15,696				--		--		--
T.O. Plastics, Inc.			--				28				--				7,400		--		2,986
Aevenia, Inc.			50				7				--				1,800		--		1,480
Foley Company			40				9				--				2,500		--		1,189
Varistar Corporation			2,050				--				--				--		4,875		205,329
Otter Tail Energy Services Company			--				--				--				--		--		66
Otter Tail Assurance Limited			143				--				--				--		--		--
		$	3,587			$	317			$	17,157			$	67,925	$	5,035	$	231,611

Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows (in thousands):

		2013				2012				2011
Cash Dividends Paid to Parent by Subsidiaries		$	91,693			$	43,018			$	43,320

See Otter Tail Corporation’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.

Other schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2013
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, Plastics and Construction. See note 2 to the 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 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 $1,002,000 in 2013, $656,000 in 2012 and $628,000 in 2011. 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 2.96% in 2013, 2.98% in 2012 and 2.94% in 2011. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

	Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination accounted for under the purchase method of accounting, 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 2013, 2012 or 2011. 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, 2013 and 2012 consolidated balance sheets:

	(in thousands)		2013				2012
	Big Stone Plant:
	Electric Plant in Service		$	142,780			$	141,221
	Construction Work in Progress			94,913				22,335
	Accumulated Depreciation			(83,005	)			(80,588	)
	Net Plant		$	154,688			$	82,968
	Coyote Station:
	Electric Plant in Service		$	162,095			$	160,617
	Construction Work in Progress			303				578
	Accumulated Depreciation			(96,907	)			(93,564	)
	Net Plant		$	65,491			$	67,631

	OTP is a joint owner, with other regional utilities, in three Capacity Expansion 2020 (CapX2020) transmission lines with the following ownership interests: 14.8% in the Bemidji-Grand Rapids 230 kV line, 13.3% in the Fargo-Monticello 345 kV line, 4.9% 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 49.2% 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, 2013 and 2012 consolidated balance sheets:

	(in thousands)		2013				2012
	Electric Plant in Service		$	26,337			$	25,852
	Construction Work in Progress			71,205				30,171
	Accumulated Depreciation			(837	)			(483	)
	Net Plant		$	96,705			$	55,540

	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 the 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. Therefore, CCMC is not required to be consolidated in the Company’s 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, 2013 is $10.2 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, 2013 could be as high as $10.2 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 the fourth quarter of 2011, IMD, Inc. (IMD), the Company’s former wind tower manufacturer, recorded a $3.1 million asset impairment charge on its plant in Fort Erie, Ontario. IMD idled this plant in the fourth quarter of 2011, as the plant had completed all of its then current tower orders.
	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 sale of the Fort Erie fixed assets closed on September 6, 2012, the West Fargo transaction closed on October 31, 2012 and the Tulsa transaction closed on November 30, 2012.

	Otter Tail Energy Services Company (OTESCO) recorded asset impairment charges of $0.4 million in 2012 and $0.5 million in 2011 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 15 to the 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.
Revisions to Presentation	'
	Revisions to Presentation
	Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the years 2012 and 2011 were revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for 2013. The change in presentation of 2012 and 2011 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for 2012 or 2011.
Revenue Recognition	'
	Revenue Recognition
	Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as 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.

	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 for further discussion.

	Manufacturing operating revenues are recorded when products are shipped.

	The companies in the Construction segment 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. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

			2013				2012			2011
	Percentage-of-Completion Revenues			16.70%				17.00%			21.40%

	The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

			December 31,				December 31,
	(in thousands)		2013				2012
	Costs Incurred on Uncompleted Contracts		$	361,487			$	307,085
	Less Billings to Date			(377,608	)			(321,388	)
	Plus Estimated Earnings Recognized			6,477				1,762
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	(9,644	)		$	(12,541	)

	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:

			December 31,				December 31,
	(in thousands)		2013				2012
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts		$	4,063			$	3,663
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts			(13,707	)			(16,204	)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		$	(9,644	)		$	(12,541	)

	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 pretax charges of $0.6 million in 2013 compared with $14.9 million in 2012 and $7.0 million in 2011.

	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, 2013 and December 31, 2012 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 17 to consolidated financial statements.
Retainage	'
	Retainage
	Accounts Receivable 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)		2013				2012
	Accounts Receivable Retained by Customers		$	7,125	1		$	12,227
	1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.
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, 2013 and 2012:

			December 31,				December 31,
	(in thousands)		2013				2012
	Cost Method:
	Portion of IPH Sales Proceeds Held in Escrow Account1		$	--			$	1,500
	Economic Development Loan Pools			219				255
	Other			158				174
	Equity Method:
	Affordable Housing and Other Partnerships			43				117
	Marketable Securities Classified as Available-for-Sale			8,942				8,925
	Total Investments		$	9,362			$	10,971
	Less: IPH Escrow Funds Reported under Other Current Assets1			--				(1,500	)
	Investments		$	9,362			$	9,471
	1$1.5 million accessible within one year is classified and reported under other current assets.

	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, 2013. See further discussion below and under note 13.
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, 2013 and December 31, 2012:

	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 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

	December 31, 2012 (in thousands)		Level 1				Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts		$	--			$	292		$	210
	Forward Gasoline Purchase Contracts							136
	Money Market Fund - Escrow Account IPH Sale			1,500
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			110
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company							7,620
	U.S. Government Debt Securities – Held by Captive Insurance Company							1,305
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan			357
	Equity Securities - Nonqualified Retirement Savings Plan			125
	Total Assets		$	2,092			$	9,353		$	210
	Liabilities:
	Derivative Liabilities - Forward Energy Contracts		$	--			$	242		$	17,992
	Total Liabilities		$	--			$	242		$	17,992

	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 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, 2013 and December 31, 2012, are based on prices indexed to observable prices at an active trading hub. The Level 3 forward electric price inputs ranged from $6.95 per megawatt-hour under the active trading hub price to $3.11 per megawatt-hour over the active trading hub price. The weighted average price was $34.00 per megawatt-hour.

	In the table above, $117,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $11,679,000 of the fair value of the Level 3 forward energy contracts in a derivative liability position as of December 31, 2013 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, 2013 and 2012.

	The remaining $221,000 of the fair value of the Level 3 forward energy contracts in a derivative asset position and $103,000 of the fair value of the Level 2 forward energy contracts in a derivative liability position as of December 31, 2013 are related to financial contracts that will not be settled by physical delivery of electricity but will be settled financially by the counterparty to the contract paying or receiving the difference between the contract price and the market price at the hour of scheduled delivery. Although the related forward energy purchase and sales contracts are 100% offsetting in terms of volumes and delivery periods, the purchase contracts and offsetting sales contracts do not have the same delivery points. Therefore, the net derivative gain related to these contracts of $118,000 as of December 31, 2013 is subject to change in subsequent reporting periods or on settlement. These contracts are scheduled for settlement in January and February of 2014. Any fluctuation in the factors used in the fair valuation of these contracts would not result in a significant change to the net fair value of the contracts.

	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, 2013 and 2012:

	(in thousands)		2013				2012
	Forward Energy Contracts - Fair Values Beginning of Period		$	(17,782	)		$	--
Transfers into Level 3 from Level 2			--				(15,884	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods			7,943				5,135
Changes in Fair Value of Contracts Entered into in Prior Periods			(640	)			(4,001	)
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period			(10,479	)			(14,750	)
Net Decrease in Value of Open Contracts Entered into in Current Period			(862	)			(3,032	)
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period		$	(11,341	)		$	(17,782	)
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)		2013				2012
	Finished Goods		$	20,649			$	21,893
	Work in Process			9,942				8,800
	Raw Material, Fuel and Supplies			42,090				38,643
	Total Inventories		$	72,681			$	69,336
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.

	The following tables summarize changes to goodwill by business segment during 2013 and 2012:

			Gross Balance				Accumulated			Balance (net of			Adjustments			Balance (net of
	(in thousands)		December 31,				Impairments			impairments)			to Goodwill			impairments)
			2012							December 31,			in 2013			December 31,
										2012						2013
	Manufacturing		$	12,186			$	--		$	12,186		$	--		$	12,186
	Construction			7,483				--			7,483			--			7,483
	Plastics			19,302				--			19,302			--			19,302
	Total		$	38,971			$	--		$	38,971		$	--		$	38,971

			Gross Balance				Accumulated			Balance (net of			Adjustments			Balance (net of
	(in thousands)		December 31,				Impairments			impairments)			to Goodwill			impairments)
			2011							December 31,			in 2012			December 31,
										2011						2012
	Electric		$	240			$	(240	)	$	--		$	--		$	--
	Manufacturing			24,445				(12,259	)		12,186			--			12,186
	Construction			7,630				--			7,630			(147	)		7,483
	Plastics			19,302				--			19,302			--			19,302
	Total		$	51,617			$	(12,499	)	$	39,118		$	(147	)	$	38,971

	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:

	2013 (in thousands)		Gross Carrying				Accumulated Amortization			Net Carrying		Amortization
	2013 (in thousands)		Amount				Accumulated Amortization			Amount		Periods
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811			$	4,935		$	11,876	15 – 25 years
	Other Intangible Assets Including Contracts			825				473			352	5 – 30 years
	Total		$	17,636			$	5,408		$	12,228
	Indefinite-Lived Intangible Assets:
	Trade Name		$	1,100				--		$	1,100

	2012 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships		$	16,811			$	4,085		$	12,726	15 – 25 years
	Other Intangible Assets Including Contracts			1,092				613			479	5 – 30 years
	Total		$	17,903			$	4,698		$	13,205
	Indefinite-Lived Intangible Assets:
	Trade Name		$	1,100				--		$	1,100

	The amortization expense for these intangible assets was:

	(in thousands)		2013				2012			2011
	Amortization Expense – Intangible Assets		$	977			$	981		$	956

	The estimated annual amortization expense for these intangible assets for the next five years is:

	(in thousands)		2014				2015			2016			2017			2018
	Estimated Amortization Expense – Intangible Assets		$	977			$	977		$	945		$	849		$	849
Supplemental Disclosures of Cash Flow Information	'
	Supplemental Disclosures of Cash Flow Information

			As of December 31,
	(in thousands)		2013				2012
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1		$	22,951			$	9,967
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2		$	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)		2013				2012			2011
	Cash Paid (Received) During the Year for:
	Interest (net of amount capitalized)		$	26,789			$	30,741		$	34,434
	Income Tax Refunds		$	(453	)		$	(353	)	$	-257
New Accounting Standards	'
	New Accounting Standards

	Accounting Standards Update (ASU) 2011-11 and 2013-01
	In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), to clarify which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The amendments in ASU 2013-01 apply to derivatives accounted for in accordance with ASC 815 and clarify that only derivatives accounted for in accordance with ASC 815 are within the scope of the disclosure requirements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.

	The Company implemented the disclosure guidance January 1, 2013. While certain of the Company’s offsetting derivative asset and liability positions related to forward energy contracts with the same counterparty are subject to legally enforceable netting arrangements, the Company does not present its derivative assets and liabilities subject to legally enforceable netting arrangements, or any related payables or receivables, on a net basis on the face of its consolidated balance sheet. The Company has added disclosures and a table in note 5 to the consolidated financial statements indicating the amounts of its derivative forward energy contracts presented at fair value in accordance with ASC 815 that are subject to legally enforceable netting arrangements.

	ASU 2013-02
	In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, which requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under accounting principles generally accepted in the United States of America (U.S. GAAP) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail on these amounts. This ASU is effective for reporting periods beginning after December 15, 2012. Additional information required by this update is included on the face of the Company’s consolidated statement of comprehensive income for the period ending December 31, 2013. The amounts of accumulated other comprehensive losses associated with the Company’s pension and other post-retirement benefit programs that are being amortized and recognized as operating expenses and the income statement line item affected by the expense are disclosed in note 12 to the consolidated financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2013
Significant Accounting Policies [Line Items]	'
Shedule for ownership share of jointly owned tansmission facilities	'
	(in thousands)	2013			2012
	Big Stone Plant:
	Electric Plant in Service	$	142,780		$	141,221
	Construction Work in Progress		94,913			22,335
	Accumulated Depreciation		(83,005	)		(80,588	)
	Net Plant	$	154,688		$	82,968
	Coyote Station:
	Electric Plant in Service	$	162,095		$	160,617
	Construction Work in Progress		303			578
	Accumulated Depreciation		(96,907	)		(93,564	)
	Net Plant	$	65,491		$	67,631
Schedule of revenues recorded under the percentage-of-completion method	'
		2013			2012			2011
	Percentage-of-Completion Revenues		16.70%			17.00%			21.40%
Schedule of costs incurred and billings and estimated earnings	'
		December 31,			December 31,
	(in thousands)	2013			2012
	Costs Incurred on Uncompleted Contracts	$	361,487		$	307,085
	Less Billings to Date		(377,608	)		(321,388	)
	Plus Estimated Earnings Recognized		6,477			1,762
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(9,644	)	$	(12,541	)
Schedule of receivables from customers being retained pending project completion	'
		December 31,			December 31,
	(in thousands)	2013			2012
	Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	4,063		$	3,663
	Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(13,707	)		(16,204	)
	Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(9,644	)	$	(12,541	)
Schedule of accounts receivable retained by customers pending project completion	'
		December 31,			December 31,
	(in thousands)	2013			2012
	Accounts Receivable Retained by Customers	$	7,125	1	$	12,227
	1 Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.
Schedule of breakdown of Investments	'
		December 31,			December 31,
	(in thousands)	2013			2012
	Cost Method:
	Portion of IPH Sales Proceeds Held in Escrow Account1	$	--		$	1,500
	Economic Development Loan Pools		219			255
	Other		158			174
	Equity Method:
	Affordable Housing and Other Partnerships		43			117
	Marketable Securities Classified as Available-for-Sale		8,942			8,925
	Total Investments	$	9,362		$	10,971
	Less: IPH Escrow Funds Reported under Other Current Assets1		--			(1,500	)
	Investments	$	9,362		$	9,471
	1$1.5 million accessible within one year is classified and reported under other current assets.
Schedule of assets and liabilities that are measured at fair value on a recurring basis	'
	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 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

	December 31, 2012 (in thousands)	Level 1			Level 2			Level 3
	Assets:
	Current Assets – Other:
	Forward Energy Contracts	$	--		$	292		$	210
	Forward Gasoline Purchase Contracts					136
	Money Market Fund - Escrow Account IPH Sale		1,500
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		110
	Investments:
	Corporate Debt Securities – Held by Captive Insurance Company					7,620
	U.S. Government Debt Securities – Held by Captive Insurance Company					1,305
	Other Assets:
	Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		357
	Equity Securities - Nonqualified Retirement Savings Plan		125
	Total Assets	$	2,092		$	9,353		$	210
	Liabilities:
	Derivative Liabilities - Forward Energy Contracts	$	--		$	242		$	17,992
	Total Liabilities	$	--		$	242		$	17,992
Schedule of derivative asset and liability fair valuations	'
	(in thousands)	2013			2012
	Forward Energy Contracts - Fair Values Beginning of Period	$	(17,782	)	$	--
	Transfers into Level 3 from Level 2		--			(15,884	)
	Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		7,943			5,135
	Changes in Fair Value of Contracts Entered into in Prior Periods		(640	)		(4,001	)
	Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,479	)		(14,750	)
	Net Decrease in Value of Open Contracts Entered into in Current Period		(862	)		(3,032	)
	Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(11,341	)	$	(17,782	)
Schedule of inventories	'
		December 31,			December 31,
	(in thousands)	2013			2012
	Finished Goods	$	20,649		$	21,893
	Work in Process		9,942			8,800
	Raw Material, Fuel and Supplies		42,090			38,643
	Total Inventories	$	72,681		$	69,336
Schedule of changes to goodwill by business segment	'
		Gross Balance			Accumulated			Balance (net of				Adjustments			Balance (net of
	(in thousands)	December 31,			Impairments			impairments)				to Goodwill			impairments)
		2012						December 31,				in 2013			December 31,
								2012							2013
	Manufacturing	$	12,186		$	--		$	12,186			$	--		$	12,186
	Construction		7,483			--			7,483				--			7,483
	Plastics		19,302			--			19,302				--			19,302
	Total	$	38,971		$	--		$	38,971			$	--		$	38,971

		Gross Balance			Accumulated			Balance (net of				Adjustments			Balance (net of
	(in thousands)	December 31,			Impairments			impairments)				to Goodwill			impairments)
		2011						December 31,				in 2012			December 31,
								2011							2012
	Electric	$	240		$	(240	)	$	--			$	--		$	--
	Manufacturing		24,445			(12,259	)		12,186				--			12,186
	Construction		7,630			--			7,630				(147	)		7,483
	Plastics		19,302			--			19,302				--			19,302
	Total	$	51,617		$	(12,499	)	$	39,118			$	(147	)	$	38,971
Schedule of components of intangible assets	'
	2013 (in thousands)	Gross Carrying			Accumulated Amortization			Net Carrying			Amortization
	2013 (in thousands)	Amount			Accumulated Amortization			Amount			Periods
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811		$	4,935		$	11,876		15 – 25 years
	Other Intangible Assets Including Contracts		825			473			352		5 – 30 years
	Total	$	17,636		$	5,408		$	12,228
	Indefinite-Lived Intangible Assets:
	Trade Name	$	1,100			--		$	1,100

	2012 (in thousands)
	Amortizable Intangible Assets:
	Customer Relationships	$	16,811		$	4,085		$	12,726		15 – 25 years
	Other Intangible Assets Including Contracts		1,092			613			479		5 – 30 years
	Total	$	17,903		$	4,698		$	13,205
	Indefinite-Lived Intangible Assets:
	Trade Name	$	1,100			--		$	1,100
Schedule of amortization expense for intangible assets	'
	(in thousands)	2013			2012			2011
	Amortization Expense – Intangible Assets	$	977		$	981		$	956
Schedule of estimated annual amortization expense for intangible assets	'
	(in thousands)	2014			2015			2016				2017			2018
	Estimated Amortization Expense – Intangible Assets	$	977		$	977		$	945			$	849		$	849
Schedule of supplemental disclosure of cash flow information	'


		As of December 31,
	(in thousands)	2013			2012
	Noncash Investing Activities:
	Accounts Payable Outstanding Related to Capital Additions1	$	22,951		$	9,967
	Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	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)	2013			2012			2011
	Cash Paid (Received) During the Year for:
	Interest (net of amount capitalized)	$	26,789		$	30,741		$	34,434
	Income Tax Refunds	$	(453	)	$	(353	)	$	(257	)
Capacity Expansion 2020	'
Significant Accounting Policies [Line Items]	'
Shedule for ownership share of jointly owned tansmission facilities	'
	(in thousands)	2013			2012
	Electric Plant in Service	$	26,337		$	25,852
	Construction Work in Progress		71,205			30,171
	Accumulated Depreciation		(837	)		(483	)
	Net Plant	$	96,705		$	55,540
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, 2013
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:		2013				2012				2011
	United States of America			97.6	%			97.7	%			98.1	%
	Mexico			1.4	%			1	%			0.4	%
	Canada			0.9	%			1.1	%			1.4	%
	All Other Countries (none greater than 0.04%)			0.1	%			0.2	%			0.1	%
Schedule of information by business segments	'

	(in thousands)		2013				2012				2011
	Operating Revenue
	Electric		$	373,540			$	350,765			$	342,727
	Manufacturing			204,997				208,965				189,459
	Plastics			164,957				150,517				123,669
	Construction			149,910				149,092				184,657
	Intersegment Eliminations			(91	)			(100	)			(343	)
	Total		$	893,313			$	859,239			$	840,169
	Cost of Products Sold and Cost of Construction Revenues Earned
	Manufacturing		$	154,235			$	157,437			$	144,987
	Plastics			129,042				112,662				103,131
	Construction			133,430				147,107				173,654
	Intersegment Eliminations			(20	)			(68	)			(122	)
	Total		$	416,687			$	417,138			$	421,650
	Other Nonelectric Expenses
	Manufacturing		$	18,820			$	18,233			$	16,524
	Plastics			8,571				8,784				6,210
	Construction			11,855				12,353				11,886
	Corporate			12,755				13,283				14,897
	Intersegment Eliminations			(71	)			(32	)			(221	)
	Total		$	51,930			$	52,621			$	49,296
	Depreciation and Amortization
	Electric		$	43,125			$	42,051			$	40,283
	Manufacturing			11,194				12,208				12,116
	Plastics			3,350				3,118				3,377
	Construction			2,009				1,906				2,009
	Corporate			207				481				550
	Total		$	59,885			$	59,764			$	58,335
	Operating Income (Loss)
	Electric		$	62,455			$	61,025			$	63,453
	Manufacturing			20,748				21,087				15,832
	Plastics			23,994				25,953				10,951
	Construction			2,616				(12,274	)			(2,892	)
	Corporate			(12,962	)			(13,764	)			(15,447	)
	Total		$	96,851			$	82,027			$	71,897
	Interest Charges
	Electric		$	17,461			$	19,049			$	19,643
	Manufacturing			3,255				3,557				3,727
	Plastics			1,001				2,519				1,525
	Construction			456				1,039				947
	Corporate and Intersegment Eliminations			4,805				5,741				9,787
	Total		$	26,978			$	31,905			$	35,629


	(in thousands)		2013				2012				2011
	Income Tax Expense (Benefit) – Continuing Operations
	Electric		$	9,278			$	5,862			$	6,683
	Manufacturing			6,047				6,954				3,962
	Plastics			9,249				9,393				3,653
	Construction			850				(5,456	)			(1,484	)
	Corporate			(11,881	)			(14,620	)			(8,693	)
	Total		$	13,543			$	2,133			$	4,121
	Earnings (Loss) Available for Common Shares
	Electric		$	38,236			$	38,341			$	38,886
	Manufacturing			11,457				10,676				8,229
	Plastics			13,809				14,113				5,811
	Construction			1,310				(7,689	)			(2,204	)
	Corporate			(15,151	)			(17,209	)			(16,548	)
	Discontinued Operations			691				(44,241	)			(48,475	)
	Total		$	50,352			$	(6,009	)		$	(14,301	)
	Capital Expenditures
	Electric		$	149,467			$	101,919			$	49,707
Manufacturing			7,046				9,311				10,546
Plastics			3,273				2,819				2,414
Construction			4,630				1,576				2,645
Corporate			47				137				2,048
Total		$	164,463			$	115,762			$	67,360
Identifiable Assets
Electric		$	1,290,416			$	1,226,145			$	1,170,449
Manufacturing			119,302				114,933				124,872
Plastics			76,853				78,855				72,200
Construction			49,440				50,696				69,453
Corporate			59,970				112,616				53,619
Assets of Discontinued Operations			38				19,092				209,929
Total		$	1,596,019			$	1,602,337			$	1,700,522

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	12 Months Ended
Regulatory Assets and Liabilities (Tables)	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Schedule of amount of regulatory assets and liabilities	'

												Remaining
			31-Dec-13									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.

												Remaining
			31-Dec-12									Recovery/
	(in thousands)		Current			Long-Term			Total			Refund Period
	Regulatory Assets:
	Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1		$	8,411		$	109,538		$	117,949		see note
	Deferred Marked-to-Market Losses1			7,949			10,050			17,999		72 months
	Conservation Improvement Program Costs and Incentives2			3,707			2,560			6,267		18 months
	Accumulated ARO Accretion/Depreciation Adjustment1			--			4,137			4,137		asset lives
	Debt Reacquisition Premiums1			268			1,978			2,246		237 months
	Big Stone II Unrecovered Project Costs – Minnesota1			526			1,618			2,144		45 months
	Recoverable Fuel and Purchased Power Costs1			1,737			--			1,737		12 months
	Deferred Income Taxes1			--			1,691			1,691		asset lives
	North Dakota Renewable Resource Rider Accrued Revenues2			532			1,087			1,619		15 months
	MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1			--			1,352			1,352		see note
	Minnesota Renewable Resource Rider Accrued Revenues2			915			--			915		5 months
	Big Stone II Unrecovered Project Costs – North Dakota1			908			--			908		7 months
	Big Stone II Unrecovered Project Costs – South Dakota2			100			711			811		97 months
	General Rate Case Recoverable Expenses1			279			6			285		13 months
	North Dakota Transmission Rider Accrued Revenues2			110			--			110		12 months
	Deferred Holding Company Formation Costs1			55			27			82		18 months
	South Dakota Transmission Rider Accrued Revenue2			2			--			2		12 months
	Total Regulatory Assets		$	25,499		$	134,755		$	160,254
	Regulatory Liabilities:
	Accumulated Reserve for Estimated Removal Costs – Net of Salvage		$	--		$	65,960		$	65,960		asset lives
	Deferred Income Taxes			--			2,553			2,553		asset lives
Minnesota Transmission Rider Accrued Refund			489			--			489		12 months
Deferred Marked-to-Market Gains			8			210			218		68 months
Deferred Gain on Sale of Utility Property – Minnesota Portion			6			112			118		252 months
South Dakota – Nonasset-Based Margin Sharing Excess			56			--			56		12 months
Total Regulatory Liabilities		$	559		$	68,835		$	69,394
Net Regulatory Asset Position		$	24,940		$	65,920		$	90,860
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
Forward Contracts Classified as Derivatives (Tables)	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of electric wholesale revenues	'

	(in thousands)		2013				2012			2011
	Wholesale Sales - Company-Owned Generation		$	14,846			$	12,951		$	14,518
	Revenue from Settled Contracts at Market Prices			133,238				160,987			168,313
	Market Cost of Settled Contracts			(132,055	)			(159,500	)		(166,920	)
	Net Margins on Settled Contracts at Market			1,183				1,487			1,393
	Marked-to-Market Gains on Settled Contracts			3,039				7,864			10,208
	Marked-to-Market Losses on Settled Contracts			(2,722	)			(7,974	)		(10,176	)
	Net Marked-to-Market Gains (Losses) on Settled Contracts			317				(110	)		32
	Unrealized Marked-to-Market Gains on Open Contracts			215				284			3,707
	Unrealized Marked-to-Market Losses on Open Contracts			(100	)			(235	)		(2,813	)
	Net Unrealized Marked-to-Market Gains on Open Contracts			115				49			894
	Wholesale Electric Revenue		$	16,461			$	14,377		$	16,837
Schedule for balance sheet location and fair value amounts of the company's forward energy contracts classified as derivatives	'

	(in thousands)		31-Dec-13				31-Dec-12
	Other Current Asset – Marked-to-Market Gain		$	338			$	502
	Regulatory Asset – Current Deferred Marked-to-Market Loss			3,008				7,949
	Regulatory Asset – Long-Term Deferred Marked-to-Market Loss			8,674				10,050
	Total Assets			12,020				18,501
	Current Liability – Marked-to-Market Loss			(11,782	)			(18,234	)
	Regulatory Liability – Current Deferred Marked-to-Market Gain			(6	)			(8	)
	Regulatory Liability – Long-Term Deferred Marked-to-Market Gain			(117	)			(210	)
	Total Liabilities			(11,905	)			(18,452	)
	Net Fair Value of Marked-to-Market Energy Contracts		$	115			$	49
Schedule of change in the consolidated balance sheet position of the company's forward energy contracts classified as derivatives	'

	(in thousands)		Year ended				Year ended
	(in thousands)		31-Dec-13				31-Dec-12
	Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period		$	49			$	894
	Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods			(49	)			(861	)
	Changes in Fair Value of Contracts Entered into in Prior Periods			--				(33	)
	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				49
	Cumulative Fair Value Adjustments Included in Earnings - End of Period		$	115			$	49
Schedule of OTP's credit risk exposure on delivered and marked-to-market forward contracts	'

			31-Dec-13							31-Dec-12
	(in thousands)		Exposure				Counterparties			Exposure			Counterparties
	Net Credit Risk on Forward Energy Contracts		$	856				3		$	580			6
	Net Credit Risk to Single Largest Counterparty		$	530						$	285
Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements	'


	(in thousands)		31-Dec-13				31-Dec-12
	Derivative Assets Subject to Legally Enforceable Netting Arrangements		$	400			$	638
	Derivative Liabilities Subject to Legally Enforceable Netting Arrangements			(11,782	)			(18,234	)
	Net Balance Subject to Legally Enforceable Netting Arrangements		$	(11,382	)		$	(17,596	)
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,
	Current Liability – Marked-to-Market Loss (in thousands)	2013				2012
	Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--			$	2,176
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,679				16,058
	Loss Contracts with No Ratings Triggers or Deposit Requirements		103				--
	Total Current Liability – Marked-to-Market Loss	$	11,782			$	18,234
	1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
	Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	11,679			$	16,058
	Offsetting Gains with Counterparties under Master Netting Agreements		(117	)			(416	)
	Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	11,562			$	15,642

Common_Shares_and_Earnings_Per1

Common Shares and Earnings Per Share (Tables)	12 Months Ended
Common Shares and Earnings Per Share (Tables)	Dec. 31, 2013
Stockholders Equity and Earnings Per Share [Abstract]	'
Schedule of reconciliation of common shares outstanding from December 31, 2012 to December 31, 2013	'

	Common Shares Outstanding, December 31, 2012			36,168,368
	Issuances:
	Stock Options Exercised			56,109
	Vesting of Restricted Stock Units			17,535
	Restricted Stock Issued to Employees			17,000
	Restricted Stock Issued to Directors			17,333
	Director’s Compensation			4,535
	Retirements:
	Shares Withheld for Individual Income Tax Requirements			(7,184	)
	Forfeiture of Unvested Restricted Stock			(2,000	)
	Common Shares Outstanding, December 31, 2013			36,271,696
Schedule of outstanding stock options excluded from the calculation of diluted earnings per share	'

	Year	Options Outstanding	Range of Exercise Prices
	2013	--	--
	2012	92,497	$24.93 – $27.245
	2011	156,397	$24.93 – $31.34

ShareBased_Payments_Tables

Share-Based Payments (Tables)	12 Months Ended
Share-Based Payments (Tables)	Dec. 31, 2013
Schedule of stock options outstanding	'

	Exercise Price	Outstanding and	Remaining Contractual Life
		Exercisable as of
		12/31/13
	$24.93	17,900	Expire on April 10, 2015
	$26.50	16,800	Expire on April 11, 2014
Schedule of summary of stock options activity	'
	Stock Option Activity		2013				2012				2011
			Options		Average		Options		Average		Options		Average
					Exercise				Exercise				Exercise
					Price				Price				Price
	Outstanding, Beginning of Year			92,497	$	26.59		156,397	$	28.53		383,460	$	27.28
	Granted			--		--		--		--		--		--
	Exercised			56,109		27.12		--		--		--		--
	Forfeited or Expired			1,688		27.245		63,900		31.34		227,063		26.43
	Outstanding, End of Year			34,700		25.69		92,497		26.59		156,397		28.53
	Exercisable, End of Year			34,700		25.69		92,497		26.59		156,397		28.53
	Cash Received for Options Exercised				$	1,522,000				--				--
	Intrinsic Value of Options Exercised				$	152,000				--				--
	Fair Value of Options Granted During Year				none granted				none granted				none granted
Schedule of summary of the status of directors' restricted stock awards	'
	Directors’ Restricted Stock Awards		2013				2012				2011
			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			56,900	$	21.84		54,250	$	23.26		59,725	$	24.95
	Granted			17,333		30.77		24,000		21.32		24,000		22.51
	Vested			29,750		21.87		21,350		24.86		29,475		26.07
	Forfeited			2,000		31.03		--				--
	Nonvested, End of Year			42,483		25.03		56,900		21.84		54,250		23.26
	Compensation Expense Recognized				$	611,000			$	552,000			$	740,000
	Fair Value of Shares Vested in Year					651,000				531,000				768,000
Schedule of summary of the status of employees' restricted stock unit awards	'
	Employees’ Restricted Stock Unit Awards		2013				2012				2011
			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			60,665	$	18.11		73,815	$	20.95		79,315	$	23.55
	Granted			15,150		25.3		15,800		17.66		19,800		18.03
	Vested			17,535		18.73		20,750		27.13		20,025		27.94
	Forfeited			2,100		19.88		8,200		19.97		5,275		22.56
	Nonvested, End of Year			56,180		19.79		60,665		18.11		73,815		20.95
	Compensation Expense Recognized				$	275,000			$	256,000			$	349,000
	Fair Value of Units Converted in Year					328,000				563,000				559,000
Executive Officers	'
Schedule of compensation expense under stock-based payment programs	'
	Performance		Maximum Shares Subject		Shares Used		Grant		Expense Recognized						Shares Awarded
	Period		To Award		To Estimate Expense		Date Fair		in the Year Ended December 31,
							Value
									2013		2012		2011
	2013-2015			100,400		50,200	$	37.51	$	580,000	$	--	$	--		--
	2012-2014			161,600		80,800	$	21.75		1,686,000		1,001,000		--		--
	2011-2013			97,200		48,600	$	23.61		412,000		254,000		553,000		48,730
	2010-2012			146,800		73,400	$	20.97		--		--		572,000		49,500
	2009-2011			181,200		90,600	$	27.98		--		--		746,000		64,500
	Total								$	2,678,000	$	1,255,000	$	1,871,000		162,730
Restricted Stock \| Employee	'
Schedule of compensation expense under stock-based payment programs	'
	Employees’ Restricted Stock Awards		2013				2012				2011
			Shares		Weighted Average		Shares		Weighted		Shares		Weighted
					Grant-Date				Average				Average
					Fair Value				Grant-Date				Grant-Date
									Fair Value				Fair Value
	Nonvested, Beginning of Year			47,645	$	21.82		34,868	$	22.86		66,161	$	24.79
	Granted			17,000		31.03		26,120		21.48		24,600		22.51
	Awards Vested			16,330		21.89		11,518		24.14		55,893		25
	Forfeited			--				1,825		22.2		--
	Nonvested, End of Year			48,315		25.04		47,645		21.82		34,868		22.86
	Compensation Expense Recognized				$	427,000			$	325,000			$	832,000
	Fair Value of Awards Vested					358,000				278,000				1,397,000

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of amounts of commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases	'
		Capacity and		Coal and Freight		Operating Leases
		Energy		Purchase		Operating Leases
	(in thousands)	Requirements		Commitments		OTP		Nonelectric		Total
	2014	$	22,565	$	50,149	$	2,519	$	5,695	$	8,214
	2015		30,468		20,790		1,649		4,533		6,182
	2016		22,812		21,041		1,309		3,756		5,065
	2017		22,123		23,599		978		2,419		3,397
	2018		25,808		23,135		989		1,554		2,543
	Beyond 2018		223,561		621,814		11,812		325		12,137
	Total	$	347,337	$	760,528	$	19,256	$	18,282	$	37,538

ShortTerm_and_LongTerm_Borrowi1

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Tables)	12 Months Ended
	Dec. 31, 2013
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,
				2013		Letters of Credit		2013		2012
	Otter Tail Corporation Credit Agreement	$	150,000	$	--	$	659	$	149,341	$	149,267
	OTP Credit Agreement		170,000		51,195		1,830		116,975		166,811
	Total	$	320,000	$	51,195	$	2,489	$	266,316	$	316,078
Schedule of aggregate amounts of maturities on bonds outstanding and other long-term obligations	'
	(in thousands)	2014		2015		2016		2017		2018
	Aggregate amounts of Debt Maturities	$	188	$	41,101	$	52,544	$	33,228	$	187
Schedule of short-term and long-term debt outstanding	'
	December 31, 2013 (in thousands)	OTP		Otter Tail Corporation		Otter Tail 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
	Other Obligations - Various up to 3.95% at December 31, 2013		--		1,548		1,548
	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

	December 31, 2012 (in thousands)	OTP		Otter Tail		Otter Tail
				Corporation		Corporation
						Consolidated
	Short-Term Debt	$	--	$	--	$	--
	Long-Term Debt:
	9.000% Notes, due December 15, 2016			$	100,000	$	100,000
	Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
	Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017		5,065				5,065
	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
	Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022		20,070				20,070
	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
	Other Obligations - Various up to 3.95% at December 31, 2012				1,725		1,725
	Total	$	320,135	$	101,725	$	421,860
	Less: Current Maturities		--		176		176
	Unamortized Debt Discount		--		4		4
	Total Long-Term Debt	$	320,135	$	101,545	$	421,680
	Total Short-Term and Long-Term Debt (with current maturities)	$	320,135	$	101,721	$	421,856

Pension_Plan_and_Other_Postret1

Pension Plan and Other Postretirement Benefits (Tables)	12 Months Ended
Pension Plan and Other Postretirement Benefits (Tables)	Dec. 31, 2013
Pension Plan	'
Schedule of components of net periodic benefit cost	'
	(in thousands)		2013				2012				2011
	Service Cost–Benefit Earned During the Period		$	5,594			$	5,084			$	4,415
	Interest Cost on Projected Benefit Obligation			12,123				12,465				12,666
	Expected Return on Assets			(14,521	)			(14,430	)			(14,140	)
	Amortization of Prior-Service Cost:
	From Regulatory Asset			333				398				423
	From Other Comprehensive Income1			9				11				11
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			6,600				4,910				2,549
	From Other Comprehensive Income1			176				131				68
	Net Periodic Pension Cost		$	10,314			$	8,569			$	5,992
	1Corporate cost included in Other Nonelectric Expenses.
Schedule of weighted-average assumptions used to determine net periodic benefit cost	'
			2013				2012				2011
	Discount Rate			4.5	%			5.15	%			6	%
	Long-Term Rate of Return on Plan Assets			7.75	%			8	%			8	%
	Rate of Increase in Future Compensation Level			3.13	%			3.38	%			3.75	%
Schedule of amounts recognized in consolidated balance sheets	'

	(in thousands)		2013				2012
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	776			$	1,109
	Unrecognized Actuarial Loss			56,051				98,808
	Total Regulatory Assets		$	56,827			$	99,917

	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	28			$	37
	Unrecognized Actuarial Loss			448				1,857
	Total Accumulated Other Comprehensive Loss		$	476			$	1,894
	Noncurrent Liability		$	40,422			$	84,616
Schedule of funded status	'
	(in thousands)		2013				2012
	Accumulated Benefit Obligation		$	(224,365	)		$	(238,706	)

	Projected Benefit Obligation		$	(254,039	)		$	(275,634	)
	Fair Value of Plan Assets			213,617				191,018
	Funded Status		$	(40,422	)		$	(84,616	)
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	'
	(in thousands)		2013				2012
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	191,018			$	168,603
	Actual Return on Plan Assets			23,044				22,656
	Discretionary Company Contributions			10,000				10,000
	Benefit Payments			(10,445	)			(10,241	)
	Fair Value of Plan Assets at December 31		$	213,617			$	191,018
	Estimated Asset Return			11.8	%			13.4	%
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	275,634			$	246,098
	Service Cost			5,594				5,084
	Interest Cost			12,123				12,465
	Benefit Payments			(10,445	)			(10,241	)
	Actuarial (Gain) Loss			(28,867	)			22,228
	Projected Benefit Obligation at December 31		$	254,039			$	275,634
Schedule of weighted average assumptions used to determine benefit obligations	'
			2013				2012
	Discount Rate			5.3	%			4.5	%
	Rate of Increase in Future Compensation Level			3.13	%			3.13	%
Schedule of measurement dates	'
	Measurement Dates:	2013	2012
	Net Periodic Pension Cost	1-Jan-13	1-Jan-12

	End of Year Benefit Obligations	January 1, 2013 projected to	January 1, 2012 projected to
	End of Year Benefit Obligations	31-Dec-13	31-Dec-12

	Market Value of Assets	31-Dec-13	31-Dec-12
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	'
	(in thousands)		2014
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	257
	Amortization of Unrecognized Actuarial Loss			3,477
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			7
	Amortization of Unrecognized Actuarial Loss			93
	Total Estimated Amortization		$	3,834
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	'
	(in thousands)		2014				2015				2016			2017			2018		Years
	(in thousands)		2014				2015				2016			2017			2018		2019-2023
			$	11,304			$	11,772			$	12,363		$	13,014		$	13,801	$	80,569
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		2013				2012
	Large Capitalization Equity Securities			21	%			24.7	%
	International Equity Securities			21.7	%			17.8	%
	Small and Mid-Capitalization Equity Securities			8.5	%			7.1	%
	SEI Dynamic Asset Allocation Fund			5.2	%			4.8	%
	Equity Securities			56.4	%			54.4	%
	Fixed-Income Securities and Cash			39.3	%			41.1	%
	Other - SEI Special Situation Collective Investment Trust			4.3	%			4.5	%
				100	%			100	%
Schedule of pension fund assets measured at fair value	'
	2013 (in thousands)		Level 1				Level 2				Level 3

	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			$	--

	2012 (in thousands)
	Large Capitalization Equity Securities Mutual Fund		$	47,083
	International Equity Securities Mutual Funds			34,088
	Small and Mid-Capitalization Equity Securities Mutual Fund			13,613
	SEI Dynamic Asset Allocation Mutual Fund			9,177
	Fixed Income Securities Mutual Funds			78,480
	Cash Management – Working Capital Account			11
	SEI Special Situation Collective Investment Trust Fund										$	8,566
	Total Assets		$	182,452			$	--			$	8,566
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'
Schedule of components of net periodic benefit cost	'
	(in thousands)		2013				2012				2011
	Service Cost–Benefit Earned During the Period		$	51			$	45			$	81
	Interest Cost on Projected Benefit Obligation			1,408				1,479				1,632
	Amortization of Prior Service Cost:
	From Regulatory Asset			22				22				42
	From Other Comprehensive Income1			51				51				31
	Amortization of Net Actuarial Loss:
	From Regulatory Asset			208				175				142
	From Other Comprehensive Income2			313				152				103
	Net Periodic Pension Cost		$	2,053			$	1,924			$	2,031
	1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses		$	20			$	20			$	--
	Other Nonelectric Expenses			31				31				31
	2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
	Electric Operation and Maintenance Expenses		$	193			$	162			$	--
	Other Nonelectric Expenses			120				(10	)			103
Schedule of weighted-average assumptions used to determine net periodic benefit cost	'
		2013				2012				2011
	Discount Rate			4.5	%			5.15	%			6	%
	Rate of Increase in Future Compensation Level			3.19	%			4.59	%			4.65	%
Schedule of amounts recognized in consolidated balance sheets	'

	(in thousands)		2013				2012
	Regulatory Assets:
	Unrecognized Prior Service Cost		$	113			$	135
	Unrecognized Actuarial Loss			1,971				2,788
	Total Regulatory Assets		$	2,084			$	2,923
	Projected Benefit Obligation Liability – Net Amount Recognized		$	(29,321	)		$	(31,925	)
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	261			$	312
	Unrecognized Actuarial Loss			2,465				5,095
	Total Accumulated Other Comprehensive Loss		$	2,726			$	5,407
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	'
	(in thousands)		2013				2012
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	--			$	--
	Actual Return on Plan Assets			--				--
	Employer Contributions			1,137				1,259
	Benefit Payments			(1,137	)			(1,259	)
	Fair Value of Plan Assets at December 31		$	--			$	--
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	31,925			$	29,323
	Service Cost			51				45
	Interest Cost			1,408				1,479
	Benefit Payments			(1,137	)			(1,259	)
	Plan Amendments			--				--
	Actuarial (Gain) Loss			(2,926	)			2,337
	Projected Benefit Obligation at December 31		$	29,321			$	31,925
	Reconciliation of Funded Status:
	Funded Status at December 31		$	(29,321	)		$	(31,925	)
	Unrecognized Net Actuarial Loss			4,436				7,882
	Unrecognized Prior Service Cost			374				448
	Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost		$	(24,511	)		$	(23,595	)
Schedule of weighted average assumptions used to determine benefit obligations	'
			2013				2012
	Discount Rate			5.30%				4.50%
	Rate of Increase in Future Compensation Level			3.18%				3.19%
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	'
	(in thousands)		2014
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	22
	Amortization of Unrecognized Actuarial Loss			142
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			51
	Amortization of Unrecognized Actuarial Loss			46
	Total Estimated Amortization		$	261
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	'
																			Years
	(in thousands)		2014				2015				2016			2017			2018		2019-2023
			$	1,178			$	1,392			$	1,381		$	1,359		$	1,402	$	8,939
Other Postretirement Benefits	'
Schedule of components of net periodic benefit cost	'

	(in thousands)		2013				2012				2011
	Service Cost–Benefit Earned During the Period		$	1,421			$	1,544			$	1,275
	Interest Cost on Projected Benefit Obligation			2,050				2,574				2,384
	Amortization of Transition Obligation
	From Regulatory Asset			--				729				729
	From Other Comprehensive Income1			--				19				19
	Amortization of Prior Service Cost
	From Regulatory Asset			205				206				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		$	3,706			$	5,736			$	4,618
	Effect of Medicare Part D Subsidy		$	(1,806	)		$	(2,039	)		$	(2,118	)
	1Corporate cost included in Other Nonelectric Expenses.

Schedule of weighted-average assumptions used to determine net periodic benefit cost	'

			2013				2012				2011
	Discount Rate			4.25	%			5.05	%			5.75	%
Schedule of amounts recognized in consolidated balance sheets	'

	(in thousands)		2013				2012
	Regulatory Asset:
	Unrecognized Prior Service Cost		$	540			$	745
	Unrecognized Net Actuarial (Gain) Loss			(344	)			14,364
	Net Regulatory Asset		$	196			$	15,109
	Projected Benefit Obligation Liability – Net Amount Recognized		$	(45,221	)		$	(58,883	)
	Accumulated Other Comprehensive Loss:
	Unrecognized Prior Service Cost		$	18			$	23
	Unrecognized Net Actuarial (Gain) Loss			(261	)			177
	Accumulated Other Comprehensive (Gain) Loss		$	(243	)		$	200
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations	'
	(in thousands)		2013				2012
	Reconciliation of Fair Value of Plan Assets:
	Fair Value of Plan Assets at January 1		$	--			$	--
	Actual Return on Plan Assets			--				--
	Company Contributions			2,012				1,956
	Benefit Payments (Net of Medicare Part D Subsidy)			(4,626	)			(4,296	)
	Participant Premium Payments			2,614				2,340
	Fair Value of Plan Assets at December 31		$	--			$	--
	Reconciliation of Projected Benefit Obligation:
	Projected Benefit Obligation at January 1		$	58,883			$	48,263
	Service Cost (Net of Medicare Part D Subsidy)			1,421				1,544
	Interest Cost (Net of Medicare Part D Subsidy)			2,050				2,575
	Benefit Payments (Net of Medicare Part D Subsidy)			(4,626	)			(4,296	)
	Participant Premium Payments			2,614				2,340
	Actuarial (Gain) Loss			(15,121	)			8,457
	Projected Benefit Obligation at December 31		$	45,221			$	58,883
	Reconciliation of Accrued Postretirement Cost:
	Accrued Postretirement Cost at January 1		$	(43,574	)		$	(39,794	)
	Expense			(3,706	)			(5,736	)
	Net Company Contribution			2,012				1,956
	Accrued Postretirement Cost at December 31		$	(45,268	)		$	(43,574	)
Schedule of weighted average assumptions used to determine benefit obligations	'
			2013				2012
	Discount Rate			5.10%				4.25%
Schedule of healthcare cost-trend rates	'
			2013				2012
	Healthcare Cost-Trend Rate Assumed for Next Year Pre-65			6.47%				6.62%
	Healthcare Cost-Trend Rate Assumed for Next Year Post-65			6.82%				7.01%
	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
Schedule of effects of one percentage change in assumed healthcare cost-trend rates	'
	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 2013 would have the following effects:

	(in thousands)		1 Point				1 Point
	(in thousands)		Increase				Decrease
	Effect on the Postretirement Benefit Obligation		$	5,306			$	(4,449	)
	Effect on Total of Service and Interest Cost		$	634			$	(500	)
	Effect on Expense		$	1,266			$	(525	)
Schedule of measurement dates	'
	Measurement Dates:	2013	2012
	Net Periodic Postretirement Benefit Cost	1-Jan-13	1-Jan-12

	End of Year Benefit Obligations	January 1, 2013 projected to	January 1, 2012 projected to
	End of Year Benefit Obligations	31-Dec-13	31-Dec-12
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized	'
	(in thousands)		2014
	Decrease in Regulatory Assets:
	Amortization of Unrecognized Prior Service Cost		$	205
	Decrease in Accumulated Other Comprehensive Loss:
	Amortization of Unrecognized Prior Service Cost			5
	Total Estimated Amortization		$	210
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets	'
																			Years
	(in thousands)		2014				2015				2016			2017			2018		2019-2023
			$	2,653			$	2,785			$	2,899		$	3,061		$	3,206	$	17,207

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
Fair Value of Financial Instruments (Tables)	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of long-term debt including current maturities	'
		31-Dec-13						31-Dec-12
	(in thousands)	Carrying			Fair Value			Carrying			Fair Value
	(in thousands)	Amount			Fair Value			Amount			Fair Value
	Cash and Cash Equivalents	$	1,150		$	1,150		$	52,362		$	52,362
	Short-Term Debt		(51,195	)		(51,195	)		--			--
	Long-Term Debt including Current Maturities		(389,777	)		(427,796	)		(421,856	)		(491,244	)

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Schedule of property, plant and equipment	'
	(in thousands)	December 31,		December 31,
	(in thousands)	2013		2012
	Electric Plant in Service
	Production	$	679,067	$	672,120
	Transmission		270,606		261,447
	Distribution		421,803		405,461
	General		89,408		84,275
	Electric Plant in Service		1,460,884		1,423,303
	Construction Work in Progress		184,780		75,758
	Total Gross Electric Plant		1,645,664		1,499,061
	Less Accumulated Depreciation and Amortization		554,818		526,467
	Net Electric Plant	$	1,090,846	$	972,594
	Nonelectric Operations Plant
	Equipment	$	153,098	$	144,901
	Buildings and Leasehold Improvements		38,074		37,209
	Land		3,700		3,984
	Nonelectric Operations Plant		194,872		186,094
	Construction Work in Progress		2,681		2,132
	Total Gross Nonelectric Plant		197,553		188,226
	Less Accumulated Depreciation and Amortization		121,383		111,368
	Net Nonelectric Operations Plant	$	76,170	$	76,858
	Net Plant	$	1,167,016	$	1,049,452
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
Income Taxes (Tables)	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of income from continuing operations before income taxes and income tax expense	'

	(in thousands)	2013			2012			2011
	Tax Computed at Federal Statutory Rate	$	22,301		$	14,385		$	13,661
	Increases (Decreases) in Tax from:
	Federal Production Tax Credit		(6,612	)		(6,695	)		(7,281	)
	State Income Taxes Net of Federal Income Tax Expense (Benefit)		1,667			(849	)		798
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(863	)		(891	)		(996	)
	Corporate Owned Life Insurance		(856	)		(585	)		(388	)
	Allowance for Funds Used During Construction - Equity		(638	)		(409	)		(301	)
	Dividend Received/Paid Deduction		(632	)		(656	)		(677	)
	Investment Tax Credit Amortization		(597	)		(720	)		(855	)
	Tax Depreciation - Treasury Grant for Wind Farms		(304	)		(304	)		(507	)
	Differences Reversing in Excess of Federal Rates		(100	)		(143	)		680
	Impact of Medicare Part D Change		--			(584	)		(599	)
	Permanent and Other Differences		177			(416	)		586
	Total Income Tax Expense – Continuing Operations	$	13,543		$	2,133		$	4,121
	Income Tax Expense (Benefit) – Discontinued Operations – U.S.		15			(14,667	)		(13,325	)
	Income Tax (Benefit) – Discontinued Operations – Foreign		--			--			(79	)
	Income Tax Expense (Benefit) – Continuing and Discontinued Operations	$	13,558		$	(12,534	)	$	(9,283	)
	Overall Effective Federal, State and Foreign Income Tax Rate		21	%		70.4	%		41.2	%

	Income Tax Expense From Continuing Operations Includes the Following:
	Current Federal Income Taxes	$	146		$	(7,198	)	$	(4,303	)
	Current State Income Taxes		37			(1,402	)		(754	)
	Deferred Federal Income Taxes		18,310			15,878			14,308
	Deferred State Income Taxes		3,122			3,161			4,002
	Federal Production Tax Credit		(6,612	)		(6,695	)		(7,281	)
	North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(863	)		(891	)		(996	)
	Investment Tax Credit Amortization		(597	)		(720	)		(855	)
	Total	$	13,543		$	2,133		$	4,121
	Income (Loss) Before Income Taxes – U.S.	$	63,924		$	(13,426	)	$	(7,547	)
	Income (Loss) Before Income Taxes – Foreign (Discontinued Operations)		499			(4,381	)		(14,979	)
	Total Income (Loss) Before Income Taxes – Continuing and Discontinued Operations	$	64,423		$	(17,807	)	$	(22,526	)
Schedule of deferred tax assets and liabilities	'
	(in thousands)	2013			2012
	Deferred Tax Assets
	North Dakota Wind Tax Credits	$	42,241		$	44,172
	Retirement Benefits Liabilities		39,524			34,618
	Benefit Liabilities		39,290			35,459
	Federal Production Tax Credits		33,620			27,048
	Cost of Removal		27,926			25,869
	Net Operating Loss Carryforward		15,360			27,682
	Differences Related to Property		9,462			12,983
	Vacation Accrual		1,985			2,017
	Investment Tax Credits		1,960			2,554
	Other		4,045			10,853
	Total Deferred Tax Assets	$	215,413		$	223,255
	Deferred Tax Liabilities
	Differences Related to Property	$	(306,232	)	$	(301,991	)
	Retirement Benefits Regulatory Asset		(39,524	)		(34,618	)
	North Dakota Wind Tax Credits		(11,543	)		(11,923	)
	Excess Tax over Book Pension		(6,977	)		(6,995	)
	Impact of State Net Operating Losses on Federal Taxes		(3,088	)		(3,484	)
	Regulatory Asset		(1,805	)		(1,691	)
	Renewable Resource Rider Accrued Revenue		(329	)		(934	)
	Other		(6,066	)		(2,442	)
	Total Deferred Tax Liabilities	$	(375,564	)	$	(364,078	)
	Deferred Income Taxes	$	(160,151	)	$	(140,823	)
Schedule of expiration of tax net operating losses and tax credits available	'
	(in thousands)	Amount			2014			2015			2016		2017			2024-33
	United States
	Federal Net Operating Losses	$	6,350		$	--		$	--		$	--	$	--	$	6,350
	Federal Tax Credits		35,350			--			--			--		--		35,350
	State Net Operating Losses		8,823			--			--			--		--		8,823
	State Tax Credits		40,750			2,339			2,339			2,339		389		33,344
Schedule of activity related to unrecognized tax benefits	'

	(in thousands)	2013			2012			2011
	Balance on January 1	$	4,436		$	12,138		$	900
	Increases Related to Tax Positions for Prior Years		98			--			11,238
	Decreases Related to Tax Positions for Prior Years		(295	)		(6,802	)		--
	Uncertain Positions Resolved During Year		--			(900	)		--
	Balance on December 31	$	4,239		$	4,436		$	12,138

Asset_Retirement_Obligations_A1

Asset Retirement Obligations (AROs) (Tables)	12 Months Ended
Asset Retirement Obligations (AROs) (Tables)	Dec. 31, 2013
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)	2013		2012
	Asset Retirement Obligations
	Beginning Balance	$	5,207	$	4,808
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		(20	)
	Accrued Accretion		454		419
	Settlements		--		--
	Ending Balance	$	5,661	$	5,207
	Asset Retirement Costs Capitalized
	Beginning Balance	$	1,477	$	1,497
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		(20	)
	Settlements		--		--
	Ending Balance	$	1,477	$	1,477
	Accumulated Depreciation - Asset Retirement Costs Capitalized
	Beginning Balance	$	407	$	351
	New Obligations Recognized		--		--
	Adjustments Due to Revisions in Cash Flow Estimates		--		--
	Depreciation Expense		55		56
	Settlements		--		--
	Ending Balance	$	462	$	407
	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
Discontinued Operations (Tables)	Dec. 31, 2013
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, 2013
	(in thousands)	IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	--		$	--		$	2,016		$	--		$	--		$	--		$	2,016
	Operating Expenses		(988	)		640			2,622			(269	)		--			--			2,005
	Other Income		412			--			67			--			--			--			479
	Income Tax Expense (Benefit)		370			(256	)		(213	)		108			--			--			9
	Net Income (Loss) from Operations		1,030			(384	)		(326	)		161			--			--			481
	Gain on Disposition Before Taxes		--			--			16			200			--			--			216
	Income Tax Expense on Disposition		--			--			6			--			--			--			6
	Net Gain on Disposition		--			--			10			200			--			--			210
	Net Gain (Loss)	$	1,030		$	(384	)	$	(316	)	$	361		$	--		$	--		$	691

		For the Year Ended December 31, 2012
	(in thousands)	IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	186,151		$	--		$	32,563		$	16,362		$	--		$	(2,017	)	$	233,059
	Operating Expenses		184,462			179			36,163			14,741			--			(2,017	)		233,528
	Asset Impairment Charge		45,573			--			7,747			--			--			--			53,320
	Operating (Loss) Income		(43,884	)		(179	)		(11,347	)		1,621			--			--			(53,789	)
	Other Income		135			--			15			122			--			--			272
	Interest Expense		5,787			--			1,553			279			--			(7,444	)		175
	Income Tax (Benefit) Expense		(15,792	)		13			(4,021	)		1,734			106			2,978			(14,982	)
	Net Loss from Operations		(33,744	)		(192	)		(8,864	)		(270	)		(106	)		4,466			(38,710	)
	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	$	(33,744	)	$	(714	)	$	(8,864	)	$	(5,279	)	$	(106	)	$	4,466		$	(44,241	)



		For the Year Ended December 31, 2011
	(in thousands)	IMD			Wylie			Shrco			DMS			IPH			Intercompany Transactions Adjustment			Total
	Operating Revenues	$	201,921		$	49,884		$	39,863		$	89,558		$	28,125		$	(6,016	)	$	403,335
	Operating Expenses		218,542			55,927			41,478			85,244			24,046			(6,016	)		419,221
	Asset Impairment Charge		3,142			--			456			56,379			--			--			59,977
	Operating (Loss) Income		(19,763	)		(6,043	)		(2,071	)		(52,065	)		4,079			--			(75,863	)
	Other (Deductions) Income		(46	)		18			1			281			(228	)		(3	)		23
	Interest Expense		6,852			709			1,580			1,726			11			(10,636	)		242
	Income Tax (Benefit) Expense		(4,768	)		(2,683	)		(1,462	)		(16,058	)		1,462			4,254			(19,255	)
	Net (Loss) Income from Operations		(21,893	)		(4,051	)		(2,188	)		(37,452	)		2,378			6,379			(56,827	)
	(Loss) Gain on Disposition Before Taxes		--			(946	)		--			--			15,471			--			14,525
	Income Tax Expense on Disposition		--			2,854			--			--			2,997			--			5,851
	Net (Loss) Gain on Disposition		--			(3,800	)		--			--			12,474			--			8,674
	Net (Loss) Income	$	(21,893	)	$	(7,851	)	$	(2,188	)	$	(37,452	)	$	14,852		$	6,379		$	(48,153	)


		31-Dec-13									31-Dec-12
	(in thousands)	IMD			Shrco			Total			IMD			Shrco			Total
	Current Assets	$	--		$	38		$	38		$	1,367		$	17,120		$	18,487
	Investments		--			--			--			--			85			85
	Net Plant		--			--			--			--			520			520
	Assets of Discontinued Operations	$	--		$	38		$	38		$	1,367		$	17,725		$	19,092
	Current Liabilities	$	2,196		$	1,441		$	3,637		$	4,587		$	6,569		$	11,156
	Liabilities of Discontinued Operations	$	2,196		$	1,441		$	3,637		$	4,587		$	6,569		$	11,156
Schedule of warranty reserves	'

	(in thousands)	2013			2012
	Warranty Reserve Balance, Beginning of Year	$	5,027		$	3,170
	Provision for Warranties Issued During the Year		188			3,240
	Less Settlements Made During the Year		(715	)		(1,342	)
	Decrease in Warranty Estimates for Prior Years		(1,413	)		(41	)
	Warranty Reserve Balance, End of Year	$	3,087		$	5,027

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - OTP's Ownership Interests in Assets and Liabilities of Big Stone Plant and Coyote Station (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Big Stone Plant	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Electric Plant in Service	$142,780	$141,221
Construction Work in Progress	94,913	22,335
Accumulated Depreciation	-83,005	-80,588
Net Plant	154,688	82,968
Coyote Station	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Electric Plant in Service	162,095	160,617
Construction Work in Progress	303	578
Accumulated Depreciation	-96,907	-93,564
Net Plant	65,491	67,631
Capacity Expansion 2020 (CapX2020) and MVP transmission facilities	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Electric Plant in Service	26,337	25,852
Construction Work in Progress	71,205	30,171
Accumulated Depreciation	-837	-483
Net Plant	$96,705	$55,540

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Asset impairment charge of DMI Industries, Inc. (Details 1) (USD $)	12 Months Ended		1 Months Ended	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012	Dec. 31, 2011
	Dec. 31, 2012	Dec. 31, 2011	IMD, Inc.	IMD, Inc.
Significant Accounting Policies [Line Items]	'	'	'	'
Long-Lived Assets (net of accumulated depreciation)	'	'	$45,285	'
Goodwill	'	'	288	'
Total Asset Impairment Charges	$432	$470	$45,573	$3,100

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Asset impairment charge of ShoreMaster's (Details 2) (USD $)	12 Months Ended		1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
	Dec. 31, 2012	Dec. 31, 2011	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	$432	$470	$7,747

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Percentages of Consolidated Revenues Recorded under Percentage-of-Completion Method (Details 3)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Percentage-of-Completion Revenues	16.70%	17.00%	21.40%

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts (Details 4) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Costs Incurred on Uncompleted Contracts	$361,487	$307,085
Less Billings to Date	-377,608	-321,388
Plus Estimated Earnings Recognized	6,477	1,762
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	($9,644)	($12,541)

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Costs and Estimated Earnings in Excess of Billings that are Included in Consolidated Balance Sheets (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$4,063	$3,663
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	-13,707	-16,204
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$9,644	$12,541

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - Accounts Receivable Retained by Customers Pending Project Completion (Details 6) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Accounting Policies [Abstract]	'		'
Accounts Receivable Retained by Customers	$7,125	[1]	$12,227

[1]	Includes $89,000 related to one project with an expected completion date beyond December 31, 2014.

Recovered_Sheet1

Summary of Significant Accounting Policies - Accounts Receivable Retained by Customers Pending Project Completion (Parentheticals) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Accounting Policies [Abstract]	'
Retainage related to projects in excess of one year	$89,000

Recovered_Sheet2

Summary of Significant Accounting Policies - Breakdown of Investments (Details 7) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Schedule of Investments [Line Items]	'		'
Marketable Securities Classified as Available-for-Sale	$8,942		$8,925
Total Investments	9,362		10,971
Investments	9,362		9,471
IPH Escrow Funds	'		'
Schedule of Investments [Line Items]	'		'
Cost Method	'	[1]	1,500	[1]
Less: IPH Escrow Funds Reported under Other Current Assets	'	[1]	1,500	[1]
Economic Development Loan Pools	'		'
Schedule of Investments [Line Items]	'		'
Cost Method	219		255
Other	'		'
Schedule of Investments [Line Items]	'		'
Cost Method	158		174
Affordable Housing and Other Partnerships	'		'
Schedule of Investments [Line Items]	'		'
Equity Method	$43		$117

[1]	$1.5 million accessible within one year is classified and reported under other current assets.

Recovered_Sheet3

Summary of Significant Accounting Policies - Breakdown of Investments (Parentheticals) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Investments [Line Items]	'	'
Other current assets	$7,747	$8,161
IPH Escrow Funds	'	'
Schedule of Investments [Line Items]	'	'
Other current assets	$1,500	$1,500

Recovered_Sheet4

Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details 8) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Level 1	'	'
Assets:	'	'
Total Assets	$976	$2,092
Liabilities:	'	'
Derivative Liabilities	'	'
Total Liabilities	'	'
Level 1 \| Forward Energy Contracts	'	'
Assets:	'	'
Derivative Assets	'	'
Liabilities:	'	'
Derivative Liabilities	'	'
Level 1 \| Money Market Fund	'	'
Assets:	'	'
Other Current Assets - Escrow Account IPH Sale	'	1,500
Level 1 \| Money Market and Mutual Funds	'	'
Assets:	'	'
Other Current Assets - Nonqualified Retirement Savings Plan	110	110
Other Assets - Nonqualified Retirement Savings Plan	866	357
Level 1 \| Equity Securities	'	'
Assets:	'	'
Other Assets - Nonqualified Retirement Savings Plan	'	125
Level 2	'	'
Assets:	'	'
Total Assets	9,004	9,353
Liabilities:	'	'
Total Liabilities	103	242
Level 2 \| Forward Energy Contracts	'	'
Assets:	'	'
Derivative Assets	'	292
Liabilities:	'	'
Derivative Liabilities	103	242
Level 2 \| Forward Gasoline Purchase Contracts	'	'
Assets:	'	'
Derivative Assets	62	136
Level 2 \| Corporate Debt Securities	'	'
Assets:	'	'
Investments of Captive Insurance Company	7,671	7,620
Level 2 \| U.S. Government Debt Securities	'	'
Assets:	'	'
Investments of Captive Insurance Company	1,271	1,305
Level 3	'	'
Assets:	'	'
Total Assets	338	210
Liabilities:	'	'
Total Liabilities	11,679	17,992
Level 3 \| Forward Energy Contracts	'	'
Assets:	'	'
Derivative Assets	338	210
Liabilities:	'	'
Derivative Liabilities	$11,679	$17,992

Recovered_Sheet5

Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 9) (Forward Energy Contracts, Level 3, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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	($17,782)	'
Transfers into Level 3 from Level 2	'	-15,884
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	7,943	5,135
Changes in Fair Value of Contracts Entered into in Prior Periods	-640	-4,001
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	-10,479	-14,750
Net Decrease in Value of Open Contracts Entered into in Current Period	-862	-3,032
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	($11,341)	($17,782)

Recovered_Sheet6

Summary of Significant Accounting Policies - Inventories (Details 10) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Finished Goods	$20,649	$21,893
Work in Process	9,942	8,800
Raw Material, Fuel and Supplies	42,090	38,643
Total Inventories	$72,681	$69,336

Recovered_Sheet7

Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details 11) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]	'	'	'
Gross Balance	'	$38,971	$51,617
Accumulated Impairments	'	'	-12,499
Goodwill [Roll Forward]	'	'	'
Balance (net of impairments)	38,971	39,118	'
Adjustments to Goodwill	'	-147	'
Balance (net of impairments)	38,971	38,971	'
Electric	'	'	'
Goodwill [Line Items]	'	'	'
Gross Balance	'	'	240
Accumulated Impairments	'	'	-240
Goodwill [Roll Forward]	'	'	'
Balance (net of impairments)	'	'	'
Adjustments to Goodwill	'	'	'
Balance (net of impairments)	'	'	'
Manufacturing	'	'	'
Goodwill [Line Items]	'	'	'
Gross Balance	'	12,186	24,445
Accumulated Impairments	'	'	-12,259
Goodwill [Roll Forward]	'	'	'
Balance (net of impairments)	12,186	12,186	'
Adjustments to Goodwill	'	'	'
Balance (net of impairments)	12,186	12,186	'
Construction	'	'	'
Goodwill [Line Items]	'	'	'
Gross Balance	'	7,483	7,630
Accumulated Impairments	'	'	'
Goodwill [Roll Forward]	'	'	'
Balance (net of impairments)	7,483	7,630	'
Adjustments to Goodwill	'	-147	'
Balance (net of impairments)	7,483	7,483	'
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_Sheet8

Summary of Significant Accounting Policies - Components of Intangible Assets (Details 12) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Amortizable Intangible Assets:	'	'
Amortized Intangible Assets, Gross Carrying Amount	17,636	17,903
Amortized Intangible Assets, Accumulated Amortization	5,408	4,698
Amortized Intangible Assets, Net Carrying Amount	12,228	13,205
Trade Name	'	'
Amortizable Intangible Assets:	'	'
Amortized Intangible Assets, Gross Carrying Amount	1,100	1,100
Amortized Intangible Assets, Accumulated Amortization	'	'
Amortized Intangible Assets, Net Carrying Amount	1,100	1,100
Customer Relationships	'	'
Amortizable Intangible Assets:	'	'
Amortized Intangible Assets, Gross Carrying Amount	16,811	16,811
Amortized Intangible Assets, Accumulated Amortization	4,935	4,085
Amortized Intangible Assets, Net Carrying Amount	11,876	12,726
Customer Relationships \| Minimum	'	'
Amortizable Intangible Assets:	'	'
Amortization Periods	'15 years	'15 years
Customer Relationships \| Maximum	'	'
Amortizable Intangible Assets:	'	'
Amortization Periods	'25 years	'25 years
Other Intangible Assets Including Contracts	'	'
Amortizable Intangible Assets:	'	'
Amortized Intangible Assets, Gross Carrying Amount	825	1,092
Amortized Intangible Assets, Accumulated Amortization	473	613
Amortized Intangible Assets, Net Carrying Amount	352	479
Other Intangible Assets Including Contracts \| Minimum	'	'
Amortizable Intangible Assets:	'	'
Amortization Periods	'5 years	'5 years
Other Intangible Assets Including Contracts \| Maximum	'	'
Amortizable Intangible Assets:	'	'
Amortization Periods	'30 years	'30 years

Recovered_Sheet9

Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details 13) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Amortization Expense - Intangible Assets	$977	$981	$956

Recovered_Sheet10

Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangible Assets (Details 14) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Accounting Policies [Abstract]	'
2014	$977
2015	977
2016	945
2017	849
2018	$849

Recovered_Sheet11

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information of Noncash Investing Activities (Details 15) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Noncash Investing Activities:	'		'
Accounts Payable Outstanding Related to Capital Additions	$22,951	[1]	$9,967	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$3,264	[2]	'	[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_Sheet12

Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information Of Cash Paid During Year (Details 16) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Paid (Received) During the Year for:	'	'	'
Interest (net of amount capitalized)	$26,789	$30,741	$34,434
Income Tax Refunds	($453)	($353)	($257)

Recovered_Sheet13

Summary of Significant Accounting Policies (Detail Textuals) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jun. 30, 2012

Dec. 31, 2011

Jun. 30, 2012

Sep. 06, 2012

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Forward Electricity Contracts

Big Stone Plant

Coyote Station

Minimum

Maximum

Electric Plant

Nonelectric Plant

IMD, Inc.

Otter Tail Energy Services Company

Shrco, Inc.

Otter Tail Power Company

Level 3

Minimum

Maximum

Minimum

Maximum

Nonbinding letter of interest with Trinity Industries, Inc. (Trinity)

Definitive agreements with Trinity Industries, Inc. (Trinity)

Big Stone Plant

Fargo Project

Brookings Project

Bemidji Project

Big Stone South - Brookings MVP

Big Stone South - Ellendale MVP

Capacity Expansion 2020

Significant Accounting Policies [Line Items]

Estimated useful lives of Property and equipment

'5 years

'70 years

'3 years

'40 years

Interest capitalized on a plant

$1,002,000

$656,000

$628,000

Provisions for utility depreciation

2.96%

2.98%

2.94%

Ownership interests

53.90%

35.00%

13.30%

4.90%

14.80%

50.00%

49.20%

Expanded capacity of projects

345

230

345

Asset Impairment Charge

432,000

470,000

45,573,000

3,100,000

400,000

500,000

7,747,000

Product warranty period (in years)

'1 year

'15 years

Nonbinding selling price DMI fixed assets

20,000,000

Fair value of DMI's assets

20,000,000

Working capital net of DMI Industries Inc

66,000,000

Noncash asset impairment charges (in dollars per share)

$0.76

$0.13

Noncash asset impairment charge (Net of tax benefit)

27,500,000

4,600,000

Fair value of assets

Electric inputs maximum deviation above active trading hub price per megawatt-hour

3.11

Electric inputs maximum deviation below active trading hub price per megawatt-hour

6.95

Electric inputs weighted average price per megawatt-hour

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

Net income impact of future fair valuation adjustments of contracts

Recovered_Sheet14

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, 2013
Coyote Creek Mining Company, L.L.C. (CCMC) \| Lignite Sales Agreement \| Otter Tail Power Company	'
Variable Interest Entity [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	$10.20

Recovered_Sheet15

Summary of Significant Accounting Policies (Detail Textuals 2) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
	Foley Company	Foley Company	Foley Company	Moorhead Electric, Inc. (MEI)
Significant Accounting Policies [Line Items]	'	'	'	'
Estimated costs on certain projects in excess of previous period estimates, Pretax charge	$600,000	$14,900,000	$7,000,000	'
Disposal of goodwill in connection with sale of MEI	'	'	'	$147,000

Recovered_Sheet16

Summary of Significant Accounting Policies (Details Textual 3) (Level 3, Forward Energy Contracts, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Significant Accounting Policies [Line Items]	'
Offsetting percentage	100.00%
Net derivative gain related to the contract	$118
Power Purchase Contracts	'
Significant Accounting Policies [Line Items]	'
Derivative Assets	117
Derivative Liabilities	11,679
Financial Contracts	'
Significant Accounting Policies [Line Items]	'
Derivative Assets	221
Derivative Liabilities	$103

Business_Combinations_Disposit2

Business Combinations, Dispositions and Segment Information - Percent of Sales Revenue by Country (Details) (Sales)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
United States Of America	'	'	'
Percentage of sales revenue	97.60%	97.70%	98.10%
Mexico	'	'	'
Percentage of sales revenue	1.40%	1.00%	0.40%
Canada	'	'	'
Percentage of sales revenue	0.90%	1.10%	1.40%
All Other Countries (none greater than 0.04%)	'	'	'
Percentage of sales revenue	0.10%	0.20%	0.10%

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	$893,313	$859,239	$840,169
Cost of Products Sold and Cost of Construction Revenues Earned	416,687	417,138	421,650
Other Nonelectric Expenses	51,930	52,621	49,296
Depreciation and Amortization	59,885	59,764	58,335
Operating Income (Loss)	96,851	82,027	71,897
Interest Charges	26,978	31,905	35,629
Income Tax Expense (Benefit) - Continuing Operations	13,543	2,133	4,121
Earnings (Loss) Available for Common Shares	50,352	-6,009	-14,301
Capital Expenditures	164,463	115,762	67,360
Identifiable Assets	1,596,019	1,602,337	1,700,522
Intersegment Eliminations	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	-91	-100	-343
Cost of Products Sold and Cost of Construction Revenues Earned	-20	-68	-122
Other Nonelectric Expenses	-71	-32	-221
Corporate and Intersegment Eliminations	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Interest Charges	4,805	5,741	9,787
Corporate	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Other Nonelectric Expenses	12,755	13,283	14,897
Depreciation and Amortization	207	481	550
Operating Income (Loss)	-12,962	-13,764	-15,447
Income Tax Expense (Benefit) - Continuing Operations	-11,881	-14,620	-8,693
Earnings (Loss) Available for Common Shares	-15,151	-17,209	-16,548
Capital Expenditures	47	137	2,048
Identifiable Assets	59,970	112,616	53,619
Discontinued Operations	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Earnings (Loss) Available for Common Shares	691	-44,241	-48,475
Identifiable Assets	38	19,092	209,929
Electric \| Operating Segments	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	373,540	350,765	342,727
Depreciation and Amortization	43,125	42,051	40,283
Operating Income (Loss)	62,455	61,025	63,453
Interest Charges	17,461	19,049	19,643
Income Tax Expense (Benefit) - Continuing Operations	9,278	5,862	6,683
Earnings (Loss) Available for Common Shares	38,236	38,341	38,886
Capital Expenditures	149,467	101,919	49,707
Identifiable Assets	1,290,416	1,226,145	1,170,449
Manufacturing \| Operating Segments	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	204,997	208,965	189,459
Cost of Products Sold and Cost of Construction Revenues Earned	154,235	157,437	144,987
Other Nonelectric Expenses	18,820	18,233	16,524
Depreciation and Amortization	11,194	12,208	12,116
Operating Income (Loss)	20,748	21,087	15,832
Interest Charges	3,255	3,557	3,727
Income Tax Expense (Benefit) - Continuing Operations	6,047	6,954	3,962
Earnings (Loss) Available for Common Shares	11,457	10,676	8,229
Capital Expenditures	7,046	9,311	10,546
Identifiable Assets	119,302	114,933	124,872
Construction \| Operating Segments	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	149,910	149,092	184,657
Cost of Products Sold and Cost of Construction Revenues Earned	133,430	147,107	173,654
Other Nonelectric Expenses	11,855	12,353	11,886
Depreciation and Amortization	2,009	1,906	2,009
Operating Income (Loss)	2,616	-12,274	-2,892
Interest Charges	456	1,039	947
Income Tax Expense (Benefit) - Continuing Operations	850	-5,456	-1,484
Earnings (Loss) Available for Common Shares	1,310	-7,689	-2,204
Capital Expenditures	4,630	1,576	2,645
Identifiable Assets	49,440	50,696	69,453
Plastics \| Operating Segments	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Operating Revenue	164,957	150,517	123,669
Cost of Products Sold and Cost of Construction Revenues Earned	129,042	112,662	103,131
Other Nonelectric Expenses	8,571	8,784	6,210
Depreciation and Amortization	3,350	3,118	3,377
Operating Income (Loss)	23,994	25,953	10,951
Interest Charges	1,001	2,519	1,525
Income Tax Expense (Benefit) - Continuing Operations	9,249	9,393	3,653
Earnings (Loss) Available for Common Shares	13,809	14,113	5,811
Capital Expenditures	3,273	2,819	2,414
Identifiable Assets	$76,853	$78,855	$72,200

Business_Combinations_Disposit4

Business Combinations, Dispositions and Segment Information (Detail Textuals)	12 Months Ended
	Dec. 31, 2013
	Segment
Business Combinations, Dispositions and Segment Information [Abstract]	'
Number of segments	4

Rate_and_Regulatory_Matters_De

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

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jun. 30, 2005

Dec. 31, 2013

Feb. 20, 2013

24-May-12

Jan. 31, 2013

Jan. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 11, 2012

Mar. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Oct. 10, 2013

Dec. 31, 2013

1-May-13

Apr. 25, 2011

Apr. 02, 2010

Apr. 25, 2011

Dec. 31, 2011

Apr. 02, 2010

31-May-13

Apr. 25, 2011

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2013

Aug. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2012

Dec. 31, 2013

Nov. 25, 2009

Jun. 25, 2010

Jul. 30, 2013

Mar. 31, 2013

Apr. 21, 2011

31-May-13

Mar. 31, 2011

Aug. 20, 2010

Nov. 12, 2013

Jan. 31, 2012

Dec. 31, 2010

Dec. 31, 2011

Aug. 25, 2013

Otter Tail Power Company

Conservation Improvement Program

Capacity Expansion 2020

Fargo Project

Big Stone Project

Brookings Project

Bemidji Project

Twin Cities La Crosse

Big Stone South - Ellendale MVP

Minnesota Public Utilities Commission

North Dakota Public Service Commission

South Dakota Public Utilities Commission

Federal Energy Regulatory Commission

Minimum

Project

Capacity Expansion 2020

Project

Capacity Expansion 2020

Transmission Cost Recovery Rider

Conservation Improvement Program

Renewable Resource Cost Recovery Rider

Renewable Energy Standards, Conservation, Renewable Resource Riders

2010 General Rate Case

General Rate Case

Big Stone Project

Big Stone South - Brookings MVP

Transmission Cost Recovery Rider

Renewable Resource Cost Recovery Rider

Environmental Cost Recovery Rider

General Rate Case

Big Stone Project

Big Stone South - Brookings MVP

2010 General Rate Case

Big Stone Project

Project

Big Stone South - Brookings MVP

Big Stone South - Ellendale MVP

Project

Fiscal Year 2011

Fiscal Year 2012

Fiscal Year 2016

Fiscal Year 2020

Fiscal Year 2025

Turbine

Property

Project

General Rate Case

Minimum

Maximum

Montana Dakota Utilities Co.

Regulatory Matters [Line Items]

Base rate increase requested by general rate case

8.01%

Interim rate increase requested by general rate case

3.80%

Revenue increase approved by MPUC

$5,000,000

$3,600,000

$643,000

Percentage of increase in base rate revenue approved by MPUC

3.76%

3.00%

2.32%

Big Stone II Investment cost incurred, recovery period

'5 years

'60 months

'36 months

'10 years

'5 years

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

Public utilities overall approximate rate increase to customers

1.60%

Public utilities interim rate increase approved

3.80%

Refundable interim rate difference to customers

3,900,000

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%

8.50%

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%

Long term debt as percentage of aggregate capital used for computation of entity's rate of return

48.28%

Common equity as percentage of aggregate capital used for computation of entity's rate of return

51.72%

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

17.00%

20.00%

25.00%

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

1.50%

Number of wind turbines

Extended period of new rate by request

'18 months

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

1.50%

Percentage of conservation cost recovery adjustment

3.80%

3.00%

Financial incentives approved

2,600,000

3,500,000

Financial incentive filing request

2,600,000

2,700,000

Financial incentives recognized during period

3,900,000

400,000

100,000

2,600,000

Conservation improvement programs surcharge

3.80%

Decrease in percentage of customers bill

1.90%

Decrease in conservation improvement programs surcharge

0.00142

Allowance for funds used during construction rate

7.65%

Filing of reply and supplemental comments to find eligible projects, description

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.

Regulatory asset

101,670,000

160,254,000

8,900,000

500,000

2,300,000

Conservation costs recoverable and incentives earned

9,300,000

7,800,000

8,000,000

Expected cost recovery from customers

9,900,000

15,600,000

Regulatory liabilities

75,121,000

69,394,000

700,000

200,000

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

100.00%

Percentage of prudently incurred costs of cancelled or abandoned transmission facilities, authorized for recovery by formula transmission rate

100.00%

Current return on equity used in transmission rates

12.38%

Proposed reduced return on equity used in transmission rates

9.15%

Number of projects authorized for recovery of costs if abandoned

Expanded capacity of projects

345

230

345

Extended distance of transmission line

160

170

Big Stone II generation costs

3,200,000

10,100,000

Big Stone II - Project transmission related costs

3,200,000

2,600,000

Regulators jurisdictional share

4,100,000

Regulators jurisdictional share of Big Stone II transmission costs transferred

400,000

300,000

Recoverable amount of deferred costs

3,500,000

Discounted present value of recoverable deferred costs

2,800,000

Charge related to discount in accordance with ASC 980 - Regulated Operations

700,000

Carrying charge of Big Stone II generation cost including in total recovery amount

300,000

Anticipated recovery period for discount and remaining balance of unrecovered project costs

'89 months

Recoverable amount of generation costs

3,200,000

4,300,000

Present value of recoverable amount of generation costs

2,800,000

3,900,000

Regulators jurisdictional share of transmission costs

1,100,000

Recovery of Big Stone II generation development costs approved

1,000,000

Accrued AFUDC

1,000,000

Remaining jurisdictional portion of unrecovered transmission costs plus accumulated AFUDC transferred

200,000

Number of additional transmission related projects

Number of additional projects approved

Number of investor

Number of major transmission projects

Number of other electric providers entered in agreement for development of project

Renewable resource adjustment rate

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, 2013		Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	$17,940		$25,499
Regulatory Liabilities - Current	1,195		559
Net Regulatory Assets - Current	16,745		24,940
Regulatory Assets - Long-Term	83,730		134,755
Regulatory Liabilities - Long-Term	73,926		68,835
Net Regulatory Assets - Long-Term	9,804		65,920
Regulatory Assets - Total	101,670		160,254
Regulatory Liabilities - Total	75,121		69,394
Net Regulatory Asset Position	26,549		90,860
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	4,095	[1]	8,411	[1]
Regulatory Assets - Long-Term	55,012	[1]	109,538	[1]
Regulatory Assets - Total	59,107	[1]	117,949	[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	3,008	[1]	7,949	[1]
Regulatory Assets - Long-Term	8,674	[1]	10,050	[1]
Regulatory Assets - Total	11,682	[1]	17,999	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'60 months	[1]	'72 months	[1]
Conservation Improvement Program Costs and Incentives	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	4,945	[2]	3,707	[2]
Regulatory Assets - Long-Term	3,959	[2]	2,560	[2]
Regulatory Assets - Total	8,904	[2]	6,267	[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	4,646	[1]	4,137	[1]
Regulatory Assets - Total	4,646	[1]	4,137	[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	558	[1]	526	[1]
Regulatory Assets - Long-Term	3,967	[1]	1,618	[1]
Regulatory Assets - Total	4,525	[1]	2,144	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'81 months	[1]	'45 months	[1]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	1,351	[1]	'	[1]
Regulatory Assets - Long-Term	1,753	[1]	1,352	[1]
Regulatory Assets - Total	3,104	[1]	1,352	[1]
Regulatory Assets - Long term - Remaining Recovery/Refund Period	'		'see note	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'24 months	[1]	'
Debt Reacquisition Premiums	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	351	[1]	268	[1]
Regulatory Assets - Long-Term	2,241	[1]	1,978	[1]
Regulatory Assets - Total	2,592	[1]	2,246	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'225 months	[1]	'237 months	[1]
North Dakota Environmental Cost Recovery Rider Accrued Revenues	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	2,331	[2]	'
Regulatory Assets - Long-Term	'	[2]	'
Regulatory Assets - Total	2,331	[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	'		'
Regulatory Assets - Long-Term	1,805	[1]	1,691	[1]
Regulatory Liabilities - Long-Term	1,960		2,553
Regulatory Assets - Total	1,805	[1]	1,691	[1]
Regulatory Liabilities - Total	1,960		2,553
Regulatory Assets - Long term - Remaining Recovery/Refund Period	'asset lives	[1]	'asset lives	[1]
Regulatory Liabilities - Remaining Recovery/Refund Period	'asset lives		'asset lives
Big Stone II Unrecovered Project Costs - South Dakota	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	101	[2]	100	[2]
Regulatory Assets - Long-Term	843	[2]	711	[2]
Regulatory Assets - Total	944	[2]	811	[2]
Regulatory Assets - Remaining Recovery/Refund Period	'113 months	[2]	'97 months	[2]
North Dakota Renewable Resource Rider Accrued Revenues	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	'	[2]	532	[2]
Regulatory Assets - Long-Term	762	[2]	1,087	[2]
Regulatory Assets - Total	762	[2]	1,619	[2]
Regulatory Assets - Remaining Recovery/Refund Period	'15 months	[2]	'15 months	[2]
Recoverable Fuel and Purchased Power Costs	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	760	[1]	1,737	[1]
Regulatory Assets - Long-Term	'	[1]	'	[1]
Regulatory Assets - Total	760	[1]	1,737	[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]	908	[1]
Regulatory Assets - Long-Term	'	[1]	'	[1]
Regulatory Assets - Total	375	[1]	908	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'3 months	[1]	'7 months	[1]
Minnesota Renewable Resource Rider Accrued Revenues	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	'	[2]	915	[2]
Regulatory Assets - Long-Term	68	[2]	'	[2]
Regulatory Assets - Total	68	[2]	915	[2]
Regulatory Assets - Long term - Remaining Recovery/Refund Period	'see note	[2]	'
Regulatory Assets - Remaining Recovery/Refund Period	'		'5 months	[2]
South Dakota Transmission Rider Accrued Revenues	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	32	[2]	2	[2]
Regulatory Assets - Long-Term	'	[2]	'	[2]
Regulatory Assets - Total	32	[2]	2	[2]
Regulatory Assets - Remaining Recovery/Refund Period	'12 months	[2]	'12 months	[2]
Deferred Holding Company Formation Costs	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	27	[1]	55	[1]
Regulatory Assets - Long-Term	'	[1]	27	[1]
Regulatory Assets - Total	27	[1]	82	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'6 months	[2]	'18 months	[2]
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]	'
Accumulated Reserve for Estimated Removal Costs - Net of Salvage	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Liabilities - Current	'		'
Regulatory Liabilities - Long-Term	71,454		65,960
Regulatory Liabilities - Total	71,454		65,960
Regulatory Liabilities - 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		489
Regulatory Liabilities - Long-Term	'		'
Regulatory Liabilities - Total	670		489
Regulatory Liabilities - Remaining Recovery/Refund Period	'12 months		'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	289		'
Regulatory Liabilities - Total	289		'
Regulatory Liabilities - Remaining Recovery/Refund Period	'see note		'
North Dakota Renewable Resource Rider Accrued Refund	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Liabilities - Current	261		'
Regulatory Liabilities - Long-Term	'		'
Regulatory Liabilities - Total	261		'
Regulatory Liabilities - Remaining Recovery/Refund Period	'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		8
Regulatory Liabilities - Long-Term	117		210
Regulatory Liabilities - Total	123		218
Regulatory Liabilities - Remaining Recovery/Refund Period	'56 months		'68 months
Deferred Gain on Sale of Utility Property - Minnesota Portion	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Liabilities - Current	5		6
Regulatory Liabilities - Long-Term	106		112
Regulatory Liabilities - Total	111		118
Regulatory Liabilities - Remaining Recovery/Refund Period	'240 months		'252 months
South Dakota - Nonasset-Based Margin Sharing Excess	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Liabilities - Current	38		56
Regulatory Liabilities - Long-Term	'		'
Regulatory Liabilities - Total	38		56
Regulatory Liabilities - Remaining Recovery/Refund Period	'12 months		'12 months
General Rate Case Recoverable Expenses	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	'		279	[1]
Regulatory Assets - Long-Term	'		6	[1]
Regulatory Assets - Total	'		285	[1]
Regulatory Assets - Remaining Recovery/Refund Period	'		'13 months	[1]
North Dakota Transmission Rider Accrued Revenues	'		'
Schedule of Regulatory Assets and Liabilities [Line Items]	'		'
Regulatory Assets - Current	'		110	[2]
Regulatory Assets - Long-Term	'		'	[2]
Regulatory Assets - Total	'		$110	[2]
Regulatory Assets - Remaining Recovery/Refund Period	'		'12 months	[2]

[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
Regulatory Assets and Liabilities (Detail Textuals)	Dec. 31, 2013
Debt Reacquisition Premiums	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Regulatory assets long term, remaining recovery/refund period	'225 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, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'	'
Wholesale Sales - Company-Owned Generation	$14,846	$12,951	$14,518
Revenue from Settled Contracts at Market Prices	133,238	160,987	168,313
Market Cost of Settled Contracts	-132,055	-159,500	-166,920
Net Margins on Settled Contracts at Market	1,183	1,487	1,393
Marked-to-Market Gains on Settled Contracts	3,039	7,864	10,208
Marked-to-Market Losses on Settled Contracts	-2,722	-7,974	-10,176
Net Marked-to-Market Gains (Losses) on Settled Contracts	317	-110	32
Unrealized Marked-to-Market Gains on Open Contracts	215	284	3,707
Unrealized Marked-to-Market Losses on Open Contracts	-100	-235	-2,813
Net Unrealized Marked-to-Market Gains on Open Contracts	115	49	894
Wholesale Electric Revenue	$16,461	$14,377	$16,837

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, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]	'	'	'
Regulatory Asset - Current Deferred Marked-to-Market Loss	$17,940	$25,499	'
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	83,730	134,755	'
Current Liability - Marked-to-Market Loss	-11,782	-18,234	'
Regulatory Liability - Current Deferred Marked-to-Market Gain	-1,195	-559	'
Regulatory Liability - Long-Term Deferred Marked-to-Market Gain	-73,926	-68,835	'
Forward Electricity Contracts	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Other Current Asset - Marked-to-Market Gain	338	502	'
Total Assets	12,020	18,501	'
Current Liability - Marked-to-Market Loss	-11,782	-18,234	'
Total Liabilities	-11,905	-18,452	'
Net Fair Value of Marked-to-Market Energy Contracts	115	49	894
Forward Electricity Contracts \| Deferred Marked-to-Market Losses	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Regulatory Asset - Current Deferred Marked-to-Market Loss	3,008	7,949	'
Regulatory Asset - Long-Term Deferred Marked-to-Market Loss	8,674	10,050	'
Forward Electricity Contracts \| Deferred Marked-to-Market Gain	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Regulatory Liability - Current Deferred Marked-to-Market Gain	-6	-8	'
Regulatory Liability - Long-Term Deferred Marked-to-Market Gain	($117)	($210)	'

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, 2013	Dec. 31, 2012
Forward Electricity Contracts	'	'
Derivatives Fair Value [Roll Forward]	'	'
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Period	$49	$894
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods	-49	-861
Changes in Fair Value of Contracts Entered into in Prior Periods	'	-33
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	49
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$115	$49

Forward_Contracts_Classified_a5

Forward Contracts Classified as Derivatives - Information on OTP's Credit Risk Exposure on Delivered and Marked-to-Market Forward Contracts (Details 3) (Otter Tail Power Company, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	Counterparty	Counterparty
Net Credit Risk on Forward Energy Contracts	'	'
Derivative [Line Items]	'	'
Exposure	$856	$580
Counterparties	3	6
Net Credit Risk To Single Largest Counterparty	'	'
Derivative [Line Items]	'	'
Exposure	$530	$285

Forward_Contracts_Classified_a6

Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 4) (Legally enforceable netting arrangements, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Legally enforceable netting arrangements	'	'
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]	'	'
Derivative Assets Subject to Legally Enforceable Netting Arrangements	$400	$638
Derivative Liabilities Subject to Legally Enforceable Netting Arrangements	-11,782	-18,234
Net Balance Subject to Legally Enforceable Netting Arrangements	($11,382)	($17,596)

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 (Details 5) (Otter Tail Power Company, USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Otter Tail Power Company	'		'
Current Liability - Marked-to-Market Loss (in thousands)	'		'
Loss Contracts Covered by Deposited Funds or Letters of Credit	'		$2,176
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	11,679	[1]	16,058	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements	103		'
Total Current Liability - Marked-to-Market Loss	$11,782		$18,234

[1]	Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $11,679 $16,058 Offsetting Gains with Counterparties under Master Netting Agreements (117 ) (416 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $11,562 $15,642

Forward_Contracts_Classified_a8

Forward Contracts Classified as Derivatives - Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in Marked-to-Market Loss Positions (Parentheticals) (Details) (Otter Tail Power Company, USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Otter Tail Power Company	'		'
Credit Derivatives [Line Items]	'		'
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$11,679	[1]	$16,058	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	-117		-416
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$11,562		$15,642

[1]	Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $11,679 $16,058 Offsetting Gains with Counterparties under Master Netting Agreements (117 ) (416 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $11,562 $15,642

Forward_Contracts_Classified_a9

Forward Contracts Classified as Derivatives (Detail Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]	'	'	'
Net unrealized gains on forward contracts	$115,000	$49,000	$894,000
Otter Tail Power Company	'	'	'
Derivative [Line Items]	'	'	'
Net unrealized gains on forward contracts	$115,000	'	'
Otter Tail Power Company \| Investment grade credit ratings	'	'	'
Derivative [Line Items]	'	'	'
Counterparties	3	'	'

Common_Shares_and_Earnings_Per2

Common Shares and Earnings Per Share - Reconciliation of Common Shares Outstanding (Details)	12 Months Ended
	Dec. 31, 2013
Stockholders Equity and Earnings Per Share [Abstract]	'
Balance (in shares)	36,168,368
Issuances:	'
Stock Options Exercised	56,109
Vesting of Restricted Stock Units	17,535
Restricted Stock Issued to Employees	17,000
Restricted Stock Issued to Directors	17,333
Director's Compensation	4,535
Retirements:	'
Shares Withheld for Individual Income Tax Requirements	-7,184
Forfeiture of Unvested Restricted Stock	-2,000
Balance (in shares)	36,271,696

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Options Outstanding	'	92,497	156,397
Range of Exercise Prices, Lower Range	'	$24.93	$24.93
Range of Exercise Prices, Upper Range	'	$27.25	$31.34

Common_Shares_and_Earnings_Per4

Common Shares and Earnings Per Share (Detail Textuals) (USD $)	12 Months Ended				12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	11-May-12	Dec. 31, 2013	14-May-12
				1999 Stock Incentive Plan	1999 Employee Stock Purchase Plan	1999 Employee Stock Purchase Plan	1999 Employee Stock Purchase Plan	1999 Employee Stock Purchase Plan	Dividend Reinvestment and Share Purchase Plan	Distribution Agreement	Distribution Agreement
								Previously Reported		J.P. Morgan Securities Inc. (JPMS)	J.P. Morgan Securities Inc. (JPMS)
Stockholders Equity Note [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Agreement with distribution agent for offer and sale of shares, aggregate sales price	'	'	'	'	'	'	'	'	'	'	$75,000,000
Percentage of commission on gross sales price	'	'	'	'	'	'	'	'	'	2.00%	'
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	'	'	'	3,600,000	1,400,000	'	'	900,000	'	'	'
Common shares available for grant	'	'	'	'	482,782	'	'	'	'	'	'
Purchase of shares in open market	'	'	'	'	43,837	60,439	78,537	'	'	'	'
Shelf registration for issuance of common shares	'	'	'	'	'	'	'	'	1,500,000	'	'
Adjustments to denominator diluted earnings per share	203,583	194,240	160,228	'	'	'	'	'	'	'	'
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	'	'	'	'	'	'	'	'

ShareBased_Payments_Informatio

Share-Based Payments - Information about Stock Options Outstanding (Details) (Stock options, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2013
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Exercise price $24.93	Exercise price $26.495
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Exercise Price	$25.69	$26.59	$28.53	$27.28	$24.93	$26.50
Outstanding and Exercisable	'	'	'	'	17,900	16,800
Remaining Contractual Life	'	'	'	'	'Expire on April 10, 2015	'Expire on April 11, 2014

ShareBased_Payments_Summary_of

Share-Based Payments - Summary of Stock Options Activity (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding [Roll Forward]	'	'	'
Exercised	56,109	'	'
Stock options	'	'	'
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding [Roll Forward]	'	'	'
Outstanding, Beginning of Year	92,497	156,397	383,460
Granted	'	'	'
Exercised	56,109	'	'
Forfeited or Expired	1,688	63,900	227,063
Outstanding, End of Year	34,700	92,497	156,397
Exercisable, End of Year	34,700	92,497	156,397
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'	'	'
Outstanding, Beginning of Year	$26.59	$28.53	$27.28
Granted	'	'	'
Exercised	$27.12	'	'
Forfeited or Expired	$27.25	$31.34	$26.43
Outstanding, End of Year	$25.69	$26.59	$28.53
Exercisable, End of Year	$25.69	$26.59	$28.53
Cash Received for Options Exercised	$1,522,000	'	'
Intrinsic Value of Options Exercised	$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. 08, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	'	56,900	54,250	59,725
Granted	16,000	17,333	24,000	24,000
Vested	'	29,750	21,350	29,475
Forfeited	'	2,000	'	'
Nonvested, End of Year	'	42,483	56,900	54,250
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	'	$21.84	$23.26	$24.95
Granted	$31.03	$30.77	$21.32	$22.51
Vested	'	$21.87	$24.86	$26.07
Forfeited	'	$31.03	'	'
Nonvested, End of Year	'	$25.03	$21.84	$23.26
Compensation Expense Recognized	'	$611,000	$552,000	$740,000
Fair Value of Shares Vested in Year	'	$651,000	$531,000	$768,000

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, 2013	Dec. 31, 2012	Dec. 31, 2011
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	47,645	34,868	66,161
Granted	17,000	26,120	24,600
Vested	16,330	11,518	55,893
Forfeited	'	1,825	'
Nonvested, End of Year	48,315	47,645	34,868
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	$21.82	$22.86	$24.79
Granted	$31.03	$21.48	$22.51
Vested	$21.89	$24.14	$25
Forfeited	'	$22.20	'
Nonvested, End of Year	$25.04	$21.82	$22.86
Stock Compensation Expense	$427,000	$325,000	$832,000
Fair Value Of Awards Vested	$358,000	$278,000	$1,397,000

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. 08, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	'	60,665	73,815	79,315
Granted	15,150	15,150	15,800	19,800
Vested	'	17,535	20,750	20,025
Forfeited	'	2,100	8,200	5,275
Nonvested, End of Year	'	56,180	60,665	73,815
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	'	$18.11	$20.95	$23.55
Granted	$25.30	$25.30	$17.66	$18.03
Vested	'	$18.73	$27.13	$27.94
Forfeited	'	$19.88	$19.97	$22.56
Nonvested, End of Year	'	$19.79	$18.11	$20.95
Compensation Expense Recognized	'	$275,000	$256,000	$349,000
Fair Value of Units Converted in Year	'	$328,000	$563,000	$559,000

ShareBased_Payments_Summary_of4

Share-Based Payments - Summary of Stock Performance Awards Granted and Amounts Expensed (Details 5) (Executive Officers, USD $)	12 Months Ended			60 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Stock compensation expense	$2,678,000	$1,255,000	$1,871,000	'
Shares Awarded	'	'	'	162,730
Performance Period 2013 To 2015	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Maximum Shares Subject To Award	100,400	'	'	100,400
Shares Used To Estimate Expense	50,200	'	'	50,200
Grant Date Fair Value	$37.51	'	'	37.51
Stock compensation expense	580,000	'	'	'
Shares Awarded	'	'	'	'
Performance Period 2013 To 2015 \| Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2013	'	'	'
Performance Period 2013 To 2015 \| Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2015	'	'	'
Performance Period 2012 To 2014	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Maximum Shares Subject To Award	161,600	'	'	161,600
Shares Used To Estimate Expense	80,800	'	'	80,800
Grant Date Fair Value	$21.75	'	'	21.75
Stock compensation expense	1,686,000	1,001,000	'	'
Shares Awarded	'	'	'	'
Performance Period 2012 To 2014 \| Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2012	'	'	'
Performance Period 2012 To 2014 \| Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2014	'	'	'
Performance Period 2011 To 2013	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Maximum Shares Subject To Award	97,200	'	'	97,200
Shares Used To Estimate Expense	48,600	'	'	48,600
Grant Date Fair Value	$23.61	'	'	23.61
Stock compensation expense	412,000	254,000	553,000	'
Shares Awarded	48,730	'	'	'
Performance Period 2011 To 2013 \| Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2011	'	'	'
Performance Period 2011 To 2013 \| Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2013	'	'	'
Performance Period 2010 To 2012	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Maximum Shares Subject To Award	146,800	'	'	146,800
Shares Used To Estimate Expense	73,400	'	'	73,400
Grant Date Fair Value	$20.97	'	'	20.97
Stock compensation expense	'	'	572,000	'
Shares Awarded	49,500	'	'	'
Performance Period 2010 To 2012 \| Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2010	'	'	'
Performance Period 2010 To 2012 \| Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2012	'	'	'
Performance Period 2009 To 2011	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Maximum Shares Subject To Award	181,200	'	'	181,200
Shares Used To Estimate Expense	90,600	'	'	90,600
Grant Date Fair Value	$27.98	'	'	27.98
Stock compensation expense	'	'	$746,000	'
Shares Awarded	64,500	'	'	'
Performance Period 2009 To 2011 \| Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2009	'	'	'
Performance Period 2009 To 2011 \| Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Performance period	'2011	'	'	'

ShareBased_Payments_Detail_Tex

Share-Based Payments (Detail Textuals) (USD $)	12 Months Ended
Share-Based Payments (Detail Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	'	'
Compensation Expense Recognized	$143,000	$179,000	$257,000
1999 Stock Incentive Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Granted	2,041,500	'	'

ShareBased_Payments_Detail_Tex1

Share-Based Payments (Detail Textuals 1) (USD $)

60 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Apr. 08, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 08, 2013

Sep. 23, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 08, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Executive Officers

Restricted Stock

Restricted Stock Units (Rsu)

Director

Steven L Fritze

Employee

Executive Officers

Employee

Minimum

Maximum

Minimum

Maximum

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Granted

162,730

16,000

17,333

24,000

1,333

17,000

26,120

24,600

17,000

15,150

15,800

19,800

Vesting date

8-Apr-14

8-Apr-17

8-Apr-14

8-Apr-17

Vesting percentage

25.00%

Grant date fair value of each share of stock awards

$31.03

$30.77

$21.32

$22.51

$27.67

$31.03

$21.48

$22.51

$31.03

$25.30

$17.66

$18.03

Vesting period for restricted stock units (in years)

'4 years

ShareBased_Payments_Detail_Tex2

Share-Based Payments (Detail Textuals 2) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2013	Dec. 14, 2011	Dec. 15, 2011
		Chief Executive Officer	Chief Executive Officer
		Performance Period 2009 To 2011	Performance Period 2009 To 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Shares Awarded	'	'	88,300
Market value per share of common stock on date of issuance	'	$21.19	'
Stock award, issuance date fair value	'	$1,871,165	'
Unrecognized amount of compensation expense related to stock-based compensation	$4,600,000	'	'
Weighted-average period of amortization	'2 years	'	'

Retained_Earnings_and_Dividend1

Retained Earnings and Dividend Restriction (Detail Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified			OTP	OTP	OTP
				Minimum	Maximum
Retained Earnings Restriction [Line Items]	'	'	'	'	'
Required equity to total capitalization ratio to limit dividend payment	'	'	'	44.80%	54.80%
Equity to total capitalization ratio	'	'	50.20%	'	'
Total Capitalization	$924,419	$959,154	'	'	$874,000

Commitments_and_Contingencies_1

Commitments and Contingencies - Amounts of Commitments under Capacity and Energy Agreements, Coal and Coal Delivery Contracts and Operating Leases (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Operating Leases	'
2014	$8,214
2015	6,182
2016	5,065
2017	3,397
2018	2,543
Beyond 2018	12,137
Total	37,538
OTP	'
Operating Leases	'
2014	2,519
2015	1,649
2016	1,309
2017	978
2018	989
Beyond 2018	11,812
Total	19,256
OTP \| Capacity and Energy Requirements	'
Purchase Commitments	'
2014	22,565
2015	30,468
2016	22,812
2017	22,123
2018	25,808
Beyond 2018	223,561
Total	347,337
OTP \| Coal and Freight Purchase Commitments	'
Purchase Commitments	'
2014	50,149
2015	20,790
2016	21,041
2017	23,599
2018	23,135
Beyond 2018	621,814
Total	760,528
Nonelectric	'
Operating Leases	'
2014	5,695
2015	4,533
2016	3,756
2017	2,419
2018	1,554
Beyond 2018	325
Total	$18,282

Commitments_and_Contingencies_2

Commitments and Contingencies (Detail Textuals) (USD $)	12 Months Ended
Commitments and Contingencies (Detail Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Rent expense from continuing operations	$11,114,000	$11,858,000	$10,061,000
Loss Contingency, range of possible loss, maximum	2,000,000	'	'
OTP \| Construction Programs	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Commitment under contracts aggregate amount	$108,227,000	'	'
OTP \| Capacity and Energy Requirements	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Contracts expiration year	'2038	'	'
OTP \| Coal and Freight Purchase Commitments	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Contracts expiration year	'2014, 2015, 2016 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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]	'	'
Line Limit	$320,000	'
In Use	51,195	'
Restricted due to Outstanding Letters of Credit	2,489	'
Available	266,316	316,078
Otter Tail Corporation Credit Agreement	'	'
Line of Credit Facility [Line Items]	'	'
Line Limit	150,000	'
In Use	'	'
Restricted due to Outstanding Letters of Credit	659	'
Available	149,341	149,267
OTP Credit Agreement	'	'
Line of Credit Facility [Line Items]	'	'
Line Limit	170,000	'
In Use	51,195	'
Restricted due to Outstanding Letters of Credit	1,830	'
Available	$116,975	$166,811

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, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Aggregate amounts of debt maturities in 2014	$188
Aggregate amounts of debt maturities in 2015	41,101
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

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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Short-Term Debt	$51,195	'
Long-Term Debt	389,778	421,860
Less: Current Maturities - Otter Tail Corporation	188	176
Unamortized Debt Discount	1	4
Total Long-Term Debt	389,589	421,680
Total Short-Term and Long-Term Debt (with current maturities)	440,972	421,856
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'
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	100,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	50,000	50,000
Other Obligations - Various up to 3.95%	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	1,548	1,725
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	'	5,065
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	'	20,070
OTP	'	'
Debt Instrument [Line Items]	'	'
Short-Term Debt	51,195	'
Long-Term Debt	335,900	320,135
Less: Current Maturities - Otter Tail Corporation	'	'
Unamortized Debt Discount	'	'
Total Long-Term Debt	335,900	320,135
Total Short-Term and Long-Term Debt (with current maturities)	387,095	320,135
OTP \| Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'
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 6.47%, Series D, due August 20, 2037	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	50,000	50,000
OTP \| Other Obligations - Various up to 3.95%	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	'	'
OTP \| Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	'	5,065
OTP \| Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	'	20,070
OTTER TAIL CORPORATION	'	'
Debt Instrument [Line Items]	'	'
Short-Term Debt	'	'
Long-Term Debt	53,878	101,725
Less: Current Maturities - Otter Tail Corporation	188	176
Unamortized Debt Discount	1	4
Total Long-Term Debt	53,689	101,545
Total Short-Term and Long-Term Debt (with current maturities)	53,877	101,721
OTTER TAIL CORPORATION \| 9.000% Notes, due December 15, 2016	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	52,330	100,000
OTTER TAIL CORPORATION \| Other Obligations - Various up to 3.95%	'	'
Debt Instrument [Line Items]	'	'
Long-Term Debt	$1,548	$1,725

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 (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Nov. 25, 2013	Nov. 06, 2013
Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'	'	'
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	'	'
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	'	4.65%	'	'
Long-Term Debt, Due Date	'	1-Sep-17	'	'
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	'	'
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	'	4.85%	'	'
Long-Term Debt, Due Date	'	1-Sep-22	'	'
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	6.37%	6.37%	'	'
Long-Term Debt, Due Date	20-Aug-27	20-Aug-27	'	'
Senior Unsecured Notes 6.47%, 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 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	'	'
Other Obligations - Various up to 3.95%	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	3.95%	3.95%	'	'
OTP \| Unsecured Term Loan - LIBOR plus 0.875%, due January 15, 2015	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	0.88%	0.88%	'	'
Long-Term Debt, Due Date	15-Jan-15	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 \| Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	'	4.65%	'	'
Long-Term Debt, Due Date	'	1-Sep-17	'	'
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 \| Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	'	4.85%	'	'
Long-Term Debt, Due Date	'	1-Sep-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 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	'	'
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	'	'
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 \| Other Obligations - Various up to 3.95%	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Long-Term Debt, Interest Rate	3.95%	3.95%	'	'

ShortTerm_and_LongTerm_Borrowi6

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Oct. 29, 2012
Line of Credit Facility [Line Items]	'	'	'
Weighted average interest rate paid on short-term debt	1.40%	'	'
Line Limit	$320,000,000	'	'
Otter Tail Corporation Credit Agreement	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Maximum amount of debt outstanding	4,754,000	'	'
Average daily balance of debt outstanding	49,000	'	'
Weighted average interest rate paid on short-term debt	1.90%	3.80%	'
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%	'	'
Line of credit facility, description of variable rate basis prior to renewal	'LIBOR	'	'
Line of credit facility, basis spread on variable rate, prior to renewal	3.25%	'	'
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
Otter Tail Corporation Credit Agreement \| Maximum	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Debt to total capitalization ratio	1	'	'
Interest and dividend coverage ratio	1.5	'	'
Otter Tail Corporation Credit Agreement \| Minimum	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Debt to total capitalization ratio	0.6	'	'
Interest and dividend coverage ratio	1	'	'
OTP Credit Agreement	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Maximum amount of debt outstanding	53,003,000	'	'
Average daily balance of debt outstanding	17,446,000	'	'
Weighted average interest rate paid on short-term debt	1.40%	1.70%	'
Line Limit	170,000,000	'	'
Line of credit facility, maximum amount 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%	'	'
Line of credit facility, description of variable rate basis prior to renewal	'LIBOR	'	'
Line of credit facility, basis spread on variable rate, prior to renewal	1.50%	'	'
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
OTP Credit Agreement \| Maximum	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Debt to total capitalization ratio	1	'	'
OTP Credit Agreement \| Minimum	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Debt to total capitalization ratio	0.6	'	'

ShortTerm_and_LongTerm_Borrowi7

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 1) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Jul. 13, 2012

Dec. 31, 2013

Mar. 18, 2011

Dec. 31, 2013

Dec. 31, 2012

Apr. 06, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 06, 2013

Dec. 31, 2013

Dec. 31, 2012

Nov. 25, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Jul. 13, 2012

Dec. 31, 2013

Otter Tail Power Company

Cascade Investment, L.L.C. (Cascade)

Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021

North Dakota Development Note, 3.95%, due April 1, 2018

Senior Unsecured Notes 4.63%, due December 1, 2021

Senior Unsecured Notes 5.95%, Series A, due August 20, 2017

Senior Unsecured Notes 6.15%, Series B, due August 20, 2022

Senior Unsecured Notes 6.37%, Series C, due August 20, 2027

Senior Unsecured Notes 6.47%, Series D, due August 20, 2037

Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017

Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022

2016 Notes

2007 and 2011 Note Purchase Agreement

2007 Note Purchase Agreement

Cascade Note Purchase Agreement

Otter Tail Corporation Credit Agreement

OTP Credit Agreement

Otter Tail Power Company

Transaction

Maximum

Minimum

Senior Unsecured Notes 4.63%, due December 1, 2021

Senior Unsecured Notes 6.63%, due December 1, 2011

Pollution control refunding revenue bonds

Unsecured Senior Notes

Senior Unsecured Notes 5.95%, Series A, due August 20, 2017

Senior Unsecured Notes 6.15%, Series B, due August 20, 2022

Senior Unsecured Notes 6.37%, Series C, due August 20, 2027

Senior Unsecured Notes 6.47%, Series D, due August 20, 2037

8.89% Senior Unsecured Note due November 30, 2017

Maximum

Minimum

Maximum

Minimum

Otter Tail Power Company

Debt Instrument [Line Items]

Original debt issued, principal amount

$1,500,000

$500,000

$100,000,000

$140,000,000

$155,000,000

$33,000,000

$30,000,000

$42,000,000

$50,000,000

Remaining principal amount of notes outstanding unless redeemed early or otherwise repaid

389,778,000

421,860,000

335,900,000

320,135,000

1,223,000

1,332,000

325,000

393,000

140,000,000

33,000,000

30,000,000

42,000,000

50,000,000

5,065,000

20,070,000

52,330,000

100,000,000

Percentage of required payment for partial prepayment

10.00%

Payments for Retirement of Long-Term Debt

72,981,000

50,224,000

100,796,000

90,000,000

10,400,000

Long-Term Debt, maturity period

'10 years

'7 years

Percentage of required payment for whole prepayment

100.00%

Interest rate of original debt repurchased

2.54%

3.95%

4.63%

5.95%

6.15%

6.37%

6.47%

4.65%

4.85%

9.00%

4.63%

6.63%

5.95%

6.15%

6.37%

6.47%

Long-Term Debt, Issuance Date

18-Mar-11

Long-Term Debt, Due Date

18-Mar-21

1-Apr-18

1-Dec-21

20-Aug-17

20-Aug-22

20-Aug-27

20-Aug-37

1-Sep-17

1-Sep-22

15-Dec-16

Percentage of required payment in the event of change in control

100.00%

Percentage of the company's outstanding common stock owned by Cascade

9.50%

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.

Debt to total capitalization ratio

1.5

0.6

Interest and dividend coverage ratio

0.6

1.5

Priority debt to total capitalization

20.00%

Prepayment of cascade note pursuant to the Note Purchase Agreement

50,000,000

Effective interest rate during the period

8.89%

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

Income (loss) from continuing operations per diluted share

$1.37

$1.05

$0.95

$0.22

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

Divesture Period

'2 years

ShortTerm_and_LongTerm_Borrowi8

Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 2) (USD $)	Dec. 31, 2013	Nov. 25, 2013	Nov. 06, 2013	Dec. 31, 2012	Sep. 30, 2013	Mar. 01, 2013	Mar. 01, 2013	Mar. 01, 2013	Mar. 01, 2013
	9.000% Notes, due December 15, 2016	9.000% Notes, due December 15, 2016	9.000% Notes, due December 15, 2016	9.000% Notes, due December 15, 2016	Cumulative Preferred Shares	Cumulative Preferred Shares	Otter Tail Power Company	Otter Tail Power Company	Otter Tail Power Company
							J P Morgan Chase Bank	J P Morgan Chase Bank	J P Morgan Chase Bank
							Unsecured Term Loan	Unsecured Term Loan	Unsecured Term Loan
								4.65 % Grant County, South Dakota and 4.85 % Mercer County, North Dakota Pollution Control Refunding Revenue Bonds	Intercompany Note
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Term loan borrowed for funding	'	'	'	'	'	'	$40,900,000	$25,100,000	$15,700,000
Description of variable rate basis	'	'	'	'	'	'	'LIBOR	'	'
Basis spread on variable rate	'	'	'	'	'	'	0.88%	'	'
Redemption amount of preferred stock equal to proceeds from term loan	'	'	'	'	'	15,700,000	'	'	'
Preferred stock redemption, call premiums	'	'	'	'	200,000	'	'	'	'
Amount of debt outstading	'	'	100,000,000	'	'	'	'	'	'
Interest rate of the original debt instrument that was repurchased	9.00%	9.00%	9.00%	9.00%	'	'	'	'	'
Amount of the original debt repurchased	'	$34,737,000	$12,933,000	'	'	'	'	'	'

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, 2013	Aug. 14, 2013	Aug. 14, 2013
	Dec. 31, 2013	Series A Senior Unsecured Notes due on February 27, 2029	Series B Senior Unsecured Notes due on February 27, 2044
Debt Instrument [Line Items]	'	'	'
Aggregate principal amount of note	'	$60	$90
Debt instrument, interest rate	'	4.68%	5.47%
Debt instrument description of prepayment	'	'	'
Debt instrument description of prepayment	The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the New OTP Notes (in an amount not less than 10% of the aggregate principal amount of the New OTP 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 2029 Notes then outstanding on or after November 27, 2028 or (ii) all of the 2044 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%	'	'

Class_B_Stock_Options_of_Subsi1

Class B Stock Options of Subsidiary (Detail Textuals) (IPH, Common Class B, USD $)	0 Months Ended	3 Months Ended
	6-May-11	Jun. 30, 2011
IPH \| Common Class B	'	'
Class of Stock [Line Items]	'	'
Number of common shares options cancelled (in shares)	363	'
Common stock fair value, per share	$2,973.90	'
Common stock, book value per share	$2,085.88	'
Adjustment to retained earnings	'	$322,000

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, 2013		Dec. 31, 2012		Dec. 31, 2011
Pension Plan	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Service Cost--Benefit Earned During the Period	$5,594		$5,084		$4,415
Interest Cost on Projected Benefit Obligation	12,123		12,465		12,666
Expected Return on Assets	-14,521		-14,430		-14,140
Amortization of Prior-Service Cost:	'		'		'
From Regulatory Asset	333		398		423
From Other Comprehensive Income	9	[1]	11	[1]	11	[1]
Amortization of Net Actuarial Loss (Net of Medicare Part D Subsidy):	'		'		'
From Regulatory Asset	6,600		4,910		2,549
From Other Comprehensive Income	176	[1]	131	[1]	68	[1]
Net Periodic Cost	10,314		8,569		5,992
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Service Cost--Benefit Earned During the Period	51		45		81
Interest Cost on Projected Benefit Obligation	1,408		1,479		1,632
Amortization of Prior-Service Cost:	'		'		'
From Regulatory Asset	22		22		42
From Other Comprehensive Income	51	[2]	51	[2]	31	[2]
Amortization of Net Actuarial Loss (Net of Medicare Part D Subsidy):	'		'		'
From Regulatory Asset	208		175		142
From Other Comprehensive Income	313	[3]	152	[3]	103	[3]
Net Periodic Cost	2,053		1,924		2,031
Other Postretirement Benefits	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Service Cost (Net of Medicare Part D Subsidy)	1,421		1,544		1,275
Interest Cost (Net of Medicare Part D Subsidy)	2,050		2,575		2,384
Amortization of Transition Obligation	'		'		'
From Regulatory Asset	'		729		729
From Other Comprehensive Income	'	[1]	19	[1]	19	[1]
Amortization of Prior-Service Cost:	'		'		'
From Regulatory Asset	205		206		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]	17	[1]	'	[1]
Net Periodic Cost	3,706		5,736		4,618
Effect of Medicare Part D Subsidy	($1,806)		($2,039)		($2,118)

[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 $ -- Other Nonelectric Expenses 31 31 31
[3]	Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 193 $ 162 $ -- Other Nonelectric Expenses 120 (10) 103

Pension_Plan_and_Other_Postret3

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan (ESSRP), USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Amortization of Prior Service Costs from Other Comprehensive Income	$51	[1]	$51	[1]	$31	[1]
Amortization of Net Actuarial Loss from Other Comprehensive Income	-313	[2]	-152	[2]	-103	[2]
Electric Operation and Maintenance Expenses	'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'
Amortization of Prior Service Costs from Other Comprehensive Income	20		20		'
Amortization of Net Actuarial Loss from Other Comprehensive Income	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	$120		($10)		$103

[1]	Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 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 $ 193 $ 162 $ -- Other Nonelectric Expenses 120 (10) 103

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount Rate	4.50%	5.15%	6.00%
Long-Term Rate of Return on Plan Assets	7.75%	8.00%	8.00%
Rate of Increase in Future Compensation Level	3.13%	3.38%	3.75%
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount Rate	4.50%	5.15%	6.00%
Rate of Increase in Future Compensation Level	3.19%	4.59%	4.65%
Other Postretirement Benefits	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount Rate	4.25%	5.05%	5.75%

Pension_Plan_and_Other_Postret5

Pension Plan and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan	'	'	'
Regulatory Assets:	'	'	'
Unrecognized Prior Service Cost	$776	$1,109	'
Unrecognized Actuarial Loss	56,051	98,808	'
Total Regulatory Assets	56,827	99,917	'
Projected Benefit Obligation	-254,039	-275,634	-246,098
Accumulated Other Comprehensive Loss:	'	'	'
Unrecognized Prior Service Cost	28	37	'
Unrecognized Actuarial Loss (Gain)	448	1,857	'
Total Accumulated Other Comprehensive Loss	476	1,894	'
Noncurrent Liability	40,422	84,616	'
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'	'	'
Regulatory Assets:	'	'	'
Unrecognized Prior Service Cost	113	135	'
Unrecognized Actuarial Loss	1,971	2,788	'
Total Regulatory Assets	2,084	2,923	'
Projected Benefit Obligation	-29,321	-31,925	-29,323
Accumulated Other Comprehensive Loss:	'	'	'
Unrecognized Prior Service Cost	261	312	'
Unrecognized Actuarial Loss (Gain)	2,465	5,095	'
Total Accumulated Other Comprehensive Loss	2,726	5,407	'
Other Postretirement Benefits	'	'	'
Regulatory Assets:	'	'	'
Unrecognized Prior Service Cost	540	745	'
Unrecognized Actuarial Loss	-344	14,364	'
Total Regulatory Assets	196	15,109	'
Projected Benefit Obligation	-45,221	-58,883	-48,263
Accumulated Other Comprehensive Loss:	'	'	'
Unrecognized Prior Service Cost	18	23	'
Unrecognized Actuarial Loss (Gain)	-261	177	'
Total Accumulated Other Comprehensive Loss	($243)	$200	'

Pension_Plan_and_Other_Postret6

Pension Plan and Other Postretirement Benefits - Funded Status (Details 3) (Pension Plan, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Accumulated Benefit Obligation	($224,365)	($238,706)	'
Projected Benefit Obligation	-254,039	-275,634	-246,098
Fair Value of Plan Assets	213,617	191,018	168,603
Funded Status	($40,422)	($84,616)	'

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan	'	'	'
Reconciliation of Fair Value of Plan Assets:	'	'	'
Fair Value of Plan Assets at January 1	$191,018,000	$168,603,000	'
Actual Return on Plan Assets	23,044,000	22,656,000	'
Employer Contributions	10,000,000	10,000,000	'
Benefit Payments	-10,445,000	-10,241,000	'
Fair Value of Plan Assets at December 31	213,617,000	191,018,000	168,603,000
Estimated Asset Return	11.80%	13.40%	'
Reconciliation of Projected Benefit Obligation:	'	'	'
Projected Benefit Obligation at January 1	275,634,000	246,098,000	'
Service Cost	5,594,000	5,084,000	4,415,000
Interest Cost	12,123,000	12,465,000	12,666,000
Benefit Payments	-10,445,000	-10,241,000	'
Actuarial (Gain) Loss	-28,867,000	22,228,000	'
Projected Benefit Obligation at December 31	254,039,000	275,634,000	246,098,000
Reconciliation of Funded Status:	'	'	'
Funded Status	-40,422,000	-84,616,000	'
Expense	-10,314,000	-8,569,000	-5,992,000
Employer Contributions	10,000,000	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	1,137,000	1,259,000	'
Benefit Payments	-1,137,000	-1,259,000	'
Fair Value of Plan Assets at December 31	'	'	'
Reconciliation of Projected Benefit Obligation:	'	'	'
Projected Benefit Obligation at January 1	31,925,000	29,323,000	'
Service Cost	51,000	45,000	81,000
Interest Cost	1,408,000	1,479,000	1,632,000
Benefit Payments	-1,137,000	-1,259,000	'
Plan Amendments	'	'	'
Actuarial (Gain) Loss	-2,926,000	2,337,000	'
Projected Benefit Obligation at December 31	29,321,000	31,925,000	29,323,000
Reconciliation of Funded Status:	'	'	'
Funded Status	-29,321,000	-31,925,000	'
Expense	-2,053,000	-1,924,000	-2,031,000
Unrecognized Net Actuarial Loss	4,436,000	7,882,000	'
Employer Contributions	1,137,000	1,259,000	'
Unrecognized Prior Service Cost	374,000	448,000	'
Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost	-24,511,000	-23,595,000	'
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	2,012,000	1,956,000	'
Benefit Payments (Net of Medicare Part D Subsidy)	-4,626,000	-4,296,000	'
Participant Premium Payments	2,614,000	2,340,000	'
Fair Value of Plan Assets at December 31	'	'	'
Reconciliation of Projected Benefit Obligation:	'	'	'
Projected Benefit Obligation at January 1	58,883,000	48,263,000	'
Service Cost (Net of Medicare Part D Subsidy)	1,421,000	1,544,000	1,275,000
Interest Cost (Net of Medicare Part D Subsidy)	2,050,000	2,575,000	2,384,000
Benefit Payments (Net of Medicare Part D Subsidy)	-4,626,000	-4,296,000	'
Participant Premium Payments	2,614,000	2,340,000	'
Actuarial (Gain) Loss	-15,121,000	8,457,000	'
Projected Benefit Obligation at December 31	45,221,000	58,883,000	48,263,000
Reconciliation of Funded Status:	'	'	'
Accrued Postretirement Cost at January 1	-43,574,000	-39,794,000	'
Expense	-3,706,000	-5,736,000	-4,618,000
Employer Contributions	2,012,000	1,956,000	'
Accrued Postretirement Cost at December 31	($45,268,000)	($43,574,000)	($39,794,000)

Pension_Plan_and_Other_Postret8

Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Benefit Obligations (Details 5)	Dec. 31, 2013	Dec. 31, 2012
Pension Plan	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount Rate	5.30%	4.50%
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	5.30%	4.50%
Rate of Increase in Future Compensation Level	3.18%	3.19%
Other Postretirement Benefits	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount Rate	5.10%	4.25%

Pension_Plan_and_Other_Postret9

Pension Plan and Other Postretirement Benefits - Measurement Dates (Details 6)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plan	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Net Periodic Pension Cost	1-Jan-13	1-Jan-12
Market Value of Assets	31-Dec-13	31-Dec-12
Pension Plan \| Minimum	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
End of Year Benefit Obligations	1-Jan-13	1-Jan-12
Pension Plan \| Maximum	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
End of Year Benefit Obligations	31-Dec-13	31-Dec-12
Other Postretirement Benefits	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Net Periodic Pension Cost	1-Jan-13	1-Jan-12
Other Postretirement Benefits \| Minimum	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
End of Year Benefit Obligations	1-Jan-13	1-Jan-12
Other Postretirement Benefits \| Maximum	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
End of Year Benefit Obligations	31-Dec-13	31-Dec-12

Recovered_Sheet17

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, 2013
Pension Plan	'
Decrease in Regulatory Assets:	'
Amortization of Unrecognized Prior Service Cost	$257
Amortization of Unrecognized Actuarial Loss	3,477
Decrease in Accumulated Other Comprehensive Loss:	'
Amortization of Unrecognized Prior Service Cost	7
Amortization of Unrecognized Actuarial Loss	93
Total Estimated Amortization	3,834
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'
Decrease in Regulatory Assets:	'
Amortization of Unrecognized Prior Service Cost	22
Amortization of Unrecognized Actuarial Loss	142
Decrease in Accumulated Other Comprehensive Loss:	'
Amortization of Unrecognized Prior Service Cost	51
Amortization of Unrecognized Actuarial Loss	46
Total Estimated Amortization	261
Other Postretirement Benefits	'
Decrease in Regulatory Assets:	'
Amortization of Unrecognized Prior Service Cost	205
Decrease in Accumulated Other Comprehensive Loss:	'
Amortization of Unrecognized Prior Service Cost	5
Total Estimated Amortization	$210

Recovered_Sheet18

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, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Pension Plan	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	$11,304
2015	11,772
2016	12,363
2017	13,014
2018	13,801
Years 2019-2023	80,569
Executive Survivor and Supplemental Retirement Plan (ESSRP)	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	1,178
2015	1,392
2016	1,381
2017	1,359
2018	1,402
Years 2019-2023	8,939
Other Postretirement Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	2,653
2015	2,785
2016	2,899
2017	3,061
2018	3,206
Years 2019-2023	$17,207

Recovered_Sheet19

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, 2013
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_Sheet20

Pension Plan and Other Postretirement Benefits - Pension Plan Asset Allocations by Asset Category (Details 10) (Pension Plan)	Dec. 31, 2013	Dec. 31, 2012
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	56.40%	54.40%
Large Capitalization Equity Securities	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	21.00%	24.70%
International Equity Securities	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	21.70%	17.80%
Small and Mid-Capitalization Equity Securities	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	8.50%	7.10%
SEI Dynamic Asset Allocation Fund	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	5.20%	4.80%
Fixed-Income Securities and Cash	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	39.30%	41.10%
Other - SEI Special Situation Collective Investment Trust	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Defined Benefit Plan, Actual Plan Asset Allocations	4.30%	4.50%

Recovered_Sheet21

Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value (Details 11) (Pension Plan, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	$213,617	$191,018	$168,603
Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	204,447	182,452	'
Level 1 \| Large Capitalization Equity Securities Mutual Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	44,882	47,083	'
Level 1 \| International Equity Securities Mutual Funds	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	46,412	34,088	'
Level 1 \| Small and Mid-Capitalization Equity Securities Mutual Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	18,151	13,613	'
Level 1 \| SEI Dynamic Asset Allocation Mutual Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	11,159	9,177	'
Level 1 \| Fixed Income Securities Mutual Funds	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	83,843	78,480	'
Level 1 \| Cash Management - Money Market Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	'	'	'
Level 1 \| Cash Management - Working Capital Account	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	'	11	'
Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	9,170	'	'
Level 2 \| SEI Special Situation Collective Investment Trust Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	9,170	'	'
Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	'	8,566	'
Level 3 \| SEI Special Situation Collective Investment Trust Fund	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Total Assets	'	$8,566	'

Recovered_Sheet22

Pension Plan and Other Postretirement Benefits - Healthcare Cost-Trend Rates (Details 12) (Other Postretirement Benefits)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
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	6.47%	6.62%
Post-65	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Healthcare Cost-Trend Rate Assumed for Next Year	6.82%	7.01%

Recovered_Sheet23

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, 2013
Other Postretirement Benefits	'
Defined Benefit Plan Disclosure [Line Items]	'
Effect of 1 point increase on the Postretirement Benefit Obligation	$5,306
Effect of 1 point increase on Total of Service and Interest Cost	634
Effect of 1 point increase on Expense	1,266
Effect of 1 point decrease on the Postretirement Benefit Obligation	-4,449
Effect of 1 point decrease on Total of Service and Interest Cost	-500
Effect of 1 point decrease on Expense	($525)

Recovered_Sheet24

Pension Plan and Other Postretirement Benefits (Detail Textuals) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended				1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 1993	Dec. 31, 2013	Dec. 31, 2012
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Subsequent Event	Pension Plan	Pension Plan	Executive Survivor and Supplemental Retirement Plan (ESSRP)	Executive Survivor and Supplemental Retirement Plan (ESSRP)	Other Postretirement Benefits	Other Postretirement Benefits	Other Postretirement Benefits
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 2014 net periodic pension cost	'	'	'	'	7.75%	'	'	'	'	'	'
Market-related valuation gains or losses recognition period	'5 years	'	'	'	'	'	'	'	'	'	'
Plan contribution	'	'	'	$20,000,000	$10,000,000	$10,000,000	$1,137,000	$1,259,000	'	$2,012,000	$1,956,000
Period of benefit payments to the beneficiaries on their deaths	'	'	'	'	'	'	'15 years	'	'	'	'
Health insurance benefits, requisite age	'	'	'	'	'	'	'	'	'	'55 years	'
Health insurance benefits, requisite service period	'	'	'	'	'	'	'	'	'	'10 years	'
Benefit obligation liability recognized	'	'	'	'	'	'	'	'	14,964,000	'	'
Benefits earned, period	'	'	'	'	'	'	'	'	'20 years	'	'
Estimated future employer contributions in the next fiscal year	'	'	'	'	'	'	'	'	'	2,700,000	'
Medicare part D subsidy expected to received in 2014	'	'	'	'	'	'	'	'	'	448,000	'
Contributions made to 401K plan by the companies	3,042,000	2,547,000	2,598,000	'	'	'	'	'	'	'	'
Contributions made by the company to employee stock ownership plan	$705,000	$735,000	$760,000	'	'	'	'	'	'	'	'

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Carrying Amount	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Cash and Cash Equivalents	$1,150	$52,362
Short-Term Debt	-51,195	'
Long-Term Debt including Current Maturities	-389,777	-421,856
Fair Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Cash and Cash Equivalents	1,150	52,362
Short-Term Debt	-51,195	'
Long-Term Debt including Current Maturities	($427,796)	($491,244)

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Detail Textuals ) (OTP Credit Agreement)	12 Months Ended
	Dec. 31, 2013
OTP Credit Agreement	'
Fair Value Of Financial Instruments [Line Items]	'
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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	$1,843,217	$1,687,287
Less Accumulated Depreciation and Amortization	676,201	637,835
Net Plant	1,167,016	1,049,452
Electric Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	1,645,664	1,499,061
Less Accumulated Depreciation and Amortization	554,818	526,467
Net Plant	1,090,846	972,594
Electric Plant \| Production Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	679,067	672,120
Electric Plant \| Transmission Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	270,606	261,447
Electric Plant \| Distribution Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	421,803	405,461
Electric Plant \| General Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	89,408	84,275
Electric Plant \| Electric Plant In Service	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	1,460,884	1,423,303
Electric Plant \| Construction In Progress	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	184,780	75,758
Nonelectric Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	197,553	188,226
Less Accumulated Depreciation and Amortization	121,383	111,368
Net Plant	76,170	76,858
Nonelectric Plant \| Equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	153,098	144,901
Nonelectric Plant \| Buildings And Leasehold Improvements	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	38,074	37,209
Nonelectric Plant \| Land	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	3,700	3,984
Nonelectric Plant \| Construction In Progress	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	2,681	2,132
Nonelectric Plant \| Nonelectric Operations Plant	'	'
Property, Plant and Equipment [Line Items]	'	'
Total Gross Plant	$194,872	$186,094

Property_Plant_and_Equipment_E

Property, Plant and Equipment - Estimated Service Lives for Properties (Details 1)	12 Months Ended
	Dec. 31, 2013
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
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
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
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

Property_Plant_and_Equipment_D1

Property, Plant and Equipment (Detail Textuals)	12 Months Ended
Property, Plant and Equipment (Detail Textuals)	Dec. 31, 2013
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Tax Computed at Federal Statutory Rate	$22,301	$14,385	$13,661
Increases (Decreases) in Tax from:	'	'	'
Federal Production Tax Credit	-6,612	-6,695	-7,281
State Income Taxes Net of Federal Income Tax Expense (Benefit)	1,667	-849	798
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	-863	-891	-996
Corporate Owned Life Insurance	-856	-585	-388
Allowance for Funds Used During Construction - Equity	-638	-409	-301
Dividend Received/Paid Deduction	-632	-656	-677
Investment Tax Credit Amortization	-597	-720	-855
Tax Depreciation - Treasury Grant for Wind Farms	-304	-304	-507
Differences Reversing in Excess of Federal Rates	-100	-143	680
Impact of Medicare Part D Change	'	-584	-599
Permanent and Other Differences	177	-416	586
Total Income Tax Expense - Continuing Operations	13,543	2,133	4,121
Income Tax Expense (Benefit) - Discontinued Operations - U.S.	15	-14,667	-13,325
Income Tax (Benefit) - Discontinued Operations - Foreign	'	'	-79
Income Tax Expense (Benefit) - Continuing and Discontinued Operations	13,558	-12,534	-9,283
Overall Effective Federal, State and Foreign Income Tax Rate	21.00%	70.40%	41.20%
Income Tax Expense From Continuing Operations Includes the Following:	'	'	'
Current Federal Income Taxes	146	-7,198	-4,303
Current State Income Taxes	37	-1,402	-754
Deferred Federal Income Taxes	18,310	15,878	14,308
Deferred State Income Taxes	3,122	3,161	4,002
Federal Production Tax Credit	-6,612	-6,695	-7,281
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	-863	-891	-996
Investment Tax Credit Amortization	-597	-720	-855
Total	13,543	2,133	4,121
Income (Loss) Before Income Taxes - U.S.	63,924	-13,426	-7,547
Income (Loss) Before Income Taxes - Foreign (Discontinued Operations)	499	-4,381	-14,979
Total Income (Loss) Before Income Taxes - Continuing and Discontinued Operations	$64,423	($17,807)	($22,526)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred Tax Assets	'	'
North Dakota Wind Tax Credits	$42,241	$44,172
Retirement Benefits Liabilities	39,524	34,618
Benefit Liabilities	39,290	35,459
Federal Production Tax Credits	33,620	27,048
Cost of Removal	27,926	25,869
Net Operating Loss Carryforward	15,360	27,682
Differences Related to Property	9,462	12,983
Vacation Accrual	1,985	2,017
Investment Tax Credits	1,960	2,554
Other	4,045	10,853
Total Deferred Tax Assets	215,413	223,255
Deferred Tax Liabilities	'	'
Differences Related to Property	-306,232	-301,991
Retirement Benefits Regulatory Asset	-39,524	-34,618
North Dakota Wind Tax Credits	-11,543	-11,923
Excess Tax over Book Pension	-6,977	-6,995
Impact of State Net Operating Losses on Federal Taxes	-3,088	-3,484
Regulatory Asset	-1,805	-1,691
Renewable Resource Rider Accrued Revenue	-329	-934
Other	-6,066	-2,442
Total Deferred Tax Liabilities	-375,564	-364,078
Deferred Income Taxes	($160,151)	($140,823)

Income_Taxes_Expiration_of_Tax

Income Taxes - Expiration of Tax Net Operating Losses and Tax Credits Available (Details 2) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Federal Net Operating Losses	'
Income Taxes [Line Items]	'
Net Operating Losses, Amount	$6,350
Net Operating Losses, Year of Expiration 2014	'
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	6,350
Tax Credits, Amount	35,350
Tax Credits, Year of Expiration 2014	'
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	35,350
State Net Operating Losses	'
Income Taxes [Line Items]	'
Net Operating Losses, Amount	8,823
Net Operating Losses, Year of Expiration 2014	'
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	8,823
Tax Credits, Amount	40,750
Tax Credits, Year of Expiration 2014	2,339
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	$33,344

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Balance on January 1	$4,436	$12,138	$900
Increases Related to Tax Positions for Prior Years	98	'	11,238
Decreases Related to Tax Positions for Prior Years	-295	-6,802	'
Uncertain Positions Resolved During Year	'	-900	'
Balance on December 31	$4,239	$4,436	$12,138

Income_Taxes_Detail_Textuals

Income Taxes (Detail Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$10.30	'	'
Period for unrecognized tax benefits not expected change	'12 months	'	'

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, 2013	Dec. 31, 2012
Asset Retirement Obligations	'	'
Beginning Balance	$5,207	$4,808
New Obligations Recognized	'	'
Adjustments Due to Revisions in Cash Flow Estimates	'	-20
Accrued Accretion	454	419
Settlements	'	'
Ending Balance	5,661	5,207
Asset Retirement Costs Capitalized	'	'
Beginning Balance	1,477	1,497
New Obligations Recognized	'	'
Adjustments Due to Revisions in Cash Flow Estimates	'	-20
Settlements	'	'
Ending Balance	1,477	1,477
Accumulated Depreciation - Asset Retirement Costs Capitalized	'	'
Beginning Balance	407	351
New Obligations Recognized	'	'
Adjustments Due to Revisions in Cash Flow Estimates	'	'
Depreciation Expense	55	56
Settlements	'	'
Ending Balance	462	407
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, 2013
	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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	$2,016	$233,059	$403,335
Operating Expenses	2,005	233,528	419,221
Asset Impairment Charge	'	53,320	59,977
Operating (Loss) Income	'	-53,789	-75,863
Other (Deductions) Income	479	272	23
Interest Expense	'	175	242
Income Tax (Benefit) Expense	9	-14,982	-19,255
Net Gain (Loss)	481	-38,710	-56,827
(Loss) Gain on Disposition Before Taxes	216	-5,216	14,525
Income Tax Expense (Benefit) on Disposition	6	315	5,851
Net Gain (Loss) on Disposition	210	-5,531	8,674
Net Gain (Loss) from Discontinued Operations	691	-44,241	-48,153
IMD	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	'	186,151	201,921
Operating Expenses	-988	184,462	218,542
Asset Impairment Charge	'	45,573	3,142
Operating (Loss) Income	'	-43,884	-19,763
Other (Deductions) Income	412	135	-46
Interest Expense	'	5,787	6,852
Income Tax (Benefit) Expense	370	-15,792	-4,768
Net Gain (Loss)	1,030	-33,744	-21,893
(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	-21,893
Wylie	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	'	'	49,884
Operating Expenses	640	179	55,927
Asset Impairment Charge	'	'	'
Operating (Loss) Income	'	-179	-6,043
Other (Deductions) Income	'	'	18
Interest Expense	'	'	709
Income Tax (Benefit) Expense	-256	13	-2,683
Net Gain (Loss)	-384	-192	-4,051
(Loss) Gain on Disposition Before Taxes	'	-62	-946
Income Tax Expense (Benefit) on Disposition	'	460	2,854
Net Gain (Loss) on Disposition	'	-522	-3,800
Net Gain (Loss) from Discontinued Operations	-384	-714	-7,851
Shrco	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	2,016	32,563	39,863
Operating Expenses	2,622	36,163	41,478
Asset Impairment Charge	'	7,747	456
Operating (Loss) Income	67	-11,347	-2,071
Other (Deductions) Income	'	15	1
Interest Expense	'	1,553	1,580
Income Tax (Benefit) Expense	-213	-4,021	-1,462
Net Gain (Loss)	-326	-8,864	-2,188
(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	-2,188
DMS	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	'	16,362	89,558
Operating Expenses	-269	14,741	85,244
Asset Impairment Charge	'	'	56,379
Operating (Loss) Income	'	1,621	-52,065
Other (Deductions) Income	'	122	281
Interest Expense	'	279	1,726
Income Tax (Benefit) Expense	108	1,734	-16,058
Net Gain (Loss)	161	-270	-37,452
(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	-37,452
IPH	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	'	'	28,125
Operating Expenses	'	'	24,046
Asset Impairment Charge	'	'	'
Operating (Loss) Income	'	'	4,079
Other (Deductions) Income	'	'	-228
Interest Expense	'	'	11
Income Tax (Benefit) Expense	'	106	1,462
Net Gain (Loss)	'	-106	2,378
(Loss) Gain on Disposition Before Taxes	'	'	15,471
Income Tax Expense (Benefit) on Disposition	'	'	2,997
Net Gain (Loss) on Disposition	'	'	12,474
Net Gain (Loss) from Discontinued Operations	'	-106	14,852
Intercompany Transactions Adjustment	'	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'
Operating Revenues	'	-2,017	-6,016
Operating Expenses	'	-2,017	-6,016
Asset Impairment Charge	'	'	'
Operating (Loss) Income	'	'	'
Other (Deductions) Income	'	'	-3
Interest Expense	'	-7,444	-10,636
Income Tax (Benefit) Expense	'	2,978	4,254
Net Gain (Loss)	'	4,466	6,379
(Loss) Gain on Disposition Before Taxes	'	'	'
Income Tax Expense (Benefit) on Disposition	'	'	'
Net Gain (Loss) on Disposition	'	'	'
Net Gain (Loss) from Discontinued Operations	'	$4,466	$6,379

Discontinued_Operations_Major_

Discontinued Operations - Major Components of Assets and Liabilities of Discontinued Operations (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Current Assets	$38	$18,487
Investments	'	85
Net Plant	'	520
Assets of Discontinued Operations	38	19,092
Current Liabilities	3,637	11,156
Liabilities of Discontinued Operations	3,637	11,156
IMD	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Current Assets	'	1,367
Investments	'	'
Net Plant	'	'
Assets of Discontinued Operations	'	1,367
Current Liabilities	2,196	4,587
Liabilities of Discontinued Operations	2,196	4,587
Shrco	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Current Assets	38	17,120
Investments	'	85
Net Plant	'	520
Assets of Discontinued Operations	38	17,725
Current Liabilities	1,441	6,569
Liabilities of Discontinued Operations	$1,441	$6,569

Discontinued_Operations_Warran

Discontinued Operations - Warranty Reserves (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations and Disposal Groups [Abstract]	'	'
Warranty Reserve Balance, Beginning of Year	$5,027	$3,170
Provision for Warranties Issued During the Year	188	3,240
Less Settlements Made During the Year	-715	-1,342
Decrease in Warranty Estimates for Prior Years	-1,413	-41
Warranty Reserve Balance, End of Year	$3,087	$5,027

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

Dec. 31, 2011

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

Disposal groups held for sale or disposed of by sale

Shrco

IMD

IPH

Wylie

Aviva

DMS

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

Proceeds from sale of discontinued operations

$12,842,000

$42,229,000

$107,310,000

$13,000,000

$18,100,000

$86,000,000

$25,000,000

$300,000

$24,000,000

Amount of working capital true up received

2,400,000

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

SCHEDULE_1_Condensed_Balance_S

SCHEDULE 1 Condensed Balance Sheets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current Assets	'	'	'	'
Cash and Cash Equivalents	$1,150	$52,362	$15,994	'
Deferred Income Taxes	35,452	30,964	'	'
Other	7,747	8,161	'	'
Total Current Assets	250,590	323,632	'	'
Investments in Subsidiaries	9,362	9,471	'	'
Other Assets	28,834	26,222	'	'
Total Assets	1,596,019	1,602,337	1,700,522	'
Current Liabilities	'	'	'	'
Other	6,532	6,334	'	'
Total Current Liabilities	232,892	173,128	'	'
Other Noncurrent Liabilities	25,209	22,244	'	'
Commitments and Contingencies	'	'	'	'
Capitalization	'	'	'	'
Long-Term Debt, Net of Current Maturities	389,589	421,680	'	'
Common Shareholder Equity	181,358	180,842	'	'
Total Capitalization	924,419	959,154	'	'
Total Liabilities and Equity	1,596,019	1,602,337	'	'
Cumulative Preferred Shares	'	'	'	'
Capitalization	'	'	'	'
Cumulative Preferred Shares	'	15,500	'	'
OTTER TAIL CORPORATION (PARENT COMPANY)	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	7,907	44,802	7,062	'
Accounts Receivable from Subsidiaries	1,736	3,587	'	'
Interest Receivable from Subsidiaries	192	317	'	'
Notes Receivable from Subsidiaries	5,703	17,157	'	'
Deferred Income Taxes	28,853	14,790	'	'
Other	947	1,594	'	'
Total Current Assets	45,338	82,247	'	'
Investments in Subsidiaries	541,291	716,453	'	'
Notes Receivable from Subsidiaries	52,249	67,925	'	'
Deferred Income Taxes	25,861	18,042	'	'
Other Assets	25,456	24,584	'	'
Total Assets	690,195	909,251	'	'
Current Liabilities	'	'	'	'
Accounts Payable to Subsidiaries	5,961	5,035	'	'
Notes Payable to Subsidiaries	62,562	231,611	'	'
Other	5,122	6,223	'	'
Total Current Liabilities	73,645	242,869	'	'
Other Noncurrent Liabilities	28,031	27,363	'	'
Commitments and Contingencies	'	'	'	'
Capitalization	'	'	'	'
Long-Term Debt, Net of Current Maturities	53,689	101,545	'	'
Common Shareholder Equity	534,830	521,974	'	'
Total Capitalization	588,519	639,019	'	'
Total Liabilities and Equity	690,195	909,251	'	'
OTTER TAIL CORPORATION (PARENT COMPANY) \| Cumulative Preferred Shares	'	'	'	'
Capitalization	'	'	'	'
Cumulative Preferred Shares	'	$15,500	'	'

SCHEDULE_1_Condensed_Statement

SCHEDULE 1 Condensed Statements of Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Loss	'	'	'
Revenue	$893,313	$859,239	$840,169
Operating Expenses	796,462	777,212	768,272
Operating Loss	96,851	82,027	71,897
Other Income (Expense)	'	'	'
Loss on Early Retirement of Debt	-10,252	-13,106	'
Interest Charges	26,978	31,905	35,629
Other Income	4,096	4,085	2,763
Income Before Income Taxes - Continuing Operations	63,717	41,101	39,031
Income Tax Benefit	13,543	2,133	4,121
Net Income (Loss) from Continuing Operations	50,174	38,968	34,910
Net Income (Loss) from Discontinued Operations	691	-44,241	-48,153
Total Net Income (Loss)	50,865	-5,273	-13,243
Income (Loss) Available for Common Shares	50,352	-6,009	-14,301
OTTER TAIL CORPORATION (PARENT COMPANY)	'	'	'
Operating Loss	'	'	'
Revenue	'	'	'
Operating Expenses	14,150	15,197	15,798
Operating Loss	-14,150	-15,197	-15,798
Other Income (Expense)	'	'	'
Equity Income (Loss) in Earnings of Subsidiaries	66,468	8,430	-4,205
Loss on Early Retirement of Debt	-10,252	-13,106	'
Interest Charges	-9,940	-13,994	-17,157
Interest Charges to Subsidiaries	-494	-512	-290
Interest Income from Subsidiaries	5,318	15,700	18,006
Other Income	1,413	1,426	548
Total Other Income (Expense)	52,513	-2,056	-3,098
Income Before Income Taxes - Continuing Operations	38,363	-17,253	-18,896
Income Tax Benefit	-12,502	-11,980	-5,653
Net Income (Loss) from Continuing Operations	50,865	-5,273	-13,243
Net Income (Loss) from Discontinued Operations	'	'	'
Total Net Income (Loss)	50,865	-5,273	-13,243
Preferred Dividend Requirement and Other Adjustments	513	736	1,058
Income (Loss) Available for Common Shares	$50,352	($6,009)	($14,301)

SCHEDULE_1_Condensed_Statement1

SCHEDULE 1 Condensed Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities	'	'	'
Net Cash Provided by Operating Activities	$147,781	$233,547	$104,383
Cash Flows from Investing Activities	'	'	'
Net Cash Provided by Investing Activities	-149,197	-83,577	5,423
Cash Flows from Financing Activities	'	'	'
Change in Checks Written in Excess of Cash	'	'	-7,268
Net Short-Term (Repayments) Borrowings	51,195	'	-79,490
Proceeds from Issuance of Common Stock	1,821	'	'
Common Stock Issuance Expenses	3	370	'
Payments for Retirement of Capital Stock	15,723	111	1,182
Proceeds from Issuance of Long-Term Debt	40,900	'	142,006
Short-Term and Long-Term Debt Issuance Expenses	522	897	1,666
Payments for Retirement of Long-Term Debt	72,981	50,224	100,796
Premium Paid for Early Retirement of Long-Term Debt	9,889	12,500	'
Dividends Paid and Other Distributions	43,818	43,976	43,923
Net Cash Used in Financing Activities	-49,020	-112,356	-95,503
Net Change in Cash and Cash Equivalents	-51,212	36,368	15,994
Cash and Cash Equivalents at Beginning of Period	52,362	15,994	'
Cash and Cash Equivalents at End of Period	1,150	52,362	15,994
OTTER TAIL CORPORATION (PARENT COMPANY)	'	'	'
Cash Flows from Operating Activities	'	'	'
Net Cash Provided by Operating Activities	70,376	43,904	30,833
Cash Flows from Investing Activities	'	'	'
Return of Capital (Investment in Subsidiaries)	150,381	-137,726	-24,534
Debt (Issued to) Repaid by Subsidiaries	-141,919	239,452	98,521
Cash Used in Investing Activities	-37	-69	-99
Net Cash Provided by Investing Activities	8,425	101,657	73,888
Cash Flows from Financing Activities	'	'	'
Change in Checks Written in Excess of Cash	'	'	-253
Net Short-Term (Repayments) Borrowings	'	'	-54,176
Proceeds from Issuance of Common Stock	1,821	'	'
Common Stock Issuance Expenses	-3	-370	'
Payments for Retirement of Capital Stock	-15,723	-111	-1,182
Proceeds from Issuance of Long-Term Debt	'	'	2,006
Short-Term and Long-Term Debt Issuance Expenses	-238	-700	-14
Payments for Retirement of Long-Term Debt	-47,846	-50,164	-117
Premium Paid for Early Retirement of Long-Term Debt	-9,889	-12,500	'
Dividends Paid and Other Distributions	-43,818	-43,976	-43,923
Net Cash Used in Financing Activities	-115,696	-107,821	-97,659
Net Change in Cash and Cash Equivalents	-36,895	37,740	7,062
Cash and Cash Equivalents at Beginning of Period	44,802	7,062	'
Cash and Cash Equivalents at End of Period	$7,907	$44,802	$7,062

SCHEDULE_1_Related_Party_Trans

SCHEDULE 1 Related Party Transactions (Details) (OTTER TAIL CORPORATION (PARENT COMPANY), USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	$1,736	$3,587
Interest Receivable	192	317
Current Notes Receivable	5,703	17,157
Long-Term Notes Receivable	52,249	67,925
Accounts Payable	5,961	5,035
Current Notes Payable	62,562	231,611
Otter Tail Power Company	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	1,346	1,201
Interest Receivable	'	'
Current Notes Receivable	'	'
Long-Term Notes Receivable	'	15,500
Accounts Payable	11	160
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	17,285	8,251
Northern Pipe Products, Inc.	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	'	'
Interest Receivable	9	9
Current Notes Receivable	'	'
Long-Term Notes Receivable	3,549	3,725
Accounts Payable	'	'
Current Notes Payable	11,948	10,537
BTD Manufacturing, Inc.	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	7	41
Interest Receivable	107	107
Current Notes Receivable	'	'
Long-Term Notes Receivable	28,500	28,500
Accounts Payable	'	'
Current Notes Payable	3,985	1,773
IMD, Inc.	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	'	20
Interest Receivable	'	113
Current Notes Receivable	1,266	1,461
Long-Term Notes Receivable	'	'
Accounts Payable	'	'
Current Notes Payable	'	'
Shrco, Inc.	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	2	40
Interest Receivable	'	12
Current Notes Receivable	3,889	15,696
Long-Term Notes Receivable	'	'
Accounts Payable	'	'
Current Notes Payable	'	'
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	4,705	2,986
Aevenia, Inc	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	'	50
Interest Receivable	7	7
Current Notes Receivable	548	'
Long-Term Notes Receivable	1,800	1,800
Accounts Payable	1	'
Current Notes Payable	'	1,480
Foley Company	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	44	40
Interest Receivable	9	9
Current Notes Receivable	'	'
Long-Term Notes Receivable	2,500	2,500
Accounts Payable	'	'
Current Notes Payable	5,343	1,189
Varistar Corporation	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	'	2,050
Interest Receivable	'	'
Current Notes Receivable	'	'
Long-Term Notes Receivable	'	'
Accounts Payable	5,948	4,875
Current Notes Payable	19,296	205,329
Otter Tail Energy Services Company	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	'	'
Interest Receivable	'	'
Current Notes Receivable	'	'
Long-Term Notes Receivable	'	'
Accounts Payable	'	'
Current Notes Payable	'	66
Otter Tail Assurance Limited	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Accounts Receivable	337	143
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'	'	'
Cash Dividends Paid to Parent by Subsidiaries	$91,693	$43,018	$43,320